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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

|
|
|

Form 10-K

|  |                                                    
|- | ---------------------------------------------------
|x | ANNUAL REPORT
  PURSUANT TO SECTION 13 OR 15(d)    
|  | OF THE SECURITIES
  EXCHANGE ACT OF 1934           
|  |                                                    
|  | For the fiscal year
  ended December 31, 2007      
|  |                                                    
|  | Or                                                 
|  |                                                    
|o | 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 | (I.R.S. Employer   
|incorporation or organization)  | Identification No.)

500 Dallas,
Suite 1000, Houston, Texas 77002(Address of principal executive
offices)(zip code)

Registrants
telephone number, including area code: 713-369-9000

|
|
|

Securities
registered pursuant to Section 12(b) of the Act:

|                    |  |                                            
|------------------- |  | -------------------------------------------
|Title of each class |  | Name of each exchange on which
  registered
|                    |  |                                            
|Common Units        |  | New York Stock Exchange                    

Securities
registered Pursuant to Section 12(g) of the Act:
None

Indicate by
check mark if the registrant is a well-known seasoned issuer, as defined in
Rule 405 of the Securities Act of 1933. Yesx  No o

Indicate by
check mark if the registrant is not required to file reports pursuant to
Section 13 or Section 15(d) of the Securities Exchange Act of 1934. Yes o  No x

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 o

Indicate by
check mark if disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K is not contained herein, and will not be contained, to the best
of registrants knowledge, in definitive proxy or information statements incorporated
by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

Indicate by
check mark whether the registrant is a large accelerated filer, an accelerated
filer, a non-accelerated filer, or a smaller reporting company (as defined in
Rule 12b-2 of the Securities Exchange Act of 1934).


|                          |                     |                         |                            
|------------------------- | ------------------- | ----------------------- | ---------------------------
|Large accelerated filer x | Accelerated filer o | Non-accelerated filer o | Smaller reporting company o

1

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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 o  No x

Aggregate
market value of the voting and non-voting common equity held by non-affiliates
of the registrant, based on closing prices in the daily composite list for
transactions on the New York Stock Exchange on June 29, 2007 was approximately
$8,185,538,074. As of January 31, 2008, the registrant had 170,224,734 Common
Units outstanding.

2

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KINDER MORGAN
ENERGY PARTNERS, L.P.

|                  | 
|----------------- | 
|TABLE OF CONTENTS | 

|               |  |                                                                                                                   |  |              
|-------------- |  | ----------------------------------------------------------------------------------------------------------------- |  | -------------
|               |  |                                                                                                                   |  | Page
  Number
|               |  |                                                                                                                   |  |              
|               |  |                                                                                                                   |  |              
|               |  | PART I                                                                                                            |  |              
|Items 1 and 2. |  | Business and Properties                                                                                           |  | 4            
|               |  | General
  Development of Business                                                                                 |  | 4            
|               |  | Organizational
  Structure                                                                                        |  | 4            
|               |  | Recent
  Developments                                                                                             |  | 5            
|               |  | Financial
  Information about Segments                                                                            |  | 10           
|               |  | Narrative
  Description of Business                                                                               |  | 10           
|               |  | Business Strategy                                                                                                 |  | 10           
|               |  | Business Segments                                                                                                 |  | 10           
|               |  | Products
  Pipelines                                                                                              |  | 11           
|               |  | Natural Gas
  Pipelines                                                                                           |  | 16           
|               |  | CO2                                                                                                               |  | 24           
|               |  | Terminals                                                                                                         |  | 29           
|               |  | Trans Mountain                                                                                                    |  | 30           
|               |  | Major Customers                                                                                                   |  | 31           
|               |  | Regulation                                                                                                        |  | 31           
|               |  | Environmental
  Matters                                                                                           |  | 34           
|               |  | Other                                                                                                             |  | 36           
|               |  | Financial
  Information about Geographic Areas                                                                    |  | 36           
|               |  | Available
  Information                                                                                           |  | 36           
|Item 1A.       |  | Risk Factors                                                                                                      |  | 37           
|Item 1B.       |  | Unresolved Staff Comments                                                                                         |  | 46           
|Item 3.        |  | Legal Proceedings                                                                                                 |  | 46           
|Item 4.        |  | Submission of Matters to a Vote of Security
  Holders                                                             |  | 46           
|               |  |                                                                                                                   |  |              
|               |  | PART II                                                                                                           |  |              
|Item 5.        |  | Market for
  Registrants Common Equity, Related Stockholder Matters and Issuer 
  Purchases of Equity Securities |  | 47           
|Item 6.        |  | Selected Financial Data                                                                                           |  | 48           
|Item 7.        |  | Managements Discussion and Analysis of
  Financial Condition and Results of Operations                           |  | 50           
|               |  | Critical
  Accounting Policies and Estimates                                                                      |  | 51           
|               |  | Results of
  Operations                                                                                           |  | 53           
|               |  | Liquidity and
  Capital Resources                                                                                 |  | 68           
|               |  | Recent
  Accounting Pronouncements                                                                                |  | 77           
|               |  | Information
  Regarding Forward-Looking Statements                                                                |  | 77           
|Item 7A.       |  | Quantitative and Qualitative Disclosures
  About Market Risk                                                      |  | 79           
|               |  | Energy Commodity
  Market Risk                                                                                    |  | 79           
|               |  | Interest Rate
  Risk                                                                                              |  | 81           
|Item 8.        |  | Financial Statements and Supplementary Data                                                                       |  | 82           
|Item 9.        |  | Changes in and Disagreements with
  Accountants on Accounting and Financial Disclosure                            |  | 82           
|Item 9A.       |  | Controls and Procedures                                                                                           |  | 83           
|Item 9B.       |  | Other Information                                                                                                 |  | 83           
|               |  |                                                                                                                   |  |              
|               |  | PART III                                                                                                          |  |              
|Item 10.       |  | Directors, Executive Officers and Corporate
  Governance                                                          |  | 84           
|               |  | Directors and
  Executive Officers of our General Partner and its Delegate                                        |  | 84           
|               |  | Corporate Governance                                                                                              |  | 86           
|               |  | Section
16(a) Beneficial
  Ownership Reporting Compliance                                                         |  | 87           
|Item 11.       |  | Executive Compensation                                                                                            |  | 88           
|Item 12.       |  | Security Ownership of Certain Beneficial
  Owners and Management and Related 
  Stockholder Matters               |  | 103          
|Item 13.       |  | Certain Relationships and Related
  Transactions, and Director Independence                                       |  | 105          
|Item 14.       |  | Principal Accounting Fees and Services                                                                            |  | 109          
|               |  |                                                                                                                   |  |              
|               |  | PART IV                                                                                                           |  |              
|Item 15.       |  | Exhibits and Financial Statement Schedules                                                                        |  | 110          
|               |  | Index to Financial Statements                                                                                     |  | 114          
|Signatures     |  |                                                                                                                   |  | 211          

3

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PART
I

Items
1 and 2. Business and Properties.

In
this report, unless the context requires otherwise, references to we, us,
our, KMP or the Partnership are intended to mean Kinder Morgan Energy
Partners, L.P., a Delaware limited partnership formed in August 1992, our
operating limited partnerships and their subsidiaries. Our common units, which
represent limited partner interests in us, trade on the New York Stock Exchange
under the symbol KMP. The address of our principal executive offices is 500
Dallas, Suite 1000, Houston, Texas 77002, and our telephone number at this
address is (713) 369-9000. You should read the following discussion and
analysis in conjunction with our consolidated financial statements included
elsewhere in this report.  All dollars in this report are United States dollars,
except where stated otherwise. Canadian dollars are designated as C$.

(a) General Development of Business

Organizational
Structure

Kinder
Morgan Energy Partners, L.P. is a leading pipeline transportation and energy
storage company in North America. We own an interest in or operate more than
25,000 miles of pipelines and approximately 165 terminals. Our pipelines
transport natural gas, gasoline, 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, commonly called
CO2, for enhanced
oil recovery projects in North America. As one of the largest
publicly traded pipeline limited partnerships in America, we have an enterprise
value of approximately $20 billion.

Our
general partner is Kinder Morgan G.P., Inc., a Delaware corporation. On July
27, 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.

Knight
Inc., a Kansas corporation and a private company formerly known as Kinder
Morgan, Inc., indirectly is the sole owner of the common stock of our general
partner. On August 28, 2006, Kinder Morgan, Inc., a Kansas corporation referred
to as KMI in this report, entered into an agreement and plan of merger
whereby generally each share of KMI common stock would be converted into the
right to receive $107.50 in cash without interest.  KMI in turn would merge with
a wholly owned subsidiary of Knight Holdco LLC, a privately owned company in
which Richard D. Kinder, Chairman and Chief Executive Officer of KMI, would be a
major investor.  On May 30, 2007, the merger closed, with KMI continuing as the
surviving legal entity and subsequently renamed Knight Inc., referred to as
Knight in this report.  Additional investors in Knight Holdco LLC include the
following: other senior members of Knight management, most of whom are also
senior officers of Kinder Morgan G.P., Inc. (our general partner) and of Kinder
Morgan Management, LLC (our general partners delegate); KMI co-founder William V.
Morgan; KMI board members Fayez Sarofim and Michael C. Morgan; and affiliates
of (i) Goldman Sachs Capital Partners; (ii) American International Group, Inc.;
(iii) The Carlyle Group; and (iv) Riverstone Holdings LLC. This transaction is
referred to in this report as the going-private transaction.

As
of December 31, 2007, Knight and its consolidated subsidiaries owned, through
its general and limited partner interests, an approximately 13.9% interest in
us. In addition to the distributions it receives from its limited and general
partner interests, Knight also receives an incentive distribution from us as a
result of its ownership of our general partner. This incentive distribution is
calculated in increments based on the amount by which quarterly distributions
to our unitholders exceed specified target levels as set forth in our
partnership agreement, reaching a maximum of 50% of distributions allocated to
the general partner for distributions above $0.23375 per limited partner unit
per quarter. Including both its general and limited partner interests in us, at
the 2007 distribution level, Knight received approximately 49% of all quarterly
Available Cash distributions (as defined in our partnership agreement) from
us, with approximately 43% and 6% of all quarterly distributions from us
attributable to Knights general partner and limited partner interests,
respectively. The actual level of distributions Knight will receive in the
future will vary with the level of distributions to our limited partners
determined in accordance with our partnership agreement.

4

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Kinder
Morgan Management, LLC, referred to as KMR in this report, is a Delaware
limited liability company formed in February 2001. Our general partner owns all
of KMRs voting securities and, pursuant to a delegation of control agreement,
our general partner 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. Under
the delegation of control agreement, KMR, as the delegate of our general
partner, manages and controls our business and affairs and the business and
affairs of our operating limited partnerships and their subsidiaries. Furthermore,
in accordance with its limited liability company agreement, KMRs activities
are limited to being a limited partner in, and managing and controlling the
business and affairs of us, our operating limited partnerships and their
subsidiaries.

KMRs
shares represent limited liability company interests and trade on the New York
Stock Exchange under the symbol KMR. Since its inception, KMR has used
substantially all of the net proceeds received from the public offerings of its
shares to purchase i-units from us. The i-units are a separate class of limited
partner interests in us and are issued only to KMR. Under the terms of our
partnership agreement, the holders of our i-units are entitled to vote on all
matters on which the holders of our common units are entitled to vote.

In
general, our limited partner units, consisting of i-units, common units and
Class B units (the Class B units are similar to our common units except that
they are not eligible for trading on the New York Stock Exchange), will vote
together as a single class, with each i-unit, common unit and Class B unit
having one vote. We pay our quarterly distributions from operations and interim
capital transactions to our common and Class B unitholders in cash, and we pay our
quarterly distributions to KMR in additional i-units rather than in cash. As of
December 31, 2007, KMR, through its ownership of our i-units, owned
approximately 29.2% of all of our outstanding limited partner units.

Recent Developments

The
following is a brief listing of significant developments since December 31,
2006. Additional information regarding most of these items may be found
elsewhere in this report.

| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | Effective
 January 1, 2007, we acquired the remaining approximate 50.2% interest in the
 Cochin pipeline system that we did not already own from affiliates of BP for
 an aggregate consideration of approximately $47.8 million, consisting of $5.5
 million in cash and a note payable having a fair value of $42.3 million. As part
 of the transaction, the seller also agreed to reimburse us for certain
 pipeline integrity management costs over a five-year period in an aggregate
 amount not to exceed $50 million. Upon closing, we became the operator of the
 pipeline;            
| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  
| |  | On January 17, 2007, we
announced that our CO2business segment will invest approximately $120
million to further expand its operations and enable it to meet the increased
demand for carbon dioxide in the Permian Basin. The expansion activities will
take place in southwest Colorado and include developing a new carbon dioxide
source field (named the Doe Canyon Deep Unit that went in service during the
first quarter of 2008) and adding infrastructure at both the McElmo Dome Unit
and the Cortez Pipeline. The entire expansion is expected to be completed by the
middle of 2008;
| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  
| |  | On January
 30, 2007, we completed a public offering of senior notes. We issued a total
 of $1.0 billion in principal amount of senior notes, consisting of $600
 million of 6.00% notes due February 1, 2017, and $400 million of 6.50% notes
 due February 1, 2037. We received proceeds from the issuance of the notes,
 after underwriting discounts and commissions, of $992.8 million, and we used
 the proceeds to reduce the borrowings under our commercial paper program;                                                                                                              
| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  
| |  | On February
 14, 2007, the first phase of the Rockies Express pipeline system, the
 327-mile REX-Entrega Project, was placed in service at a cost of
 approximately $745 million and provided up to 500 million cubic feet of
 natural gas capacity from the Meeker Hub in Rio Blanco County, Colorado and
 Wamsutter Hub in Sweetwater County, Wyoming to the Cheyenne Hub in Weld
 County, Colorado.                                                                                                                                                                                           
| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  
| |   | The Rockies
 Express pipeline project is an approximate $4.9 billion, 1,679-mile natural
 gas pipeline system which is owned and currently being developed by Rockies
 Express Pipeline LLC. The Rockies Express                                                                                                                                                                                                                                                                                                                                                                                 



5

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| |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  
| |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | pipeline
 project is to be completed in three phases: (i) a 327-mile, $745 million
 pipeline running from the Meeker Hub to the Cheyenne Hub with a nominal
 capacity of 500 million cubic feet per day; (ii) a 713-mile, $1.6 billion
 pipeline from the Cheyenne Hub to an interconnect in Audrain County,
 Missouri, transporting up to 1.5 billion cubic feet per day; and (iii) a
 639-mile, $2.6 billion pipeline from Audrain County, Missouri to Clarington,
 located in Monroe County, Ohio. When fully completed, the Rockies Express
 pipeline system will have the capability to transport 1.8 billion cubic feet
 per day of natural gas, and binding firm commitments have been secured for
 all of the pipeline capacity. On January 12, 2008, interim service on the
 REX-West Project (second phase) commenced. Full service on the REX-West
 system for 1.5 billion cubic feet per day of contracted capacity is expected
 to commence in mid-March 2008. See (c) Narrative Description of
 BusinessBusiness SegmentsNatural Gas PipelinesRockies Express Pipeline
 for more information;

| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | On February
 28, 2007, we announced plans to invest up to $100 million to expand our
 liquids terminal facilities in order to help serve the growing biodiesel
 market. We entered into long-term agreements as lessors with Green Earth
 Fuels, LLC to build tankage that will handle biodiesel at our Houston Ship
 Channel liquids facility. Green Earth Fuels completed construction of an 86
 million gallon biodiesel production facility at our Galena Park, Texas
 liquids terminal in the fourth quarter of 2007;                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            
| |  | On April 30,
 2007, we acquired the Trans Mountain pipeline system from Knight for $549.1
 million. The Trans Mountain pipeline system, which transports crude oil and
 refined products from Edmonton, Alberta, Canada to marketing terminals and
 refineries in British Columbia and the state of Washington, currently
 transports approximately 260,000 barrels per day. An additional expansion
 that will increase capacity of the pipeline to 300,000 barrels per day is
 expected to be in service by November 2008. Current accounting principles
 require our consolidated financial statements and all other financial
 information included in this report to be stated to assume that the transfer
 of Trans Mountain net assets from Knight to us had occurred at the date when
 both Trans Mountain and we met the accounting requirements for entities under
 common control (January 1, 2006). As a result, financial statements and financial
 information presented for prior periods in this report have been restated to
 reflect our acquisition. In addition, due to the fact that Trans Mountains
 operations are managed separately, involve different products and marketing
 strategies, and produce discrete financial information that is separately
 evaluated internally by our management, we have identified our Trans Mountain
 pipeline system as a separate reportable business segment. For additional
 information regarding this acquisition, see Note 3 to our consolidated
 financial statements;
| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            
| |  | On May 14,
 2007, we announced plans to construct a $72 million natural gas pipeline
 designed to bring new supplies out of East Texas to markets in the Houston
 and Beaumont, Texas areas. The new pipeline will consist of approximately 63
 miles of 24-inch diameter pipe and multiple interconnections with other
 pipelines. It will connect our Kinder Morgan Tejas system in Harris County,
 Texas to our Kinder Morgan Texas Pipeline system in Polk County near Goodrich,
 Texas. In addition, we entered into a long-term binding agreement with
 CenterPoint Energy Services, Inc. to provide firm transportation for a
 significant portion of the initial project capacity, which will consist of
 approximately 225 million cubic feet per day of natural gas using existing
 compression and be expandable to over 400 million cubic feet per day with
 additional compression;                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            
| |  | On May 17,
 2007, KMR closed the public offering of 5,700,000 of its shares at a price of
 $52.26 per share. The net proceeds from the offering were used by KMR to buy
 additional i-units from us. We used the proceeds of $297.9 million from our
 i-unit issuance to reduce the borrowings under our commercial paper program;                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         
| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            
| |  | On May 30,
 2007, we purchased the Vancouver Wharves bulk marine terminal from British
 Columbia Railway Company, a crown corporation owned by the Province of
 British Columbia, for an aggregate consideration of $57.2 million, consisting
 of $38.8 million in cash and $18.4 million in assumed liabilities. The
 Vancouver Wharves facility is located on the north shore of the Port of
 Vancouvers main harbor, and includes five deep-sea vessel berths situated on
 a 139-acre site. The terminal assets include significant rail infrastructure,
 dry bulk and liquid storage, and material handling systems which allow the
 terminal to handle over 3.5 million tons of cargo annually;                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      

6

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| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | On June 21,
 2007, we closed a public offering of $550 million in principal amount of
 6.95% senior notes. The notes are due January 15, 2038. We received proceeds
 from the issuance of the notes, after underwriting discounts and commissions,
 of $543.9 million, and we used the proceeds to reduce our commercial
 paper debt;                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
| |  | On June 22,
 2007, the Federal Energy Regulatory Commission, referred to in this report as
 the FERC, issued an order granting construction and operation of our
 Kinder Morgan Louisiana Pipeline project, and we officially accepted
 the order on July 10, 2007. The Kinder Morgan Louisiana Pipeline is
 expected to cost approximately $510 million and will provide
 approximately 3.2 billion cubic feet per day of take-away natural gas
 capacity from the Cheniere Sabine Pass liquefied natural gas terminal,
 located in Cameron Parish, Louisiana, to various delivery points in Louisiana
 and will provide interconnects with many other natural gas pipelines,
 including Natural Gas Pipeline Company of America. The project is
 supported by fully subscribed capacity and long-term customer commitments
 with Chevron and Total and is expected to be in service by January 1,
 2009;
| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
| |  | On July 10,
 2007, we announced a combined $41 million investment for two terminal
 expansions to help meet the growing need for terminal services in key
 markets along the Gulf Coast. The investment consists of (i) the construction
 of a terminal that will include liquids storage, transfer and packaging
 facilities at the Rubicon Plant site in Geismar, Louisiana; and (ii) the
 purchase of liquids storage tanks from Royal Vopak in Westwego, Louisiana.
 The tanks have a storage capacity of approximately 750,000 barrels for
 vegetable oil, biodiesel, ethanol and other liquids products. The new
 terminal being built in Geismar will be capable of handling inbound and
 outbound material via pipeline, rail, truck and barge/vessel.
 Construction is expected to be complete by the fourth quarter of 2008;                                                                    
| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
| |  | On July 23,
 2007, following the FERCs expedited approval of our CALNEV Pipelines
 proposed tariff rate structure, we announced our continuing development
 of the approximate $426 million expansion of the pipeline system into
 Las Vegas, Nevada. The expansion involves the construction of a new
 16-inch diameter pipeline, which will parallel existing utility
 corridors between Colton, California and Las Vegas in order to minimize
 environmental impacts. System capacity would increase to approximately
 200,000 barrels per day upon completion of the expansion, and could be
 increased as necessary to over 300,000 barrels per day with the addition
 of pump stations. The CALNEV expansion is expected to be complete in
 early 2011;                                                                                                                                           
| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
| |  | On August 6,
 2007, Kinder Morgan Interstate Gas Transmission LLC, referred to in this
 report as KMIGT, filed for regulatory approval to construct and operate
 a 41-mile, $29 million natural gas pipeline from the Cheyenne Hub
 to markets in and around Greeley, Colorado. When completed, the Colorado
 Lateral expansion project will provide firm transportation of up to 55
 million cubic feet per day to a local utility under long-term contract. On
 February 21, 2008, the FERC granted the certification application;                                                                                                                                                                                                                                                                                                                                                                      
| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
| |  | On August
 23, 2007, we announced that we have begun construction on the approximately
 C$467 million  Anchor Loop project, the second phase of
 the Trans Mountain pipeline system expansion that will increase
 pipeline capacity from approximately 260,000 to 300,000 barrels of crude
 oil per day. The project is expected to be complete in November 2008. In
 April 2007, we commissioned 10 new pump stations which boosted capacity on
 Trans Mountain from 225,000 to approximately 260,000 barrels per day.
 The pipeline is currently operating at full capacity;                                                                                                                                                                                                                                                                                                                            
| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
| |  | On August
 28, 2007, we closed a public offering of $500 million in principal amount of
 5.85% senior notes. The notes are due September 15, 2012. We received
 proceeds from the issuance of the notes, after underwriting discounts
 and commissions, of $497.8 million, and we used the proceeds to reduce
 our commercial paper debt;                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
| |  | Effective
 September 1, 2007, we acquired five bulk terminal facilities from Marine
 Terminals, Inc. for an aggregate consideration of approximately $101.5
 million, consisting of $100.3 million in cash and an assumed liability of
 $1.2 million. The acquired assets and operations are primarily involved
 in the handling and storage of steel and alloys, and also provide
 stevedoring and harbor services, scrap handling, and scrap processing
 services to customers in the steel and alloys industry. The operations
 are located in Blytheville, Arkansas; Decatur, Alabama; Hertford, North
 Carolina; and Berkley, South Carolina. Combined, the five                                                                                                                                                                                                                                     

7

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| |  |                                                                                                                                                                                                                                                                                                                      
| |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | facilities
 handled approximately 13.7 million tons of steel products in 2007. Under
 long-term contracts, the acquired terminal facilities will continue to
 provide handling, processing, harboring and warehousing services to Nucor
 Corporation, one of the nations largest steel and steel products companies;

| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | Effective
 October 5, 2007, we sold our North System natural gas liquids and refined
 petroleum products pipeline system and our 50% ownership interest in the
 Heartland Pipeline Company to ONEOK Partners, L.P. for approximately $298.6
 million in cash. Our investment in net assets, including all transaction
 related accruals, was approximately $145.8 million, most of which represented
 property, plant and equipment, and we recognized approximately $152.8 million
 of gain on the sale of these net assets. In accordance with generally
 accepted accounting principles, we accounted for the North System business as
 a discontinued operation for all periods presented in this report, and we
 reported the gain with the caption as Gain on disposal of North System on
 our accompanying consolidated statement of income;
| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      
| |  | On October
 9, 2007, Midcontinent Express Pipeline LLC filed an application with the FERC
 requesting a certificate of public convenience and necessity that would
 authorize construction and operation of the approximate 500-mile Midcontinent
 Express Pipeline natural gas transmission system. We own a 50% interest in
 Midcontinent Express Pipeline LLC and Energy Transfer Partners L.P. owns the
 remaining interest. The Midcontinent Express Pipeline will create long-haul,
 firm natural gas transportation takeaway capacity, either directly or
 indirectly, from natural gas producing regions located in Texas, Oklahoma and
 Arkansas. The total project is expected to cost approximately $1.3 billion,
 and will have an initial transportation capacity of approximately 1.4 billion
 cubic feet per day of natural gas.      

| |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                
| |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | The
 Midcontinent Express Pipeline will originate near Bennington, Oklahoma and
 terminate at an interconnect with Williams Transco natural gas pipeline
 system near Butler, Alabama. It will also connect to Natural Gas Pipeline
 Company of Americas natural gas pipeline and to Energy Transfer Partners
 135-mile natural gas pipeline, which extends from the Barnett Shale natural
 gas producing area in North Texas to an interconnect with the Texoma Pipeline
 near Paris, Texas. The Midcontinent Express Pipeline now has long-term
 binding commitments from multiple shippers for approximately 1.2 billion
 cubic feet per day and, in order to provide a seamless transportation path
 from various locations in Oklahoma, the pipeline has also executed a firm
 capacity lease agreement with Enogex, Inc., an Oklahoma-based intrastate
 natural gas gathering and pipeline company that is wholly-owned by OGE Energy
 Corp. Subject to the receipt of regulatory approvals, construction of the
 pipeline is expected to commence in August 2008 and be in service during the
 first quarter of 2009.
| |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                
| |  | In January
 2008, in conjunction with the signing of additional binding transportation
 commitments, Midcontinent Express and MarkWest entered
 into an option agreement which provides MarkWest a one-time right to purchase
 a 10% ownership interest in Midcontinent Express after the pipeline is fully
 constructed and placed into service. If the option is exercised, we and
 Energy Transfer Partners will each own 45% of Midcontinent Express, while
 MarkWest will own the remaining 10%;                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          
| |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                

| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | On October
 17, 2007, we announced that we will invest approximately $23 million to
 expand our Kinder Morgan Interstate Gas Transmission pipeline system in order
 to serve five separate industrial plants (four of which
 produce ethanol) near Grand Island, Nebraska. The project is fully subscribed
 with long-term customer contracts, and subject to the receipt of regulatory
 approvals filed December 21, 2007, the expansion project is expected to be
 fully operational by the fall of 2008. Since 2000, our KMIGT system has
 connected to 17 new ethanol plants, 11 of which are located in the state of
 Nebraska;
| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
| |  | On November
 26, 2007, we announced that we expect to declare cash distributions of $4.02
 per unit for 2008, an almost 16% increase over our cash distributions of
 $3.48 per unit for 2007. This expectation includes contributions from assets
 owned by us as of the announcement date and does not include any potential
 benefits from unidentified acquisitions. Additionally, our expectation does
 not take into account any capital costs associated with financing the payment
 of reparations sought by shippers on our Pacific operations                                                                             

8

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| |  |                                                                                                                                                                                                                                  
| |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | interstate
 pipelines. Our expected growth in distributions in 2008 will be fueled by
 incremental earnings from Rockies Express-West (the western portion of the
 Rockies Express Pipeline), higher hedge prices on our         
| |  |                                                                                                                                                                                                                                  
| |  | crude oil
 production (budgeted production volumes for the SACROC oil field unit in 2008
 are approximately equal to the volumes realized in 2007), and an anticipated
 strong performance from our remaining business portfolio;

| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | In December
 2007, we completed a public offering of 7,130,000 of our common units,
 including common units sold pursuant to the underwriters over-allotment
 option, at a price of $48.09 per unit, less commissions and underwriting
 expenses. We received net proceeds of $342.9 million for the issuance of
 these 7,130,000 common units, and we used the proceeds to reduce the
 borrowings under our commercial paper program;                                                                                                                                                                                                                                              
| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      
| |  | In December
 2007, we completed a second expansion of our Pacific operations East Line
 pipeline segment. This expansion consisted of replacing approximately 130
 miles of 12-inch diameter pipe between El Paso, Texas and Tucson, Arizona
 with new 16-inch diameter pipe, constructing additional pump stations, and
 adding new storage tanks at Tucson. The project, completed at a cost of
 approximately $154 million, will increase East Line capacity by 36% (to
 approximately 200,000 barrels per day) to meet the demand for refined
 petroleum products, and will provide the platform for further incremental
 expansions through horsepower additions to the system;
| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      
| |  | On December
 31, 2007, TransColorado Gas Transmission LLC completed an approximate $50
 million expansion to provide up to 250 million cubic feet per day of natural
 gas transportation, starting January 1, 2008, from the Blanco Hub to an
 interconnect with the Rockies Express pipeline system at the Meeker Hub;                                                                                                                                                                                                                                                                                                                                                              
| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      
| |  | During 2007,
 we spent $1,691.6 million for additions to our property, plant and equipment,
 including both expansion and maintenance projects. Our capital expenditures
 included the following:                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    

| |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |                                                                                                                                                                                                                                                                                                                                                                                                                                     
| |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  | $480.0
 million in our Terminals segment, largely related to expanding the petroleum
 products storage capacity at our liquids terminal facilities, including the
 construction of additional liquids storage tanks at our facilities in Canada
 and at our facilities located on the Houston Ship Channel and the New York
 Harbor, and to various expansion projects and improvements undertaken at
 multiple terminal facilities;
| |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |                                                                                                                                                                                                                                                                                                                                                                                                                                     
| |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  | $382.5 million in our CO2segment, mostly related to
additional infrastructure, including wells and injection and compression
facilities, to support the expanding carbon dioxide flooding operations at
the SACROC and Yates oil field units in West Texas and to expand our capacity
to produce and deliver CO2from our McElmo Dome and Doe Canyon Source Fields;                                                                  
| |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |                                                                                                                                                                                                                                                                                                                                                                                                                                     
| |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  | $305.7
 million in our Trans Mountain segment, mostly related to pipeline expansion
 and improvement projects undertaken to increase crude oil and refined
 products delivery volumes;                                                                                                                                                                                                                                              
| |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |                                                                                                                                                                                                                                                                                                                                                                                                                                     
| |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  | $264.0
 million in our Natural Gas Pipelines segment, mostly related to current
 construction of our Kinder Morgan Louisiana Pipeline and to various expansion
 and improvement projects on our Texas intrastate natural gas pipeline
 systems, including the development of additional natural gas storage capacity
 at our natural gas storage facilities located at Markham and Dayton, Texas;
 and                              
| |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |                                                                                                                                                                                                                                                                                                                                                                                                                                     
| |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  | $259.4
 million in our Products Pipelines segment, mostly related to the continued
 expansion work on our Pacific operations East Line products pipeline,
 completion of construction projects resulting in additional capacity, and an
 additional refined products line on our CALNEV Pipeline in order to increase
 delivery service to the growing Las Vegas, Nevada market;                                                   
| |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |                                                                                                                                                                                                                                                                                                                                                                                                                                     
| |  | Our capital
 expansion program in 2007 was approximately $2.6 billion (including our share
 of capital expenditures for both the Rockies Express and Midcontinent Express
 natural gas pipeline projects).  Including all of our business acquisition
 expenditures, total spending was $3.3 billion.  Our capital expansion program
 will continue to be significant in 2008, as we expect to invest approximately
 $3.3 billion in expansion capital expenditures (including our share of capital
 expenditures for both the Rockies Express and Midcontinent Express natural gas
 pipeline projects), which will help drive earnings and cash flow growth in 2009
 and beyond;

9

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| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | On January
 16, 2008, we announced that we plan to invest approximately $56 million to
 construct a petroleum coke terminal at the BP refinery located in Whiting,
 Indiana. We have entered into a long-term contract to build and operate the
 facility, which will handle approximately 2.2 million tons of petroleum coke
 per year from a coker unit BP plans to construct to process heavy crude oil
 from Canada. The facility is expected to be in service in mid-year 2011;                                
| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
| |  | On February
 12, 2008, we completed an additional public offering of senior notes. We
 issued a total of $900 million in principal amount of senior notes,
 consisting of $600 million of 5.95% notes due February 15, 2018, and $300
 million of 6.95% notes due January 15, 2038. We received proceeds from the
 issuance of the notes, after underwriting discounts and commissions, of approximately
 $894.1 million, and we used the proceeds to reduce the borrowings under our
 commercial paper program; and
| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
| |  | On February
 12, 2008, we completed an additional offering of 1,080,000 of our common
 units at a price of $55.65 per unit in a privately negotiated transaction.
 We received net proceeds of $60.1 million for the issuance of these 1,080,000
 common units, and we used the proceeds to reduce the borrowings under our
 commercial paper program.                                                                                                                                                              

(b) Financial Information about
Segments

For
financial information on our five reportable business segments, see Note 15 to
our consolidated financial statements.

(c) Narrative Description of
Business

Business Strategy

The
objective of our business strategy is to grow our portfolio of businesses by:

| |   |                                                                                                                                                                     
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | focusing on
 stable, fee-based energy transportation and storage assets that are core to
 the energy infrastructure of growing markets within North America;        
| |   |                                                                                                                                                                     
| |  | increasing
 utilization of our existing assets while controlling costs, operating safely,
 and employing environmentally sound operating practices;                 
| |   |                                                                                                                                                                     
| |  | leveraging
 economies of scale from incremental acquisitions and expansions of assets
 that fit within our strategy and are accretive to cash flow and earnings; and
| |   |                                                                                                                                                                     
| |  | maximizing
 the benefits of our financial structure to create and return value to our
 unitholders.                                                                 

Business
Segments

We
own and manage a diversified portfolio of energy transportation and storage
assets. Our operations are conducted through our five operating limited
partnerships and their subsidiaries and are grouped into five reportable
business segments. These segments are as follows:

| |   |                                                                                                                                                                                                                                                                                                                                                          
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | Products
 Pipelineswhich consists of approximately 8,300 miles of refined petroleum
 products pipelines that deliver gasoline, diesel fuel, jet fuel and natural
 gas liquids to various markets; plus approximately 60 associated product
 terminals and petroleum pipeline transmix processing facilities serving
 customers across the United States;
| |   |                                                                                                                                                                                                                                                                                                                                                          
| |  | Natural Gas
 Pipelineswhich consists of approximately 14,700 miles of natural gas
 transmission pipelines and gathering lines, plus natural gas storage,
 treating and processing facilities, through which natural gas is gathered,
 transported, stored, treated, processed and sold;                                                                 

10

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| |   |                                                                                                                                                                                                                                                                                                                                                                                                                            
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | CO2 which produces,
markets and transports, through approximately 1,300 miles of pipelines,
carbon dioxide to oil fields that use carbon dioxide to increase
production of oil; owns interests in and/or operates ten oil fields in West
Texas; and owns and operates a 450 mile crude oil pipeline system in West
Texas;                                                                                                 
| |   |                                                                                                                                                                                                                                                                                                                                                                                                                            
| |  | Terminalswhich
 consists of approximately 108 owned or operated liquids and bulk terminal
 facilities and more than 45 rail transloading and materials handling
 facilities located throughout the United States and portions of Canada, which
 together transload, store and deliver a wide variety of bulk, petroleum,
 petrochemical and other liquids products for customers across the United
 States and Canada; and
| |   |                                                                                                                                                                                                                                                                                                                                                                                                                            
| |  | Trans
 Mountainwhich consists of over 700 miles of common carrier pipelines,
 originating at Edmonton, Alberta, for the transportation of crude oil and
 refined petroleum to the interior of British Columbia and to marketing
 terminals and refineries located in the greater Vancouver, British Columbia
 area and Puget Sound in Washington State; plus five associated product
 terminals.                          

Generally,
as utilization of our pipelines and terminals increases, our fee-based revenues
increase. We do not face significant risks relating directly to short-term
movements in commodity prices for two principal reasons. First, we primarily
transport and/or handle products for a fee and are not engaged in significant
unmatched purchases and resales of commodity products. Second, in those areas
of our business where we do face exposure to fluctuations in commodity prices, primarily oil production in
our CO2business
segment, we engage in a hedging program to mitigate this exposure.

We
regularly consider and enter into discussions regarding potential acquisitions,
including those from Knight or its affiliates, and are currently contemplating
potential acquisitions. Any such transaction would be subject to negotiation of
mutually agreeable terms and conditions, receipt of fairness opinions and
approval of the parties respective boards of directors. While there are
currently no unannounced purchase agreements for the acquisition of any
material business or assets, such transactions can be effected quickly, may
occur at any time and may be significant in size relative to our existing
assets or operations.

It
is our intention to carry out the above business strategy, modified as
necessary to reflect changing economic conditions and other circumstances.
However, as discussed under Item 1A Risk Factors below, there are factors
that could affect our ability to carry out our strategy or affect its level of
success even if carried out.

Products
Pipelines

Our
Products Pipelines segment consists of our refined petroleum products and
natural gas liquids pipelines and their associated terminals, our Southeast
terminals and our transmix processing facilities.

Pacific
Operations

Our
Pacific operations include our SFPP, L.P. operations, our CALNEV Pipeline
operations and our West Coast Liquid Terminals operations. The assets include
interstate common carrier pipelines regulated by the FERC, intrastate pipelines
in the state of California regulated by the California Public Utilities
Commission, and certain non rate-regulated operations and terminal facilities.

Our
Pacific operations serve seven western states with approximately 3,000 miles of
refined petroleum products pipelines and related terminal facilities that
provide refined products to some of the fastest growing population centers in
the United States, including California; Las Vegas and Reno, Nevada; and the
Phoenix-Tucson, Arizona corridor. For 2007, the three main product types
transported were gasoline (59%), diesel fuel (23%) and jet fuel (18%).

Our
Pacific operations also includes CALNEV Pipeline which consists of two parallel
248-mile, 14-inch and 8-inch diameter pipelines that run from our facilities at
Colton, California to Las Vegas, Nevada, and which also serves Nellis Air Force
Base located in Las Vegas. It also includes approximately 55 miles of pipeline
serving Edwards Air Force Base.

11

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Our Pacific
operations include 15
truck-loading terminals (13 on SFPP, L.P. and two on CALNEV) with an aggregate
usable tankage capacity of approximately 13.7 million barrels. The truck
terminals provide services including short-term product storage, truck loading,
vapor handling, additive injection, dye injection and oxygenate blending.

Our
Pacific operations West Coast Liquid Terminals are fee-based terminals located
in the Seattle, Portland, San Francisco and Los Angeles areas along the west
coast of the United States with a combined total capacity of approximately 8.3
million barrels of storage for both petroleum products and chemicals.

Markets.Combined, our Pacific operations pipelines transport
approximately 1.3 million barrels per day of refined petroleum products,
providing pipeline service to approximately 31 customer-owned terminals, 11
commercial airports and 14 military bases. Currently, our Pacific operations
pipelines serve approximately 100 shippers in the refined petroleum products
market; the largest customers being major petroleum companies, independent
refiners, and the United States military.

A
substantial portion of the product volume transported is gasoline. Demand for
gasoline depends on such factors as prevailing economic conditions, vehicular
use patterns and demographic changes in the markets served. If current trends
continue, we expect the majority of our Pacific operations markets to maintain
growth rates that will exceed the national average for the foreseeable future.
The volume of products transported is affected by various factors, principally
demographic growth, economic conditions, product pricing, vehicle miles
traveled, population and fleet mileage. Certain product volumes can experience
seasonal variations and, consequently, overall volumes may be lower during the
first and fourth quarters of each year.

Supply.The majority of refined products supplied to our
Pacific operations pipeline system come from the major refining centers around
Los Angeles, San Francisco, El Paso and Puget Sound, as well as from waterborne
terminals and connecting pipelines located near these refining centers.

Competition.The two
most significant competitors of our Pacific operations pipeline system are
proprietary pipelines owned and operated by major oil companies in the area
where our pipeline system delivers products and also refineries with terminals
that have trucking arrangements within our market areas. We believe that high
capital costs, tariff regulation, and environmental and right-of-way permitting
considerations make it unlikely that a competing pipeline system comparable in
size and scope to our Pacific operations will be built in the foreseeable
future. However, the possibility of individual pipelines being constructed or
expanded to serve specific markets is a continuing competitive factor.

The
use of trucks for product distribution from either shipper-owned proprietary
terminals or from their refining centers continues to compete for short haul
movements by pipeline. Our Pacific terminal operations compete with terminals
owned by our shippers and by third party terminal operators in California,
Arizona and Nevada. Competitors include Shell Oil Products U.S., BP (formerly
Arco Terminal Services Company), Wilmington Liquid Bulk Terminals (Vopak),
NuStar, and Chevron. We cannot predict with any certainty whether the use of
short haul trucking will decrease or increase in the future.

Plantation
Pipe Line Company

We
own approximately 51% of Plantation Pipe Line Company, referred to in this
report as Plantation, a 3,100-mile refined petroleum products pipeline system
serving the southeastern United States. An affiliate of ExxonMobil owns the
remaining 49% ownership interest. ExxonMobil is the largest shipper on the
Plantation system both in terms of volumes and revenues. We operate the system
pursuant to agreements with Plantation Services LLC and Plantation. Plantation
serves as a common carrier of refined petroleum products to various
metropolitan areas, including Birmingham, Alabama; Atlanta, Georgia; Charlotte,
North Carolina; and the Washington, D.C. area.

For
the year 2007, Plantation delivered an average of 535,672 barrels per day of refined
petroleum products. These delivered volumes were comprised of gasoline (63%),
diesel/heating oil (23%) and jet fuel (14%). Average delivery volumes for 2007
were 3.5% lower than the 555,063 barrels per day delivered during 2006. The
decrease was predominantly driven by (i) the full year impact of alternative
pipeline service (initial startup mid-2006) into Southeast markets, and (ii)
changes in production patterns from Louisiana refineries related to refiners
directing

12

---



higher margin
products (such as reformulated gasoline blendstock for oxygenate blending) into
markets not directly served by Plantation.

Markets.Plantation ships products for approximately 30
companies to terminals throughout the southeastern United States. Plantations
principal customers are Gulf Coast refining and marketing companies, fuel
wholesalers, and the United States Department of Defense. Plantations top five
shippers represent approximately 80% of total system volumes.

The
eight states in which Plantation operates represent a collective pipeline
demand of approximately two million barrels per day of refined petroleum
products. Plantation currently has direct access to about 1.5 million barrels
per day of this overall market. The remaining 0.5 million barrels per day of
demand lies in markets (e.g., Nashville, Tennessee; North Augusta, South
Carolina; Bainbridge, Georgia; and Selma, North Carolina) currently served by
another pipeline company. Plantation also delivers jet fuel to the Atlanta,
Georgia; Charlotte, North Carolina; and Washington, D.C. airports (Ronald
Reagan National and Dulles). Combined jet fuel shipments to these four major
airports increased 3% in 2007 compared to 2006, with the majority of this
growth occurring at Dulles Airport.

Supply.Products shipped on Plantation originate at various
Gulf Coast refineries from which major integrated oil companies and independent
refineries and wholesalers ship refined petroleum products. Plantation is
directly connected to and supplied by a total of ten major refineries
representing approximately 2.3 million barrels per day of refining capacity.

Competition.Plantation competes primarily with the Colonial
pipeline system, which also runs from Gulf Coast refineries throughout the
southeastern United States and extends into the northeastern states.

Central
Florida Pipeline

Our
Central Florida pipeline system consists of a 110-mile, 16-inch diameter
pipeline that transports gasoline and an 85-mile, 10-inch diameter pipeline
that transports diesel fuel and jet fuel from Tampa to Orlando, with an
intermediate delivery point on the 10-inch pipeline at Intercession City,
Florida. In addition to being connected to our Tampa terminal, the pipeline
system is connected to terminals owned and operated by TransMontaigne, Citgo,
BP, and Marathon Petroleum. The 10-inch diameter pipeline is connected to our
Taft, Florida terminal (located near Orlando) and is also the sole pipeline
supplying jet fuel to the Orlando International Airport in Orlando, Florida. In
2007, the pipeline system transported approximately 113,800 barrels per day of
refined products, with the product mix being approximately 69% gasoline, 12%
diesel fuel, and 19% jet fuel.

We
also own and operate liquids terminals in Tampa and Taft, Florida. The Tampa
terminal contains approximately 1.5 million barrels of storage capacity and is
connected to two ship dock facilities in the Port of Tampa. The Tampa terminal
provides storage for gasoline, diesel fuel and jet fuel for further movement
into either trucks or into the Central Florida pipeline system. The Tampa
terminal also provides storage and truck rack blending services for ethanol and
bio-diesel. The Taft terminal contains approximately 0.7 million barrels of
storage capacity, for gasoline and diesel fuel for further movement into
trucks.

Markets.The estimated total refined petroleum products demand
in the state of Florida is approximately 800,000 barrels per day. Gasoline is,
by far, the largest component of that demand at approximately 545,000 barrels
per day. The total refined petroleum products demand for the Central Florida
region of the state, which includes the Tampa and Orlando markets, is estimated
to be approximately 360,000 barrels per day, or 45% of the consumption of
refined products in the state. We distribute approximately 150,000 barrels of
refined petroleum products per day, including the Tampa terminal truck
loadings. The balance of the market is supplied primarily by trucking firms and
marine transportation firms. Most of the jet fuel used at Orlando International
Airport is moved through our Tampa terminal and the Central Florida pipeline
system. The market in Central Florida is seasonal, with demand peaks in March and
April during spring break and again in the summer vacation season, and is also
heavily influenced by tourism, with Disney World and other attractions located
near Orlando.

Supply.The vast majority of refined petroleum products
consumed in Florida is supplied via marine vessels from major refining centers
in the Gulf Coast of Louisiana and Mississippi and refineries in the Caribbean
basin. A

13

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lesser amount
of refined petroleum products is being supplied by refineries in Alabama and by
Texas Gulf Coast refineries via marine vessels and through pipeline networks
that extend to Bainbridge, Georgia. The supply into Florida is generally
transported by ocean-going vessels to the larger metropolitan ports, such as
Tampa, Port Everglades near Miami, and Jacksonville. Individual markets are
then supplied from terminals at these ports and other smaller ports,
predominately by trucks, except the Central Florida region, which is served by
a combination of trucks and pipelines.

Competition.
With respect to the Central Florida pipeline system, the most significant
competitors are trucking firms and marine transportation firms. Trucking
transportation is more competitive in serving markets close to the marine
terminals on the east and west coasts of Florida. We are utilizing tariff
incentives to attract volumes to the pipeline that might otherwise enter the
Orlando market area by truck from Tampa or by marine vessel into Cape
Canaveral. We believe it is unlikely that a new pipeline system comparable in
size and scope to our Central Florida Pipeline system will be constructed, due
to the high cost of pipeline construction, tariff regulation and environmental
and right-of-way permitting in Florida. However, the possibility of such a
pipeline or a smaller capacity pipeline being built is a continuing competitive
factor.

With
respect to the terminal operations at Tampa, the most significant competitors
are proprietary terminals owned and operated by major oil companies, such as
Marathon Petroleum, BP and Citgo, located along the Port of Tampa, and the
Chevron and Motiva terminals in Port Tampa. These terminals generally support
the storage requirements of their parent or affiliated companies refining and
marketing operations and provide a mechanism for an oil company to enter into
exchange contracts with third parties to serve its storage needs in markets
where the oil company may not have terminal assets.

Federal
regulation of marine vessels, including the requirement under the Jones Act
that United States-flagged vessels contain double-hulls, is a significant
factor influencing the availability of vessels that transport refined petroleum
products. Marine vessel owners are phasing in the requirement based on the age
of the vessel and some older vessels are being redeployed into use in other
jurisdictions rather than being retrofitted with a double-hull for use in the
United States.

Cochin
Pipeline System

Our
Cochin pipeline system consists of an approximate 1,900-mile, 12-inch diameter
multi-product pipeline operating between Fort Saskatchewan, Alberta and
Windsor, Ontario, including five terminals.

The
pipeline operates on a batched basis and has an estimated system capacity of
approximately 70,000 barrels per day. It includes 31 pump stations spaced at 60
mile intervals and five United States propane terminals. Underground storage is
available at Fort Saskatchewan, Alberta and Windsor, Ontario through third
parties. In 2007, the pipeline system transported approximately 40,600 barrels
per day of natural gas liquids.

Markets.
The pipeline traverses three provinces in Canada and seven states in the United
States transporting high vapor pressure ethane, propane, butane and natural gas
liquids to the Midwestern United States and eastern Canadian petrochemical and
fuel markets. Current operations involve only the transportation of propane on
Cochin.

Supply.Injection into the system can occur from BP,
Provident, Keyera or Dow facilities with connections at Fort Saskatchewan,
Alberta and from Spectra at interconnects at Regina and Richardson,
Saskatchewan.

Competition.The pipeline competes with railcars and Enbridge
Energy Partners for natural gas liquids long-haul business from Fort
Saskatchewan, Alberta and Windsor, Ontario. The pipelines primary competition
in the Chicago natural gas liquids market comes from the combination of the
Alliance pipeline system, which brings unprocessed gas into the United States
from Canada, and from Aux Sable, which processes and markets the natural gas
liquids in the Chicago market.

Cypress
Pipeline

Our
Cypress pipeline is an interstate common carrier natural gas liquids pipeline
originating at storage facilities in Mont Belvieu, Texas and extending 104
miles east to a major petrochemical producer in the Lake Charles,

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Louisiana
area. Mont Belvieu, located approximately 20 miles east of Houston, is the
largest hub for natural gas liquids gathering, transportation, fractionation
and storage in the United States.

Markets.
The pipeline was built to service Westlake Petrochemicals Corporation in the
Lake Charles, Louisiana area under a 20-year ship-or-pay agreement that expires
in 2011. The contract requires a minimum volume of 30,000 barrels per day.

Supply.
The Cypress pipeline originates in Mont Belvieu where it is able to receive
ethane and ethane/propane mix from local storage facilities. Mont Belvieu has
facilities to fractionate natural gas liquids received from several pipelines
into ethane and other components. Additionally, pipeline systems that transport
natural gas liquids from major producing areas in Texas, New Mexico, Louisiana,
Oklahoma and the Mid-Continent Region supply ethane and ethane/propane mix to
Mont Belvieu.

Competition.The pipelines primary competition into the Lake
Charles market comes from Louisiana onshore and offshore natural gas liquids.

Southeast
Terminals

Our
Southeast terminal operations consist of Kinder Morgan Southeast Terminals LLC
and its consolidated affiliate, Guilford County Terminal Company, LLC. Kinder
Morgan Southeast Terminals LLC, a wholly-owned subsidiary referred to in this
report as KMST, was formed for the purpose of acquiring and operating
high-quality liquid petroleum products terminals located primarily along the
Plantation/Colonial pipeline corridor in the Southeastern United States.

Combined,
our Southeast terminal operations consist of 24 petroleum products terminals
with a total storage capacity of approximately 8.0 million barrels. These
terminals transferred approximately 361,000 barrels of refined products per day
during 2007 and approximately 347,000 barrels of refined products per day
during 2006.

Markets.
KMSTs acquisition and marketing activities are focused on the Southeastern
United States from Mississippi through Virginia, including Tennessee. The
primary function involves the receipt of petroleum products from common carrier
pipelines, short-term storage in terminal tankage, and subsequent loading onto
tank trucks. KMST also offered ethanol blending and storage services in
northern Virginia during 2007. Longer term storage is available at many of the
terminals. KMST has a physical presence in markets representing almost 80% of
the pipeline-supplied demand in the Southeast and offers a competitive
alternative to marketers seeking a relationship with a truly independent truck
terminal service provider.

Supply.Product supply is predominately from Plantation and/or
Colonial pipelines. To the maximum extent practicable, we endeavor to connect
KMST terminals to both Plantation and Colonial.

Competition.
There are relatively few independent terminal operators in the Southeast. Most
of the refined petroleum products terminals in this region are owned by large
oil companies (BP, Motiva, Citgo, Marathon, and Chevron) who use these assets
to support their own proprietary market demands as well as product exchange
activity. These oil companies are not generally seeking third party throughput
customers. Magellan Midstream Partners and TransMontaigne Product Services
represent the other significant independent terminal operators in this region.

Transmix
Operations

Our
Transmix operations include the processing of petroleum pipeline transmix, a
blend of dissimilar refined petroleum products that have become co-mingled in
the pipeline transportation process. During pipeline transportation, different
products are transported through the pipelines abutting each other, and
generate a volume of different mixed products called transmix. At our transmix
processing facilities, we process and separate pipeline transmix into
pipeline-quality gasoline and light distillate products. We process transmix at
six separate processing facilities located in Colton, California; Richmond,
Virginia; Dorsey Junction, Maryland; Indianola, Pennsylvania; Wood River,
Illinois; and Greensboro, North Carolina. Combined, our transmix facilities
processed approximately 10.4 million barrels of transmix in 2007 and
approximately 9.1 million barrels in 2006.

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In
2007, we increased the processing capacity of the recently constructed
Greensboro, North Carolina transmix facility to better serve the needs of
Plantation. The facility, which is located within KMSTs refined products tank
farm, now has the capability to process approximately 8,500 barrels of transmix
per day. In addition to providing additional processing business, the facility
continues to provide Plantation a lower cost alternative compared to other
transmix processing arrangements that recover ultra low sulfur diesel, and also
more fully utilizes current KMST tankage at the Greensboro, North Carolina tank
farm.

Markets.The Gulf and East Coast refined petroleum products
distribution system, particularly the Mid-Atlantic region, is the target market
for our East Coast transmix processing operations. The Mid-Continent area and
the New York Harbor are the target markets for our Illinois and Pennsylvania
assets, respectively. Our West Coast transmix processing operations support the
markets served by our Pacific operations in Southern California.

Supply.Transmix generated by Plantation, Colonial, Explorer,
Sun, Teppco, and our Pacific operations provide the vast majority of the
supply. These suppliers are committed to the use of our transmix facilities
under long-term contracts. Individual shippers and terminal operators provide
additional supply. Shell acquires transmix for processing at Indianola,
Richmond and Wood River; Colton is supplied by pipeline shippers of our Pacific
operations; Dorsey Junction is supplied by Colonial Pipeline Company and
Greensboro is supplied by Plantation.

Competition.Placid Refining is our main competitor in the Gulf
Coast area. There are various processors in the Mid-Continent area, primarily
ConocoPhillips, Gladieux Refining and Williams Energy Services, who compete
with our transmix facilities. Motiva Enterprisess transmix facility located
near Linden, New Jersey is the principal competition for New York Harbor
transmix supply and for our Indianola facility. A number of smaller
organizations operate transmix processing facilities in the West and Southwest.
These operations compete for supply that we envision as the basis for growth in
the West and Southwest. Our Colton processing facility also competes with major
oil company refineries in California.

Natural Gas Pipelines

Our
Natural Gas Pipelines segment contains both interstate and intrastate
pipelines. Its primary businesses consist of natural gas sales, transportation,
storage, gathering, processing and treating. Within this segment, we own
approximately 14,700 miles of natural gas pipelines and associated storage and
supply lines that are strategically located at the center of the North American
pipeline grid. Our transportation network provides access to the major gas
supply areas in the western United States, Texas and the Midwest, as well as
major consumer markets.

Texas
Intrastate Natural Gas Pipeline Group

The
group, which operates primarily along the Texas Gulf Coast, consists of the
following four natural gas pipeline systems:

| |   |                                          
| | - | -----------------------------------------
| |  | our Kinder
  Morgan Texas Pipeline;      
| |   |                                          
| |  | our Kinder
  Morgan Tejas Pipeline;      
| |   |                                          
| |  | our
  Mier-Monterrey Mexico Pipeline; and
| |   |                                          
| |  | our Kinder
  Morgan North Texas Pipeline.

The
two largest systems in the group are our Kinder Morgan Texas Pipeline and our
Kinder Morgan Tejas Pipeline. These pipelines essentially operate as a single
pipeline system, providing customers and suppliers with improved flexibility
and reliability. The combined system includes approximately 6,000 miles of
intrastate natural gas pipelines with a peak transport and sales capacity of
approximately 5.2 billion cubic feet per day of natural gas and approximately
120 billion cubic feet of system natural gas storage capacity. In addition, the
combined system, through owned assets and contractual arrangements with third
parties, has the capability to process 915 million cubic feet per day of
natural gas for liquids extraction and to treat approximately 250 million cubic
feet per day of natural gas for carbon dioxide removal.

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Collectively,
the combined system primarily serves the Texas Gulf Coast by selling,
transporting, processing and treating gas from multiple onshore and offshore
supply sources to serve the Houston/Beaumont/Port Arthur industrial markets,
local gas distribution utilities, electric utilities and merchant power
generation markets. It serves as a buyer and seller of natural gas, as well as
a transporter of natural gas. The purchases and sales of natural gas are
primarily priced with reference to market prices in the consuming region of its
system. The difference between the purchase and sale prices is the rough
equivalent of a transportation fee and fuel costs.

Included
in the operations of our Kinder Morgan Tejas system is our Kinder Morgan Border
Pipeline system. Kinder Morgan Border owns and operates an approximately
97-mile, 24-inch diameter pipeline that extends from a point of interconnection
with the pipeline facilities of Pemex Gas Y Petroquimica Basica at the
International Border between the United States and Mexico, to a point of
interconnection with other intrastate pipeline facilities of Kinder Morgan
Tejas located at King Ranch, Kleburg County, Texas. The 97-mile pipeline,
referred to as the import/export facility, is capable of importing Mexican gas
into the United States, and exporting domestic gas to Mexico. The imported
Mexican gas is received from, and the exported domestic gas is delivered to,
Pemex. The capacity of the import/export facility is approximately 300 million
cubic feet of natural gas per day.

Our
Mier-Monterrey Pipeline consists of a 95-mile, 30-inch diameter natural gas
pipeline that stretches from south Texas to Monterrey, Mexico and can transport
up to 375 million cubic feet per day. The pipeline connects to a 1,000-megawatt
power plant complex and to the PEMEX natural gas transportation system. We have
entered into a long-term contract (expiring in 2018) with Pemex, which has
subscribed for all of the pipelines capacity.

Our
Kinder Morgan North Texas Pipeline consists of an 86-mile, 30-inch diameter
pipeline that transports natural gas from an interconnect with the facilities
of Natural Gas Pipeline Company of America LLC, referred to in this report as
NGPL, in Lamar County, Texas to a 1,750-megawatt electric generating facility
located in Forney, Texas, 15 miles east of Dallas, Texas. It has the capacity
to transport 325 million cubic feet per day of natural gas and is fully
subscribed under a long-term contract that expires in 2032.  In 2006, the
existing system was enhanced to be bi-directional, so that deliveries of
additional supply coming out of the Barnett Shale area can be delivered into
NGPLs pipeline as well as power plants in the area.

We
also own and operate various gathering systems in South and East Texas. These
systems aggregate natural gas supplies into our main transmission pipelines,
and in certain cases, aggregate natural gas that must be processed or treated
at its own or third-party facilities. We own plants that can process up to 115
million cubic feet per day of natural gas for liquids extraction. In addition,
we have contractual rights to process approximately 800 million cubic feet per
day of natural gas at various third-party owned facilities. We also own and
operate three natural gas treating plants that provide carbon dioxide and/or
hydrogen sulfide removal. We can treat up to 155 million cubic feet per day of
natural gas for carbon dioxide removal at our Fandango Complex in Zapata
County, Texas, 50 million cubic feet per day of natural gas at our Indian Rock
Plant in Upshur County, Texas and approximately 45 million cubic feet per day
of natural gas at our Thompsonville Facility located in Jim Hogg County, Texas.

Our
North Dayton natural gas storage facility, located in Liberty County, Texas,
has two existing storage caverns providing approximately 6.3 billion cubic feet
of total capacity, consisting of 4.2 billion cubic feet of working capacity and
2.1 billion cubic feet of cushion gas. We have entered into a long-term storage
capacity and transportation agreement with NRG covering two billion cubic feet
of natural gas working capacity that expires in March 2017. In June 2006, we
announced an expansion project that will significantly increase natural gas storage
capacity at our North Dayton facility. The project is now expected to cost
between $105 million and $115 million and involves the development of a new
underground storage cavern that will add an estimated 6.5 billion cubic feet of
incremental working natural gas storage capacity. The additional capacity is
expected to be available in mid-2010.

We
also own the West Clear Lake natural gas storage facility located in Harris
County, Texas. Under a long term contract that expires in 2012, Coral Energy
Resources, L.P. operates the facility and controls the 96 billion cubic feet of
natural gas working capacity, and we provide transportation service into and
out of the facility.

Additionally,
we lease a salt dome storage facility located near Markham, Texas according to
the provisions of an operating lease that expires in March 2013. We can, at our
sole option, extend the term of this lease for two

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additional
ten-year periods. The facility was expanded in 2007 and now consists of four salt
dome caverns with approximately 17.3 billion cubic feet of working natural gas
capacity and up to 1.1 billion cubic feet per day of peak deliverability. We
also lease two salt dome caverns, known as the Stratton Ridge Facilities, from
BP America Production Company in Brazoria County, Texas. The Stratton Ridge
Facilities have a combined working natural gas capacity of 1.4 billion cubic
feet and a peak day deliverability of 100 million cubic feet per day. A lease
with Dow Hydrocarbon & Resources, Inc. for a salt dome cavern containing
approximately 5.0 billion cubic feet of working capacity expired during the
third quarter of 2007.

Markets.Texas is one of the largest natural gas consuming
states in the country. The natural gas demand profile in our Texas intrastate
pipeline groups market area is primarily composed of industrial (including
on-site cogeneration facilities), merchant and utility power, and local natural
gas distribution consumption. The industrial demand is primarily year-round load.
Merchant and utility power demand peaks in the summer months and is
complemented by local natural gas distribution demand that peaks in the winter
months. As new merchant gas fired generation has come online and displaced
traditional utility generation, we have successfully attached many of these new
generation facilities to our pipeline systems in order to maintain and grow our
share of natural gas supply for power generation. Additionally, in 2007, we
have increased our capability and commitment to serve the growing local natural
gas distribution market in the greater Houston metropolitan area.

We
serve the Mexico market through interconnection with the facilities of Pemex at
the United States-Mexico border near Arguellas, Mexico and our Mier-Monterrey
Mexico pipeline. In 2007, deliveries through the existing interconnection near
Arguellas fluctuated from zero to approximately 206 million cubic feet per day
of natural gas, and there were several days of exports to the United States
which ranged up to 250 million cubic feet per day. Deliveries to Monterrey also
generally ranged from zero to 312 million cubic feet per day. We primarily
provide transport service to these markets on a fee for service basis,
including a significant demand component, which is paid regardless of actual
throughput. Revenues earned from our activities in Mexico are paid in U.S.
dollar equivalent.

Supply.
We purchase our natural gas directly from producers attached to our system in
South Texas, East Texas, West Texas and along the Texas Gulf Coast. In
addition, we also purchase gas at interconnects with third-party interstate and
intrastate pipelines. While our intrastate group does not produce gas, it does
maintain an active well connection program in order to offset natural declines
in production along its system and to secure supplies for additional demand in
its market area. Our intrastate system has access to both onshore and offshore
sources of supply, and is well positioned to interconnect with liquefied natural
gas projects currently under development by others along the Texas Gulf Coast.

Competition.
The Texas intrastate natural gas market is highly competitive, with many
markets connected to multiple pipeline companies. We compete with interstate
and intrastate pipelines, and their shippers, for attachments to new markets
and supplies and for transportation, processing and treating services.

Rocky
Mountain Natural Gas Pipeline Group

The
group, which operates primarily along the Rocky Mountain region of the Western
portion of the United States, consists of the following four natural gas
pipeline systems:

| |   |                                                              
| | - | -------------------------------------------------------------
| |  | our Kinder
  Morgan Interstate Gas Transmission Pipeline;    
| |   |                                                              
| |  | our
  Trailblazer Pipeline;                                  
| |   |                                                              
| |  | our
  Trans-Colorado Pipeline; and                           
| |   |                                                              
| |  | our 51%
  ownership interest in the Rockies Express Pipeline.

Kinder
Morgan Interstate Gas Transmission LLC

Kinder
Morgan Interstate Gas Transmission LLC, referred to in this report as KMIGT,
owns approximately 5,100 miles of transmission lines in Wyoming, Colorado,
Kansas, Missouri and Nebraska. The pipeline system is

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powered by 28
transmission and storage compressor stations with approximately 160,000
horsepower. KMIGT also owns the Huntsman natural gas storage facility, located
in Cheyenne County, Nebraska, which has approximately 10 billion cubic feet of
firm capacity commitments and provides for withdrawal of up to 169 million
cubic feet of natural gas per day.

Under
transportation agreements and FERC tariff provisions, KMIGT offers its
customers firm and interruptible transportation and storage services, including
no-notice service and park and loan services. For these services, KMIGT charges
rates which include the retention of fuel and gas lost and unaccounted for
in-kind. Under KMIGTs tariffs, firm transportation and storage customers pay
reservation charges each month plus a commodity charge based on the actual
transported or stored volumes. In contrast, interruptible transportation and storage
customers pay a commodity charge based upon actual transported and/or stored
volumes. Under the no-notice service, customers pay a fee for the right to use
a combination of firm storage and firm transportation to effect deliveries of
natural gas up to a specified volume without making specific nominations. KMIGT
also has the authority to make gas purchases and sales, as needed for system
operations, pursuant to its currently effective FERC gas tariff.

KMIGT
also offers its Cheyenne Market Center service, which provides nominated
storage and transportation service between its Huntsman storage field and
multiple interconnecting pipelines at the Cheyenne Hub, located in Weld County,
Colorado. This service is fully subscribed through May 2014.

Markets.
Markets served by KMIGT provide a stable customer base with expansion
opportunities due to the systems access to growing Rocky Mountain supply
sources. Markets served by KMIGT are comprised mainly of local natural gas
distribution companies and interconnecting interstate pipelines in the
mid-continent area. End-users of the local natural gas distribution companies
typically include residential, commercial, industrial and agricultural
customers. The pipelines interconnecting with KMIGT in turn deliver gas into
multiple markets including some of the largest population centers in the
Midwest. Natural gas demand to power pumps for crop irrigation during the
summer from time-to-time exceeds heating season demand and provides KMIGT
relatively consistent volumes throughout the year. In addition, KMIGT has seen
a significant increase in demand from ethanol producers, and is actively
seeking ways to meet the demands from the ethanol producing community.

Supply.
Approximately 7%, by volume, of KMIGTs firm contracts expire within one year
and 51% expire within one to five years. Over 99% of the systems total firm
transport capacity is currently subscribed, with 78%
of the total contracted capacity held by KMIGTs
top nine shippers.

Competition.
KMIGT competes with other interstate and intrastate gas pipelines transporting
gas from the supply sources in the Rocky Mountain and Hugoton Basins to
mid-continent pipelines and market centers.

Trailblazer
Pipeline Company LLC

Our
subsidiary, Trailblazer Pipeline Company LLC, owns a 436-mile natural gas
pipeline system. Trailblazers pipeline originates at an interconnection with
Wyoming Interstate Company Ltd.s pipeline system near Rockport, Colorado and
runs through southeastern Wyoming to a terminus near Beatrice, Nebraska where
it interconnects with NGPL and Northern Natural Gas Companys pipeline systems.
NGPL, an investee of Knight, manages, maintains and operates Trailblazer, for
which it is reimbursed at cost.

Trailblazer
provides transportation services to third-party natural gas producers,
marketers, local distribution companies and other shippers. Pursuant to
transportation agreements and FERC tariff provisions, Trailblazer offers its
customers firm and interruptible transportation. Under Trailblazers tariffs,
firm transportation customers pay reservation charges each month plus a
commodity charge based on actual volumes transported. Interruptible
transportation customers pay a commodity charge based upon actual volumes
transported.

Markets.
Significant growth in Rocky Mountain natural gas supplies has prompted a need
for additional pipeline transportation service. Trailblazer has a certificated
capacity of 846 million cubic feet per day of natural gas.

Supply.
As of December 31, 2007, none of Trailblazers firm contracts, by volume,
expire before one year and 54%, by volume, expire within one to five years.
Affiliated entities have contracted for less than 1% of the total firm
transportation capacity. All of the systems firm transport capacity is
currently subscribed.

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Competition.
The main competition that Trailblazer currently faces is that the gas supply in
the Rocky Mountain area either stays in the area or is moved west and therefore
is not transported on Trailblazers pipeline. In addition, El Pasos Cheyenne
Plains Pipeline can transport approximately 730 million cubic feet per day of
natural gas from Weld County, Colorado to Greensburg, Kansas and competes with
Trailblazer for natural gas pipeline transportation demand from the Rocky
Mountain area. Additional competition could come from the Rockies Express
pipeline system or from proposed pipeline projects. No assurance can be given
that additional competing pipelines will not be developed in the future.

TransColorado
Gas Transmission Company LLC

Our
subsidiary, TransColorado Gas Transmission Company LLC, owns a 300-mile
interstate natural gas pipeline that extends from approximately 20 miles
southwest of Meeker, Colorado to Bloomfield, New Mexico. It has multiple points
of interconnection with various interstate and intrastate pipelines, gathering
systems, and local distribution companies. The pipeline system is powered by
eight compressor stations having an aggregate of approximately 39,000
horsepower. Knight manages, maintains and operates TransColorado, for which it
is reimbursed at cost.

TransColorado
has the ability to flow gas south or north. TransColorado receives gas from one
coal seam natural gas treating plant located in the San Juan Basin of Colorado
and from pipeline, processing plant and gathering system interconnections
within the Paradox and Piceance Basins of western Colorado. Gas flowing south
through the pipeline moves onto the El Paso, Transwestern and Questar Southern
Trail pipeline systems. Gas moving north flows into the Colorado Interstate,
Wyoming Interstate and Questar pipeline systems at the Greasewood Hub and the
Rockies Express pipeline system at the Meeker Hub. TransColorado provides
transportation services to third-party natural gas producers, marketers,
gathering companies, local distribution companies and other shippers.

Pursuant
to transportation agreements and FERC tariff provisions, TransColorado offers
its customers firm and interruptible transportation and interruptible park and
loan services. For these services, TransColorado charges rates which include
the retention of fuel and gas lost and unaccounted for in-kind. Under
TransColorados tariffs, firm transportation customers pay reservation charges
each month plus a commodity charge based on actual volumes transported.
Interruptible transportation customers pay a commodity charge based upon actual
volumes transported. The underlying reservation and commodity charges are
assessed pursuant to a maximum recourse rate structure, which does not vary
based on the distance gas is transported. TransColorado has the authority to
negotiate rates with customers if it has first offered service to those
customers under its reservation and commodity charge rate structure.

TransColorados
approximately $50 million Blanco-Meeker Expansion Project was completed in the
fourth quarter of 2007 and placed into service on January 1, 2008. The project
boosted capacity on the pipeline by approximately 250 million cubic feet per
day of natural gas from the Blanco Hub area in San Juan County, New Mexico
through TransColorados existing pipeline for deliveries to the Rockies Express
Pipeline at an existing point of interconnection located at the Meeker Hub in
Rio Blanco County, Colorado. All of the incremental capacity is subscribed
under a long-term contract with ConocoPhillips.

Markets.
TransColorado acts principally as a feeder pipeline system from the developing
natural gas supply basins on the Western Slope of Colorado into the interstate
natural gas pipelines that lead away from the Blanco Hub area of New Mexico and
the interstate natural gas pipelines that lead away eastward from northwestern
Colorado and southwestern Wyoming. TransColorado is one of the largest
transporters of natural gas from the Western Slope supply basins of Colorado
and provides a competitively attractive outlet for that developing natural gas
resource. In 2007, TransColorado transported an average of approximately 734
million cubic feet per day of natural gas from these supply basins.

Supply.
During 2007, 94% of TransColorados transport business was with producers or their
own marketing affiliates, and 6% was with marketing companies and various gas
marketers. Approximately 64% of TransColorados transport business in 2007 was
conducted with its two largest customers. All of TransColorados southbound
pipeline capacity is committed under firm transportation contracts that extend
at least through year-end 2008. TransColorados pipeline capacity is 62%
subscribed during 2009 through 2012, and TransColorado is actively pursuing
contract extensions and or replacement contracts to increase firm subscription
levels beyond 2008.

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Competition.
TransColorado competes with other transporters
of natural gas in each of the natural gas supply basins it serves. These
competitors include both interstate and intrastate natural gas pipelines and
natural gas gathering systems. TransColorados shippers compete for market
share with shippers drawing upon gas production facilities within the New
Mexico portion of the San Juan Basin. TransColorado has phased its past
construction and expansion efforts to coincide with the ability of the interstate
pipeline grid at Blanco, New Mexico to accommodate greater natural gas volumes.
TransColorados transport concurrently ramped up over that period such that
TransColorado now enjoys a growing share of the outlet from the San Juan Basin
to the southwestern United States marketplace.

Historically,
the competition faced by TransColorado with respect to its natural gas
transportation services has generally been based upon the price differential
between the San Juan and Rocky Mountain basins. New pipelines servicing these
producing basins have had the effect of reducing that price differential;
however, given the growth in the Piceance and Paradox basins and the direct
accessibility of the TransColorado system to these basins, we believe that TransColorados
transport business to be sustainable and not significantly impacted by any new
entry of competition.

Rockies
Express Pipeline

We operate
and currently own 51% of the 1,679-mile Rockies Express Pipeline
system, which when fully completed, will be one of the largest natural gas
pipelines ever constructed in North America. The approximately $4.9 billion
project will have the capability to transport 1.8 billion cubic feet per day of
natural gas, and binding firm commitments have been secured for virtually all
of the pipeline capacity.

Our
ownership is through our 51% interest in West2East Pipeline LLC. the sole owner
of Rockies Express Pipeline LLC. Sempra Pipelines & Storage, a unit of
Sempra Energy, and ConocoPhillips hold the remaining ownership interests in the
Rockies Express project. We account for our investment under the equity method
of accounting due to the fact that our ownership interest will be reduced to
50% when construction of the entire project is completed. At that time, the
capital accounts of West2East Pipeline LLC will be trued up to reflect our 50%
economics in the project. We do not anticipate any additional changes in the
ownership structure of the project.

On
August 9, 2005, the FERC approved Rockies Express Pipeline LLCs application to
construct 327 miles of pipeline facilities in two phases. Phase I consisted of
the following two pipeline segments: (i) a 136-mile, 36-inch diameter pipeline
that extends from the Meeker Hub in Rio Blanco County, Colorado to the
Wamsutter Hub in Sweetwater County, Wyoming; and (ii) a 191-mile, 42-inch
diameter pipeline that extends from the Wamsutter Hub to the Cheyenne Hub in
Weld County, Colorado. Phase II of the project includes the construction of
three compressor stations referred to as the Meeker, Big Hole and Wamsutter
compressor stations. The Meeker and Wamsutter stations were completed and
placed in-service in January 2008. Construction of the Big Hole compressor
station is planned to commence in the second quarter of 2008, in order to meet
an expected in-service date of June 30, 2009.

On
April 19, 2007 the FERC issued a final order approving Rockies Express Pipeline
LLCs application for authorization to construct and operate certain facilities
comprising its proposed Rockies Express-West Project. This project is the first
planned segment extension of the Rockies Express Pipeline LLCs original
certificated facilities, and is comprised of approximately 713 miles of 42-inch
diameter pipeline extending eastward from the Cheyenne Hub to an
interconnection with Panhandle Eastern Pipe Line located in Audrain County,
Missouri. The segment extension transports approximately 1.5 billion cubic feet
per day of natural gas across the following five states: Wyoming, Colorado,
Nebraska, Kansas and Missouri and includes certain improvements to pre-existing
Rockies Express facilities located to the west of the Cheyenne Hub.
Construction of the Rockies Express-West project commenced on May 21, 2007, and
interim firm transportation service with capacity of approximately 1.4 billion
cubic feet per day began January 12, 2008. The entire project (Rockies
Express-West pipeline segment) is expected to become fully operational in
mid-March 2008.

On
April 30, 2007, Rockies Express Pipeline LLC filed an application with the FERC
requesting approval to construct and operate the REX-East Project, the third
segment of the Rockies Express pipeline system. The REX-East Project will be
comprised of approximately 639 miles of 42-inch diameter pipeline commencing
from the terminus of the Rockies Express-West pipeline in Audrain County,
Missouri to a terminus near the town of

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Clarington in
Monroe County, Ohio. The pipeline segment will be capable of transporting
approximately 1.8 billion cubic feet per day of natural gas. The FERC issued a
draft environmental report in late November 2007 for the REX-East Project, and
subject to receipt of regulatory approvals, the REX-East Project is expected to
begin partial service on December 31, 2008, and to be in full service in June
2009.

In
December 2007, Rockies Express Pipeline LLC completed a non-binding open season
undertaken to solicit market interest for the Northeast Express Project, a
375-mile extension and expansion of the Rockies Express pipeline system from
Clarington, Ohio, to Princeton, New Jersey. Significant expressions of interest
were received on the Northeast Express Project and negotiations with
prospective shippers to enter into binding commitments are currently underway.
Subject to receipt of sufficient binding commitments and regulatory approvals,
the Northeast Express Project would go into service in late 2010. When
complete, the Northeast Express Project would provide up to 1.8 billion cubic
feet of transportation capacity to northeast markets from the Lebanon Hub and
other pipeline receipt points between Lebanon, Ohio and Clarington, Ohio.

Markets. The
Rockies Express Pipeline is capable of
delivering gas to multiple markets along its pipeline system, primarily through
interconnects with other interstate pipeline companies and direct connects to
local distribution companies. Rockies Express Pipelines Zone 1 encompasses
receipts and deliveries of natural gas west of the Cheyenne Hub, located in
Northern Colorado near Cheyenne, Wyoming. Through the Zone 1 facilities,
Rockies Express can deliver gas to TransColorado Gas Transmission Company LLC
in northwestern Colorado, which can in turn transport the gas further south for
delivery into the San Juan Basin area. In Zone 1, Rockies Express Pipeline can
also deliver gas into western Wyoming through leased capacity on the Overthrust
Pipeline Company system, or through its interconnections with Colorado
Interstate Gas Company and Wyoming Interstate Company in southern Wyoming.
REX-West has the ability to deliver natural gas to points at the Cheyenne Hub,
which could be used in markets along the Front Range of Colorado, or could be
transported further east through either Rockies Express Pipelines Zone 2
facilities or other pipeline systems.

Rockies
Express Pipelines Zone 2 extends from the Cheyenne Hub to an interconnect with
the Panhandle Eastern Pipeline in Audrain County, Missouri. Through the Zone 2
facilities, Rockies Express facilitates the delivery of natural gas into the
Midcontinent area of the Unites States through various interconnects with other
major interstate pipelines in Nebraska (Northern Natural Gas Pipeline and
NGPL), Kansas (ANR Pipeline), and Missouri (Panhandle Eastern Pipeline).
Rockies Express Pipelines transportation capacity under interim service is
currently 1.4 billion cubic feet per day, and when this system is placed into
full service it will be capable of delivering 1.5 billion cubic feet per day
through these interconnects to the Midcontinent market.

Supply.
Rockies Express Pipeline directly accesses major
gas supply basins in western Colorado and western Wyoming. In western Colorado,
Rockies Express Pipeline has access to gas supply from the Uinta and Piceance
basins in eastern Utah and western Colorado. In western Wyoming, Rockies
Express Pipeline accesses the Green River Basin through its facilities that are
leased from Overthrust. With its connections to numerous other pipeline systems
along its route, Rockies Express Pipeline has access to almost all of the major
gas supply basins in Wyoming, Colorado and eastern Utah.

Competition.
Although there are some competitors to the
Rockies Express Pipeline system that provide a similar service, there are none
that can compete with the economy-of-scale that Rockies Express Pipeline
provides to its shippers to transport gas from the Rocky Mountain region to the
Midcontinent markets. The REX-East Project, noted above, will put the Rockies
Express Pipeline system in a very unique position of being the only pipeline
capable of offering a large volume of transportation service from Rocky
Mountain gas supply directly to customers in Ohio.

Rockies Express Pipeline could also experience competition for its
Rocky Mountain gas supply from both existing and proposed systems. Questar
Pipeline Company accesses many of the same basins as Rockies Express Pipeline
and transports gas to its markets in Utah and to other interconnects, which
have access to the California market. In addition, there are pipelines that are
proposed to use Rocky Mountain gas to supply markets on the West Coast.

22

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Kinder
Morgan Louisiana Pipeline

In September
2006, we filed an application with the FERC requesting approval to construct
and operate our Kinder Morgan Louisiana Pipeline. The natural gas pipeline
project is expected to cost approximately $510 million and will provide
approximately 3.2 billion cubic feet per day of take-away natural gas capacity
from the Cheniere Sabine Pass liquefied natural gas terminal located in Cameron
Parish, Louisiana. The project is supported by fully subscribed capacity and long-term customer commitments with
Chevron and Total.

The
Kinder Morgan Louisiana Pipeline will consist of two segments:

| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | a 132-mile,
 42-inch diameter pipeline with firm capacity of approximately 2.0 billion
 cubic feet per day of natural gas that will extend from the Sabine Pass
 terminal to a point of interconnection with an existing Columbia Gulf
 Transmission line in Evangeline Parish, Louisiana (an offshoot will consist
 of approximately 2.3 miles of 24-inch diameter pipeline with firm peak day
 capacity of approximately 300 million cubic feet per day extending away from
 the 42-inch diameter line to the existing Florida Gas Transmission Company
 compressor station in Acadia Parish, Louisiana). This segment is expected to
 be in service by January 1, 2009; and
| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               
| |  | a 1-mile,
 36-inch diameter pipeline with firm capacity of approximately 1.2 billion
 cubic feet per day that will extend from the Sabine Pass terminal and connect
 to NGPLs natural gas pipeline. This portion of the project is expected to be
 in service in the third quarter of 2008.                                                                                                                                                                                                                                                                                                                                                                                  

We
have designed and will construct the Kinder Morgan Louisiana Pipeline in a
manner that will minimize environmental impacts, and where possible, existing
pipeline corridors will be used to minimize impacts to communities and to the
environment. As of December 31, 2007, there were no major pipeline re-routes as
a result of any landowner requests.

Midcontinent
Express Pipeline LLC

On
October 9, 2007, Midcontinent Express Pipeline LLC filed an application with
the FERC requesting a certificate of public convenience and necessity that
would authorize construction and operation of the approximate 500-mile
Midcontinent Express Pipeline natural gas transmission system. We currently own
a 50% interest in Midcontinent Express Pipeline LLC and we account for our
investment under the equity method of accounting. Energy Transfer Partners,
L.P. owns the remaining 50% interest. The Midcontinent Express Pipeline will
create long-haul, firm natural gas transportation takeaway capacity, either
directly or indirectly, from natural gas producing regions located in Texas,
Oklahoma and Arkansas. The total project is expected to cost approximately $1.3
billion, and will have an initial transportation capacity of approximately 1.4
billion cubic feet per day of natural gas.

For
additional information regarding the Midcontinent Express Pipeline, see (a)
General Development of BusinessRecent Developments.

Casper
and Douglas Natural Gas Processing Systems

We own and
operate our Casper and Douglas, Wyoming natural gas processing plants, which
have the capacity to process up to 185 million cubic feet per day of natural
gas depending on raw gas quality.

Markets.
Casper and Douglas are processing plants
servicing gas streams flowing into KMIGT. Natural gas liquids processed by our
Casper plant are sold into local markets consisting primarily of retail propane
dealers and oil refiners. Natural gas liquids processed by our Douglas plant are
sold to ConocoPhillips via their Powder River natural gas liquids pipeline for
either ultimate consumption at the Borger refinery or for further disposition
to the natural gas liquids trading hubs located in Conway, Kansas and Mont
Belvieu, Texas.

Competition.Other regional facilities in the Greater Powder River
Basin include the Hilight plant (80 million cubic feet per day) owned and
operated by Anadarko, the Sage Creek plant (50 million cubic feet per day)
owned and operated by Merit Energy, and the Rawlins plant (230 million cubic
feet per day) owned and operated by El

23

---



Paso. Casper
and Douglas, however, are the only plants which provide straddle processing of
natural gas flowing into KMIGT.

Red
Cedar Gathering Company

We own a
49% equity interest in the Red Cedar Gathering Company, a joint venture
organized in August 1994 and referred to in this report as Red Cedar. The
remaining 51% interest in Red Cedar is owned by the Southern Ute Indian Tribe.
Red Cedar owns and operates natural gas gathering, compression and treating
facilities in the Ignacio Blanco Field in La Plata County, Colorado. The
Ignacio Blanco Field lies within the Colorado portion of the San Juan Basin,
most of which is located within the exterior boundaries of the Southern Ute
Indian Tribe Reservation. Red Cedar gathers coal seam and conventional natural
gas at wellheads and several central delivery points, for treating, compression
and delivery into any one of four major interstate natural gas pipeline systems
and an intrastate pipeline.

Red Cedar
also owns Coyote Gas Treating, LLC, referred to in this report as Coyote Gulch.
The sole asset owned by Coyote Gulch is a 250 million cubic feet per day
natural gas treating facility located in La Plata County, Colorado. The inlet
gas stream treated by Coyote Gulch contains an average carbon dioxide content
of between 12% and 13%. The plant treats the gas down to a carbon dioxide
concentration of 2% in order to meet interstate natural gas pipeline quality
specifications, and then compresses the natural gas into the TransColorado Gas
Transmission pipeline for transport to the Blanco, New Mexico-San Juan Basin
Hub.

Red Cedars
gas gathering system currently consists of over 1,100 miles of gathering
pipeline connecting more than 920 producing wells, 85,000 horsepower of
compression at 24 field compressor stations and two carbon dioxide treating
plants. The capacity and throughput of the Red Cedar system as currently
configured is approximately 750 million cubic feet per day of natural gas.

Thunder
Creek Gas Services, LLC

We own a
25% equity interest in Thunder Creek Gas Services, LLC, referred to in this
report as Thunder Creek. Devon Energy owns the remaining 75%. Thunder Creek
provides gathering, compression and treating services to a number of coal seam
gas producers in the Powder River Basin of Wyoming. Throughput volumes include
both coal seam and conventional plant residue gas.

Thunder
Creeks operations are a combination of mainline and low pressure gathering
assets. The mainline assets include 125 miles of mainline pipeline, 230 miles
of high and low pressure laterals, 26,635 horsepower of mainline compression
and carbon dioxide removal facilities consisting of a 220 million cubic feet
per day carbon dioxide treating plant complete with dehydration. The mainline
assets receive gas from 53 receipt points and can deliver treated gas to seven
delivery points including Colorado Interstate Gas, Wyoming Interstate Gas
Company, KMIGT and three power plants. The low pressure gathering assets
include five systems consisting of 194 miles of gathering pipeline and 35,329
horsepower of field compression.

CO2

Our CO2
segment consists of Kinder Morgan CO2 Company, L.P. and its
consolidated affiliates, referred to in this report as KMCO2. Carbon
dioxide is used in enhanced oil recovery projects as a flooding medium for
recovering crude oil from mature oil fields. Our carbon dioxide pipelines and
related assets allow us to market a complete package of carbon dioxide supply,
transportation and technical expertise to the customer. Together, our CO2
business segment produces, transports and markets carbon dioxide for use in
enhanced oil recovery operations. We also hold ownership
interests in several oil-producing fields and own a 450-mile crude oil
pipeline, all located in the Permian Basin region of West Texas.

Carbon
Dioxide Reserves

We own
approximately 45% of, and operate, the McElmo Dome unit in Colorado, which
contains more than nine trillion cubic feet of recoverable carbon dioxide.
Deliverability and compression capacity exceeds one billion cubic feet per day.
We are currently installing facilities and drilling 8 wells to increase the
production capacity from

24

---



McElmo Dome by approximately 200 million cubic feet per day. We also
own approximately 11% of the Bravo Dome unit in New Mexico, which contains more
than one trillion cubic feet of recoverable carbon dioxide and produces approximately
290 million cubic feet per day.

We also own
approximately 88% of the Doe Canyon Deep unit in Colorado, which contains more
than 1.5 trillion cubic feet of carbon dioxide. We have installed facilities
and drilled six wells to produce approximately 100 million cubic feet per day
of carbon dioxide beginning in January 2008.

Markets.Our principal
market for carbon dioxide is for injection into mature oil fields in the
Permian Basin, where industry demand is expected to grow modestly for
the next several years. We are exploring
additional potential markets, including enhanced oil recovery targets in
California, Wyoming, the Gulf Coast, Mexico, and Canada, and coal bed methane
production in the San Juan Basin of New Mexico.

Competition.Our primary
competitors for the sale of carbon dioxide include suppliers that have an
ownership interest in McElmo Dome, Bravo Dome and Sheep Mountain carbon dioxide
reserves, and Petro-Source Carbon Company, which gathers waste carbon dioxide
from natural gas production in the Val Verde Basin of West Texas. There is no
assurance that new carbon dioxide sources will not be discovered or developed,
which could compete with us or that new methodologies for enhanced oil recovery
will not replace carbon dioxide flooding.

Carbon
Dioxide Pipelines

As
a result of our 50% ownership interest in Cortez Pipeline Company, we own a 50%
equity interest in and operate the approximate 500-mile, Cortez pipeline. The
pipeline carries carbon dioxide from the McElmo Dome and Doe Canyon source
fields near Cortez, Colorado to the Denver City, Texas hub. The Cortez pipeline
currently transports over one billion cubic feet of carbon dioxide per day,
including approximately 99% of the carbon dioxide transported downstream on our
Central Basin pipeline and our Centerline pipeline. The tariffs charged by
Cortez Pipeline are not regulated.

Our Central
Basin pipeline consists of approximately 143 miles of pipe and 177 miles of
lateral supply lines located in the Permian Basin between Denver City, Texas
and McCamey, Texas with a throughput capacity of 600 million cubic feet per
day. At its origination point in Denver City, our Central Basin pipeline
interconnects with all three major carbon dioxide supply pipelines from
Colorado and New Mexico, namely the Cortez pipeline (operated by KMCO2)
and the Bravo and Sheep Mountain pipelines (operated by Oxy Permian). Central
Basins mainline terminates near McCamey where it interconnects with the Canyon
Reef Carriers pipeline and the Pecos pipeline. The tariffs charged by the
Central Basin pipeline are not regulated.

Our
Centerline pipeline consists of approximately 113 miles of pipe located in the
Permian Basin between Denver City, Texas and Snyder, Texas. The pipeline has a
capacity of 300 million cubic feet per day. The tariffs charged by the
Centerline pipeline are not regulated.

We own a
13% undivided interest in the 218-mile, Bravo pipeline, which delivers CO2 from
the Bravo Dome source field in northeast New Mexico to the Denver City hub and
has a capacity of more than 350 million cubic feet per day. Tariffs on the
Bravo pipeline are not regulated.

In
addition, we own approximately 98% of the Canyon Reef Carriers pipeline and
approximately 69% of the Pecos pipeline. The Canyon Reef Carriers pipeline
extends 139 miles from McCamey, Texas, to the SACROC unit. The pipeline has a
capacity of approximately 290 million cubic feet per day and makes deliveries
to the SACROC, Sharon Ridge, Cogdell and Reinecke units. The Pecos pipeline is
a 25-mile pipeline that runs from McCamey to Iraan, Texas. It has a capacity of
approximately 120 million cubic feet per day of carbon dioxide and makes
deliveries to the Yates unit. The tariffs charged on the Canyon Reef Carriers
and Pecos pipelines are not regulated.

Markets.
The principal market for transportation on our carbon dioxide pipelines is to
customers, including ourselves, using carbon dioxide for enhanced recovery
operations in mature oil fields in the Permian Basin, where industry demand is
expected to grow modestly for the next several years.

25

---



Competition.
Our ownership interests in the Central Basin,
Cortez and Bravo pipelines are in direct competition with other carbon dioxide
pipelines. We also compete with other interest owners in McElmo Dome and Bravo
Dome for transportation of carbon dioxide to the Denver City, Texas market
area.

Oil
Acreage and Wells

KMCO2
also holds ownership interests in oil-producing fields, including an
approximate 97% working interest in the SACROC unit, an approximate 50% working
interest in the Yates unit, a 21% net profits interest in the H.T. Boyd unit,
an approximate 65% working interest in the Claytonville unit, an approximate
95% working interest in the Katz CB Long unit, an approximate 64% working
interest in the Katz SW River unit, a 100% working interest in the Katz East
River unit, and lesser interests in the Sharon Ridge unit, the Reinecke unit
and the MidCross unit, all of which are located in the Permian Basin of West
Texas.

The SACROC
unit is one of the largest and oldest oil fields in the United States using
carbon dioxide flooding technology. The field is comprised of approximately
56,000 acres located in the Permian Basin in Scurry County, Texas. SACROC was
discovered in 1948 and has produced over 1.29 billion barrels of oil since
inception. It is estimated that SACROC originally held approximately 2.7
billion barrels of oil. We have expanded the development of the carbon dioxide
project initiated by the previous owners and increased production over the last
several years. The Yates unit is also one of the largest oil fields ever
discovered in the United States. It is estimated that it originally held more
than five billion barrels of oil, of which about 29% has been produced. The
field, discovered in 1926, is comprised of approximately 26,000 acres located
about 90 miles south of Midland, Texas.

As of
December 2007, the SACROC unit had 391 producing wells, and the purchased
carbon dioxide injection rate was 211 million cubic feet per day, down from an
average of 247 million cubic feet per day as of December 2006. The average oil
production rate for 2007 was approximately 27,600 barrels of oil per day, down
from an average of approximately 30,800 barrels of oil per day during 2006. The
average natural gas liquids production rate (net of the processing plant share)
for 2007 was approximately 6,300 barrels per day, an increase from an average
of approximately 5,700 barrels per day during 2006.

Our plan
has been to increase the production rate and ultimate oil recovery from Yates
by combining horizontal drilling with carbon dioxide injection to ensure a
relatively steady production profile over the next several years. We are
implementing our plan and as of December 2007, the Yates unit was producing
about 27,600 barrels of oil per day. As of December 2006, the Yates unit was
producing approximately 27,200 barrels of oil per day. Unlike our operations at
SACROC, where we use carbon dioxide and water to drive oil to the producing
wells, we are using carbon dioxide injection to replace nitrogen injection at
Yates in order to enhance the gravity drainage process, as well as to maintain
reservoir pressure. The differences in geology and reservoir mechanics between
the two fields mean that substantially less capital will be needed to develop
the reserves at Yates than is required at SACROC.

We
also operate and own an approximate 65% gross working interest in the
Claytonville oil field unit located in Fisher County, Texas. The Claytonville
unit is located nearly 30 miles east of the SACROC unit in the Permian Basin of
West Texas and is currently producing approximately 230 barrels of oil per day.
We are presently evaluating operating and subsurface technical data from the
Claytonville unit to further assess redevelopment opportunities including
carbon dioxide flood operations.

We
also operate and own working interests in the Katz CB Long unit, the Katz
Southwest River unit and Katz East River unit. The Katz field is located in the
Permian Basin area of West Texas and, as of December 2007, was producing
approximately 400 barrels of oil equivalent per day. We are presently
evaluating operating and subsurface technical data to further assess
redevelopment opportunities for the Katz field including the potential for
carbon dioxide flood operations.

The
following table sets forth productive wells, service wells and drilling wells
in the oil and gas fields in which we own interests as of December 31, 2007. When
used with respect to acres or wells, gross refers to the total acres or wells
in which we have a working interest; net refers to gross acres or wells multiplied,
in each case, by the percentage working interest owned by us:

26

---



|            |  |                       |       |                    |  |                     |  |     |       |       |  |     |  |  |   |  |  |   | 
|----------- |  | --------------------- | ----- | ------------------ |  | ------------------- |  | --- | ----- | ----- |  | --- |  |  | - |  |  | - | 
|            |  | Productive
 Wells (a) |       | Service
 Wells (b) |  | Drilling
 Wells (c) | 
|            |  |                       |       |                    |  |                     | 
|            |  | Gross                 |       | Net                |  | Gross               |  | Net |       | Gross |  | Net | 
|            |  |                       |       |                    |  |                     |  |     |       |       |  |     | 
|Crude Oil   |  |                       | 2,463 |                    |  | 1,587               |  |     | 1,066 |       |  | 789 |  |  | 2 |  |  | 2 | 
|Natural Gas |  |                       | 8     |                    |  | 4                   |  |     |      |       |  |    |  |  |  |  |  |  | 
|            |  |                       |       |                    |  |                     |  |     |       |       |  |     |  |  |   |  |  |   | 
|Total
Wells |  |                       | 2,471 |                    |  | 1,591               |  |     | 1,066 |       |  | 789 |  |  | 2 |  |  | 2 | 
|            |  |                       |       |                    |  |                     |  |     |       |       |  |     |  |  |   |  |  |   | 



---

|    |                                                                                                                                                                                                                                                                                                                  
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(a) | Includes active wells and
 wells temporarily shut-in. As of December 31, 2007, we did not operate any
 productive wells with multiple completions.                                                                                                                                                               
|    |                                                                                                                                                                                                                                                                                                                  
|(b) | Consists of injection,
 water supply, disposal wells and service wells temporarily shut-in. A
 disposal well is used
 for disposal of saltwater into an underground formation; a service well is a well drilled in a known
 oil field in order to inject liquids that enhance recovery or dispose of salt
 water.
|    |                                                                                                                                                                                                                                                                                                                  
|(c) | Consists of development
 wells in the process of being drilled as of December 31, 2007.A
 development well is a well drilled in an already discovered oil field.                                                                                                                                                 

The
oil and gas producing fields in which we own interests are located in the
Permian Basin area of West Texas. The following table reflects our net
productive and dry wells that were completed in each of the three years ended
December 31, 2007, 2006 and 2005:

|            |  |      |    |      |  |      |  |  |    | 
|----------- |  | ---- | -- | ---- |  | ---- |  |  | -- | 
|            |  | 2007 |    | 2006 |  | 2005 | 
|            |  |      |    |      |  |      | 
|Productive  |  |      |    |      |  |      |  |  |    | 
|Development |  |      | 31 |      |  | 37   |  |  | 42 | 
|Exploratory |  |      |   |      |  |     |  |  |   | 
|Dry         |  |      |    |      |  |      |  |  |    | 
|Development |  |      |   |      |  |     |  |  |   | 
|Exploratory |  |      |   |      |  |     |  |  |   | 
|            |  |      |    |      |  |      |  |  |    | 
|Total Wells |  |      | 31 |      |  | 37   |  |  | 42 | 
|            |  |      |    |      |  |      |  |  |    | 

|       |                                                                                                                                                                                                                                                                                                                                         
|------ | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Notes: | The
 above table includes wells
 that were completed during each year regardless of the year in which drilling
 was initiated, and does not include any wells where drilling operations were
 not completed as of the end of the applicable year. Development wells include
 wells drilled in the proved area of an oil or gas resevoir.

The
following table reflects the developed and undeveloped oil and gas acreage that
we held as of December 31, 2007:

|                  |  |       |        |     |  |        | 
|----------------- |  | ----- | ------ | --- |  | ------ | 
|                  |  | Gross |        | Net | 
|                  |  |       |        |     | 
|Developed Acres   |  |       | 72,435 |     |  | 67,731 | 
|Undeveloped Acres |  |       | 8,788  |     |  | 8,129  | 
|                  |  |       |        |     |  |        | 
|Total             |  |       | 81,223 |     |  | 75,860 | 
|                  |  |       |        |     |  |        | 

27

---



Operating
Statistics

Operating
statistics from our oil and gas producing activities for each of the years
2007, 2006 and 2005 are shown in the following table:

Results of Operations for Oil and Gas Producing
Activities  Unit Prices and Costs

|                                                          |  |                         |       |      |   |       |  |   |       | 
|--------------------------------------------------------- |  | ----------------------- | ----- | ---- | - | ----- |  | - | ----- | 
|                                                          |  | Year Ended December 31, |      
|                                                          |  |                         |      
|                                                          |  | 2007                    |       | 2006 |   | 2005  | 
|                                                          |  |                         |       |      |   |       |  |   |       | 
|Consolidated
  Companies(a)                               |  |                         |       |      |   |       |  |   |       | 
|Production
costs per barrel of oil equivalent(b)(c)(d)    |  | $                       | 16.22 |      | $ | 13.30 |  | $ | 10.00 | 
|                                                          |  |                         |       |      |   |       |  |   |       | 
|Crude oil
production (MBbl/d)                             |  |                         | 35.6  |      |   | 37.8  |  |   | 37.9  | 
|                                                          |  |                         |       |      |   |       |  |   |       | 
|Natural gas
liquids production (MBbl/d)(d)                |  |                         | 5.5   |      |   | 5.0   |  |   | 5.3   | 
|Natural gas
liquids production from gas plants(MBbl/d)(e) |  |                         | 4.1   |      |   | 3.9   |  |   | 4.1   | 
|                                                          |  |                         |       |      |   |       |  |   |       | 
|Total natural
gas liquids production(MBbl/d)              |  |                         | 9.6   |      |   | 8.9   |  |   | 9.4   | 
|                                                          |  |                         |       |      |   |       |  |   |       | 
|Natural gas
production (MMcf/d)(d)(f)                     |  |                         | 0.8   |      |   | 1.3   |  |   | 3.7   | 
|Natural gas
production from gas plants(MMcf/d)(e)(f)      |  |                         | 0.3   |      |   | 0.3   |  |   | 3.1   | 
|                                                          |  |                         |       |      |   |       |  |   |       | 
|Total natural
gas production(MMcf/d)(f)                   |  |                         | 1.1   |      |   | 1.6   |  |   | 6.8   | 
|                                                          |  |                         |       |      |   |       |  |   |       | 
|Average sales
prices including hedge gains/losses:        |  |                         |       |      |   |       |  |   |       | 
|Crude oil
price per Bbl(g)                                |  | $                       | 36.05 |      | $ | 31.42 |  | $ | 27.36 | 
|                                                          |  |                         |       |      |   |       |  |   |       | 
|Natural gas
liquids price per Bbl(g)                      |  | $                       | 52.22 |      | $ | 43.52 |  | $ | 38.79 | 
|                                                          |  |                         |       |      |   |       |  |   |       | 
|Natural gas
price per Mcf(h)                              |  | $                       | 6.08  |      | $ | 6.36  |  | $ | 5.84  | 
|                                                          |  |                         |       |      |   |       |  |   |       | 
|Total natural
gas liquids price per Bbl(e)                |  | $                       | 52.91 |      | $ | 43.90 |  | $ | 38.98 | 
|                                                          |  |                         |       |      |   |       |  |   |       | 
|Total natural
gas price per Mcf(e)                        |  | $                       | 5.89  |      | $ | 7.02  |  | $ | 5.80  | 
|                                                          |  |                         |       |      |   |       |  |   |       | 
|Average sales
prices excluding hedge gains/losses:        |  |                         |       |      |   |       |  |   |       | 
|Crude oil
price per Bbl(g)                                |  | $                       | 69.63 |      | $ | 63.27 |  | $ | 54.45 | 
|                                                          |  |                         |       |      |   |       |  |   |       | 
|Natural gas
liquids price per Bbl(g)                      |  | $                       | 52.22 |      | $ | 43.52 |  | $ | 38.79 | 
|                                                          |  |                         |       |      |   |       |  |   |       | 
|Natural gas
price per Mcf(h)                              |  | $                       | 6.08  |      | $ | 6.36  |  | $ | 5.84  | 
|                                                          |  |                         |       |      |   |       |  |   |       | 

|    |                                                                                                                                                                                                                                                                                            
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(a) | Amounts relate to Kinder
  Morgan CO2 Company, L.P.
  and its consolidated subsidaries.                                                                                                                                                                                                    
|    |                                                                                                                                                                                                                                                                                            
|(b) | Computed using production
  costs, excluding transportation costs, as defined by the United States
  Securities and Exchange Commisson. Natural gas volumes were converted to
  barrels of oil equivalent (BOE) using a conversion factor of six mcf of
  natural gas to one barrel of oil.
|    |                                                                                                                                                                                                                                                                                            
|(c) | Production costs include
  labor, repairs and maintenance, materials, supplies, fuel and power, property
  taxes, severance taxes, and general and administrative expenses directly
  related to oil and gas producing activities.                                                         
|    |                                                                                                                                                                                                                                                                                            
|(d) | Includes only production
  attributable to leasehold ownership.                                                                                                                                                                                                                            
|    |                                                                                                                                                                                                                                                                                            
|(e) | Includes production
  attributable to our ownership in processing plants and third party processing
  agreements.                                                                                                                                                                          
|    |                                                                                                                                                                                                                                                                                            
|(f) | Excludes natural gas
  production used as fuel.                                                                                                                                                                                                                                            
|    |                                                                                                                                                                                                                                                                                            
|(g) | Hedge gains/losses for
  crude oil and natural gas liquids are included with crude oil.                                                                                                                                                                                                    
|    |                                                                                                                                                                                                                                                                                            
|(h) | Natural gas sales were not
  hedged.                                                                                                                                                                                                                                                       

See
Note 20 to our consolidated financial statements included in this report for
additional information with respect to operating statistics and supplemental
information on our oil and gas producing activities.

Gas and Gasoline
Plant Interests

We
operate and own an approximate 22% working interest plus an additional 28% net
profits interest in the Snyder gasoline plant. We also operate and own a 51%
ownership interest in the Diamond M gas plant and a 100% ownership interest in
the North Snyder plant, all of which are located in the Permian Basin of West
Texas. The Snyder gasoline plant processes gas produced from the SACROC unit
and neighboring carbon dioxide projects, specifically the Sharon Ridge and
Cogdell units, all of which are located in the Permian Basin area of West
Texas. The Diamond M and the North Snyder plants contract with the Snyder plant
to process gas. Production of natural gas liquids at the Snyder gasoline plant
as of December 2007 was approximately 15,500 barrels per day as compared to
15,000 barrels per day as of December 2006.

Crude
Oil Pipeline

We
own our Kinder Morgan Wink Pipeline, a 450-mile Texas intrastate crude oil
pipeline system consisting of three mainline sections, two gathering systems
and numerous truck delivery stations. The segment that runs from Wink to El
Paso has a total capacity of 130,000 barrels of crude oil per day. The pipeline
allows us to better manage crude oil deliveries from our oil field interests in
West Texas, and we have entered into a long-term throughput

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agreement with
Western Refining Company, L.P. to transport crude oil into Westerns 120,000
barrel per day refinery in El Paso. The 20-inch pipeline segment transported
approximately119,000 barrels of
oil per day in 2007. The Kinder Morgan Wink Pipeline is regulated by both the
FERC and the Texas Railroad Commission.

Terminals

Our
Terminals segment includes the operations of our petroleum, chemical and other
liquids terminal facilities (other than those included in our Products
Pipelines segment) and all of our coal, petroleum coke, fertilizer, steel, ores
and dry-bulk material services, including all transload, engineering, conveying
and other in-plant services. Combined, the segment is composed of approximately100 owned or operated liquids and bulk
terminal facilities, and more than 45 rail transloading and materials handling
facilities located throughout the United States, Canada and the Netherlands. In
2007, the number of customers from whom our Terminals segment received more
than $0.1 million of revenue was approximately 650.

Liquids
Terminals

Our
liquids terminals operations primarily store refined petroleum products,
petrochemicals, industrial chemicals and vegetable oil products in aboveground
storage tanks and transfer products to and from pipelines, vessels, tank
trucks, tank barges, and tank railcars. Combined, our liquids terminals
facilities possess liquids storage capacity of approximately 47.5 million
barrels, and in 2007, these terminals handled approximately 557 million barrels
of petroleum, chemicals and vegetable oil products.

In
September 2006, we announced major expansions at our Pasadena and Galena Park,
Texas terminal facilities. The expansions will provide additional
infrastructure to help meet the growing need for refined petroleum products
storage capacity along the Gulf Coast. The investment of approximately $195
million includes the construction of the following: (i) new storage tanks at
both our Pasadena and Galena Park terminals; (ii) an additional cross-channel
pipeline to increase the connectivity between the two terminals; (iii) a new
ship dock at Galena Park; and (iv) an additional loading bay at our fully
automated truck loading rack located at our Pasadena terminal. The expansions
are supported by long-term customer commitments and will result in
approximately 3.4 million barrels of additional tank storage capacity at the
two terminals. Construction began in October 2006, and all of the projects are
expected to be completed by the spring of 2008, with the exception of the of
the Galena Park ship dock which is now scheduled to be in-service by the third
quarter of 2008.

At
Perth Amboy, New Jersey, we completed construction and placed into service nine
new storage tanks with a capacity of 1.4 million barrels for gasoline, diesel
and jet fuel. These tanks have been leased on a long-term basis to two
customers. Our total investment in these facilities was approximately $69
million.

In
June 2006, we announced the construction of a new crude oil tank farm located
in Edmonton, Alberta, Canada, and long-term contracts with customers for all of
the available capacity at the facility. Situated on approximately 24 acres, the
new storage facility will have nine tanks with a combined storage capacity of
approximately 2.2 million barrels for crude oil. Service is expected to begin
in the first quarter of 2008, and when completed, the tank farm will serve as a
premier blending and storage hub for Canadian crude oil. Originally estimated
at $115 million, due primarily to additional labor costs, total investment in
this tank farm is projected to be $162 million on a constant U.S. dollar basis.
The tank farm will have access to more than 20 incoming pipelines and several
major outbound systems, including a connection with our Trans Mountain pipeline
system, which currently transports up to 260,000 barrels per day of heavy crude
oil and refined products from Edmonton to marketing terminals and refineries located
in the greater Vancouver, British Columbia area and Puget Sound in Washington
state.

Competition.
We are one of the largest independent operators of liquids terminals in North
America. Our primary competitors are IMTT, Magellan, Morgan Stanley, NuStar,
Oil Tanking, Teppco, and Vopak.

Bulk
Terminals

Our
bulk terminal operations primarily involve dry-bulk material handling services;
however, we also provide conveyor manufacturing and installation, engineering
and design services and in-plant services covering material

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handling,
conveying, maintenance and repair, railcar switching and miscellaneous marine
services. Combined, our dry-bulk and material transloading facilities handled
approximately 87.1 million tons of coal, petroleum coke, fertilizers, steel,
ores and other dry-bulk materials in 2007. We own or operate approximately 93
dry-bulk terminals in the United States, Canada and the Netherlands.

In
May 2007, we purchased certain buildings and equipment and completed a 40 year
agreement to operate Vancouver Wharves, a bulk marine terminal located at the
entrance to the Port of Vancouver, British Columbia. The facility consists of
five vessel berths situated on a 139-acre site, extensive rail infrastructure,
dry-bulk and liquid storage, and material handling systems, which allow the
terminal to handle over 3.5 million tons of cargo annually.  Vancouver Wharves has access to three major
rail carriers connecting to shippers in western and central Canada and the U.S.
Pacific Northwest. Vancouver Wharves offers a variety of inbound, outbound and
value-added services for mineral concentrates, wood products, agri-products and
sulfur. In addition to the aggregate consideration of approximately $57.2
million ($38.8 million in cash and the assumption of $18.4 million of assumed
liabilities) paid for this facility, we plan to invest an additional $46
million at Vancouver Wharves over the next two years to upgrade and relocate
certain rail track and transloading systems, buildings and a shiploader.

Effective
September 1, 2007, we purchased the assets of Marine Terminals, Inc. for an
aggregate consideration of approximately $101.5 million. Combined, the assets
handle approximately 13.5 million tons of alloys and steel products annually
from five facilities located in the southeast United States. These
strategically located terminals provide handling, processing, harboring and
warehousing services primarily to Nucor Corporation, one of the largest steel
and steel products companies in the world, under long-term contracts.

Competition.
Our bulk terminals compete with numerous independent terminal operators, other
terminals owned by oil companies, stevedoring companies, and other industrials
opting not to outsource terminal services. Many of our bulk terminals were
constructed pursuant to long-term contracts for specific customers. As a
result, we believe other terminal operators would face a significant
disadvantage in competing for this business.

Materials
Services (rail transloading)

Our
materials services operations include rail or truck transloading operations
conducted at 45 owned and non-owned facilities. The Burlington Northern Santa
Fe, CSX, Norfolk Southern, Union Pacific, Kansas City Southern and A&W
railroads provide rail service for these terminal facilities. Approximately 50%
of the products handled are liquids, including an entire spectrum of liquid
chemicals, and 50% are dry-bulk products. Many of the facilities are equipped
for bi-modal operation (rail-to-truck, and truck-to-rail) or connect via
pipeline to storage facilities. Several facilities provide railcar storage
services. We also design and build transloading facilities, perform inventory
management services, and provide value-added services such as blending, heating
and sparging. In 2007, our materials services operations handled approximately
347,000 railcars.

CompetitionOur material services operations compete with a variety of national transload
and terminal operators across the United States, including Savage Services,
Watco and Bulk Plus Logistics. Additionally, single or multi-site terminal
operators are often entrenched in the network of Class 1 rail carriers.

Trans
Mountain

Our
Trans Mountain common carrier pipeline system originates at Edmonton, Alberta
and transports crude oil and refined petroleum to destinations in the interior
and on the west coast of British Columbia. A connecting pipeline owned by us
delivers petroleum to refineries in the state of Washington.

Trans
Mountains pipeline is 715 miles. The capacity of the line out of Edmonton
ranges from 260,000 barrels per day when heavy crude represents 20% of the
total throughput to 300,000 barrels per day with no heavy crude. The pipeline
system utilizes 21 pump stations controlled by a centralized computer control
system.

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Trans
Mountain also operates a 5.3 mile spur line from its Sumas Pump Station to the
U.S.  Canada international border where it connects with a 63 mile pipeline
system owned and operated by us. The pipeline system in Washington State has a
sustainable throughput capacity of approximately 135,000 barrels per day when
heavy crude represents approximately 25% of throughput and connects to four
refineries located in northwestern Washington State. The volumes of petroleum
shipped to Washington State fluctuate in response to the price levels of
Canadian crude oil in relation to petroleum produced in Alaska and other
offshore sources.

In
2007, deliveries on Trans Mountain averaged 258,540 barrels per day. This was
an increase of 13% from average 2006 deliveries of 229,369 barrels per day. In
April 2007, we commissioned ten new pump stations that boosted capacity on
Trans Mountain from 225,000 to approximately 260,000 barrels per day. The crude
oil and refined petroleum transported through Trans Mountains pipeline system
originates in Alberta and British Columbia. The refined and partially refined
petroleum transported to Kamloops, British Columbia and Vancouver originates
from oil refineries located in Edmonton. Petroleum products delivered through
Trans Mountains pipeline system are used in markets in British Columbia,
Washington State and elsewhere.

Overall
Alberta crude oil supply has been increasing steadily over the past few years
as a result of significant oilsands development with projects led by Shell
Canada, Suncor Energy and Syncrude Canada. Further development is expected to
continue into the future with expansions to existing oilsands production
facilities as well as with new projects. In its moderate growth case, the
Canadian Association of Petroleum Producers (CAPP) forecasts Western Canadian
crude oil production to increase by over 1.6 million barrels per day by 2015.
This increasing supply will likely result in constrained export pipeline
capacity from Western Canada, which supports Trans Mountains view that both
the demand for transportation services provided by Trans Mountains pipeline
and the supply of crude oil will remain strong for the foreseeable future.

Shipments
of refined petroleum represent a significant portion of Trans Mountains
throughput. In 2007, shipments of
refined petroleum and iso-octane represented 25% of throughput, as compared
with 28% in 2006.

Major
Customers

Our
total operating revenues are derived from a wide customer base.For each of the years ended December 31,
2007, 2006 and 2005, no revenues from transactions with a single external
customer accounted for 10% or more of our total consolidated revenues. Our
Texas intrastate natural gas pipeline group buys and sells significant volumes of natural gas within the state of Texas and,
to a far lesser extent, our CO2 business segment also sells natural gas.
Combined, total revenues from the sales
of natural gas from our Natural Gas Pipelines and CO2 business segments
in 2007, 2006 and 2005 accounted for 63.3%, 66.8% and 73.9%, respectively, of
our total consolidated revenues.

As
a result of our Texas intrastate group selling natural gas in the same price
environment in which it is purchased, both our total consolidated revenues and
our total consolidated purchases (cost of sales) increase considerably due to
the inclusion of the cost of gas in both financial statement line items.
However, these higher revenues and higher purchased gas costs do not
necessarily translate into increased margins in comparison to those situations
in which we charge a fee to transport gas owned by others as we seek to match
the purchase and sales indexes and lock in a transport fee. We do not believe
that a loss of revenues from any single customer would have a material adverse
effect on our business, financial position, results of operations or cash
flows.

Regulation

Interstate Common Carrier Pipeline Rate
Regulation  U.S. Operations

Some
of our pipelines are interstate common carrier pipelines, subject to regulation
by the FERC under the Interstate Commerce Act, or ICA. The ICA requires that we
maintain our tariffs on file with the FERC, which tariffs set forth the rates
we charge for providing transportation services on our interstate common
carrier pipelines as well as the rules and regulations governing these
services. The ICA requires, among other things, that such rates on interstate
common carrier pipelines be just and reasonable and nondiscriminatory. The
ICA permits interested persons to challenge newly proposed or changed rates and
authorizes the FERC to suspend the effectiveness of such rates for a period of
up to seven months and to investigate such rates. If, upon completion of an
investigation, the

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FERC finds
that the new or changed rate is unlawful, it is authorized to require the
carrier to refund the revenues in excess of the prior tariff collected during
the pendency of the investigation. The FERC may also investigate, upon
complaint or on its own motion, rates that are already in effect and may order
a carrier to change its rates prospectively. Upon an appropriate showing, a
shipper may obtain reparations for damages sustained during the two years prior
to the filing of a complaint.

On
October 24, 1992, Congress passed the Energy Policy Act of 1992. The Energy
Policy Act deemed petroleum products pipeline tariff rates that were in effect
for the 365-day period ending on the date of enactment or that were in effect
on the 365th day preceding enactment and had not been subject to complaint,
protest or investigation during the 365-day period to be just and reasonable or
grandfathered under the ICA. The Energy Policy Act also limited the
circumstances under which a complaint can be made against such grandfathered
rates. The rates we charged for transportation service on our Cypress Pipeline
were not suspended or subject to protest or complaint during the relevant
365-day period established by the Energy Policy Act. For this reason, we believe
these rates should be grandfathered under the Energy Policy Act. Certain rates
on our Pacific operations pipeline system were subject to protest during
the 365-day period established by the Energy Policy Act. Accordingly, certain of
the Pacific pipelines rates have been, and continue to be, subject to
complaints with the FERC, as is more fully described in Note 16 to our
consolidated financial statements included elsewhere in this report.

Petroleum
products pipelines may change their rates within prescribed ceiling levels that
are tied to an inflation index. Shippers may protest rate increases made within
the ceiling levels, but such protests must show that the portion of the rate
increase resulting from application of the index is substantially in excess of
the pipelines increase in costs from the previous year. A pipeline must, as a
general rule, utilize the indexing methodology to change its rates. The FERC,
however, uses cost-of-service ratemaking, market-based rates and settlement
rates as alternatives to the indexing approach in certain specified circumstances.

Common
Carrier Pipeline Rate Regulation  Canadian Operations

The
Canadian portion of our crude oil and refined petroleum products pipeline
system is under the regulatory jurisdiction of Canadas National Energy Board,
referred to in this report as the NEB. The National Energy Board Act gives the
NEB power to authorize pipeline construction and to establish tolls and
conditions of service. In November 2004, Trans Mountain entered into
negotiations with the Canadian Association of Petroleum Producers and principal
shippers for a new incentive toll settlement to be effective for the period
starting January 1, 2006 and ending December 31, 2010. In January 2006, Trans
Mountain reached agreement in principle, which was reduced to a memorandum of
understanding for the 2006 toll settlement. A final agreement was reached with
the Canadian Association of Petroleum Producers in October 2006 and NEB
approval was received in November 2006.

The
2006 toll settlement incorporates an incentive toll mechanism that is intended
to provide Trans Mountain with the opportunity to earn a return on equity
greater than that calculated using the formula established by the NEB. In
return for this opportunity, Trans Mountain has agreed to assume certain risks
and provide cost certainty in certain areas. Part of the incentive toll
mechanism specifies that Trans Mountain is allowed to keep 75% of the net
revenue generated by throughput in excess of 92.5% of the capacity of the
pipeline. The 2006 incentive toll settlement provides for base tolls which
will, other than recalculation or adjustment in certain specified
circumstances, remain in effect for the five-year period. The toll settlement
also governs the financial arrangements for the approximately C$638 million
expansions to Trans Mountain that will add 75,000 barrels per day of incremental
capacity to the system by November 2008. The toll charged for the portion of Trans Mountains pipeline system located in the United States
falls under the jurisdiction of the FERC. See Interstate Common Carrier
Pipeline Rate Regulation  U.S. Operations.

Interstate
Natural Gas Transportation and Storage Regulation

Both
the performance of and rates charged by companies performing interstate natural
gas transportation and storage services are regulated by the FERC under the
Natural Gas Act of 1938 and, to a lesser extent, the Natural Gas Policy Act of
1978. Beginning in the mid-1980s, the FERC initiated a number of regulatory
changes intended to create a more competitive environment in the natural gas
marketplace. Among the most important of these changes were:

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|  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                
|- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | Order
  No. 436 (1985) requiring open-access, nondiscriminatory transportation of
  natural gas;                                                                                                                                                                                                                                                                                                                                                                               
|  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                
| | Order
  No. 497 (1988) which set forth new standards and guidelines imposing certain
  constraints on the interaction between
   interstate
  natural gas pipelines and their marketing affiliates and imposing certain
  disclosure requirements regarding that
  interaction; and                                                                                                                                                                                            
|  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                
| | Order
  No. 636 (1992) which required interstate natural gas pipelines that perform
  open-access transportation under blanket
  certificates to
  unbundle or separate their traditional merchant sales services from their
  transportation and storage
  services and to
  provide comparable transportation and storage services with respect to all
  natural gas supplies whether purchased
  from the pipeline or from other merchants such as marketers or producers.

Natural
gas pipelines must now separately state the applicable rates for each unbundled
service they provide (i.e., for the natural gas commodity, transportation and
storage). Order 636 contains a number of procedures designed to increase
competition in the interstate natural gas industry, including: (i) requiring
the unbundling of sales services from other services; (ii) permitting holders
of firm capacity on interstate natural gas pipelines to release all or a part
of their capacity for resale by the pipeline; and (iii) the issuance of blanket
sales certificates to interstate pipelines for unbundled services. Order 636
has been affirmed in all material respects upon judicial review, and our own
FERC orders approving our unbundling plans are final and not subject to any
pending judicial review.

On
November 25, 2003, the FERC issued Order No. 2004, adopting revised Standards
of Conduct that apply uniformly to interstate natural gas pipelines and public
utilities. In light of the changing structure of the energy industry, these
Standards of Conduct govern relationships between regulated interstate natural
gas pipelines and all of their energy affiliates. These new Standards of
Conduct were designed to eliminate the loophole in the previous regulations
that did not cover an interstate natural gas pipelines relationship with
energy affiliates that are not marketers. The rule is designed to prevent
interstate natural gas pipelines from giving an undue preference to any of
their energy affiliates and to ensure that transmission is provided on a
nondiscriminatory basis. In addition, unlike the prior regulations, these
requirements apply even if the energy affiliate is not a customer of its
affiliated interstate pipeline. Our interstate natural gas pipelines are in
compliance with these Standards of Conduct.

On
November 17, 2006, the United States Court of Appeals for the District of
Columbia Circuit vacated Order No. 2004, as applied to natural gas pipelines,
and remanded the Order back to the FERC. On January 9, 2007, the FERC issued an
interim rule regarding standards of conduct in Order 690 to be effective
immediately. The interim rule repromulgated the standards of conduct that were
not challenged before the court. On January 18, 2007, the FERC issued a notice
of proposed rulemaking soliciting comments on whether or not the interim rule
should be made permanent for natural gas transmission providers.

Please
refer to Note 17 to our consolidated financial statements included elsewhere in
this report for additional information regarding FERC Order No. 2004 and other
Standards of Conduct rulemaking.

On August 8,
2005, Congress enacted the Energy Policy Act of 2005. The Energy Policy Act,
among other things, amended the Natural Gas Act to prohibit market manipulation
by any entity, directed the FERC to facilitate market transparency in the
market for sale or transportation of physical natural gas in interstate
commerce, and significantly increased the penalties for violations of the
Natural Gas Act, the Natural Gas Policy Act of 1978, or FERC rules, regulations
or orders thereunder.

California
Public Utilities Commission Rate Regulation

The
intrastate common carrier operations of our Pacific operations pipelines in
California are subject to regulation by the California Public Utilities
Commission, referred to in this report as the CPUC, under a depreciated book
plant methodology, which is based on an original cost measure of investment.
Intrastate tariffs filed by us with the CPUC have been established on the basis
of revenues, expenses and investments allocated as applicable to the California
intrastate portion of our Pacific operations business. Tariff rates with
respect to intrastate pipeline service in California are subject to challenge
by complaint by interested parties or by independent action of the CPUC. A
variety of factors can affect the rates of return permitted by the CPUC, and
certain other issues similar to those which have arisen with respect to our
FERC regulated rates could also arise with respect to

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our intrastate
rates. Certain of our Pacific operations pipeline rates have been, and
continue to be, subject to complaints with the CPUC, as is more fully described
in Note 16 to our consolidated financial statements included elsewhere in this
report.

Texas
Railroad Commission Rate Regulation

The
intrastate common carrier operations of our natural gas and crude oil pipelines
in Texas are subject to certain regulation with respect to such intrastate
transportation by the Texas Railroad Commission. Although the Texas Railroad
Commission has the authority to regulate our rates, the Commission has
generally not investigated the rates or practices of our intrastate pipelines
in the absence of shipper complaints.

Safety
Regulation

Our
interstate pipelines are subject to regulation by the United States Department
of Transportation, referred to in this report as U.S. DOT, and our intrastate pipelines
and other operations are subject to comparable state regulations with respect
to their design, installation, testing, construction, operation, replacement
and management. Comparable regulation exists in some states in which we conduct
pipeline operations. In addition, our truck and terminal loading facilities are
subject to U.S. DOT regulations dealing with the transportation of hazardous
materials by motor vehicles and railcars. We believe that we are in substantial
compliance with U.S. DOT and comparable state regulations.

The
Pipeline Safety Improvement Act of 2002 provides guidelines in the areas of
testing, education, training and communication. The Pipeline Safety Act
requires pipeline companies to perform integrity tests on natural gas
transmission pipelines that exist in high population density areas that are
designated as High Consequence Areas. Testing consists of hydrostatic testing,
internal magnetic flux or ultrasonic testing, or direct assessment of the
piping. In addition to the pipeline integrity tests, pipeline companies must
implement a qualification program to make certain that employees are properly
trained. The U.S. DOT has approved our qualification program. We believe that
we are in substantial compliance with this laws requirements and have
integrated appropriate aspects of this pipeline safety law into our internal
Operator Qualification Program. A similar integrity management rule for refined
petroleum products pipelines became effective May 29, 2001.

We
are also subject to the requirements of the Federal Occupational Safety and
Health Act and other comparable federal and state statutes. We believe that we
are in substantial compliance with Federal OSHA requirements, including general
industry standards, recordkeeping requirements and monitoring of occupational
exposure to hazardous substances.

In
general, we expect to increase expenditures in the future to comply with higher
industry and regulatory safety standards. Some of these changes, such as U.S.
DOT implementation of additional hydrostatic testing requirements, could
significantly increase the amount of these expenditures. Such increases in our
expenditures cannot be accurately estimated at this time.

State
and Local Regulation

Our
activities are subject to various state and local laws and regulations, as well
as orders of regulatory bodies, governing a wide variety of matters, including
marketing, production, pricing, pollution, protection of the environment, and
safety.

Environmental Matters

Our
operations are subject to federal, state and local, and some foreign laws and
regulations governing the release of regulated materials into the environment
or otherwise relating to environmental protection or human health or safety. We
believe that our operations are in substantial compliance with applicable
environmental laws and regulations.

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We
accrue liabilities for environmental matters when it is probable that
obligations have been incurred and the amounts can be reasonably estimated.
This policy applies to assets or businesses currently owned or previously
disposed. We have accrued liabilities for probable environmental remediation
obligations at various sites, including multiparty sites where the U.S.
Environmental Protection Agency has identified us as one of the potentially
responsible parties. The involvement of other financially responsible companies
at these multiparty sites could mitigate our actual joint and several liability
exposures. Although no assurance can be given, we believe that the ultimate
resolution of all these environmental matters will not have a material adverse
effect on our business, financial position or results of operations. We have
accrued an environmental reserve in the amount of $92.0 million as of December
31, 2007. Our reserve estimates range in value from approximately $92.0 million
to approximately $142.7 million, and we recorded our liability equal to the low
end of the range, as we did not identify any amounts within the range as a
better estimate of the liability. For additional information related to
environmental matters, see Note 16 to our consolidated financial statements
included elsewhere in this report.

Solid
Waste

We
generate both hazardous and non-hazardous solid wastes that are subject to the
requirements of the Federal Resource Conservation and Recovery Act and
comparable state statutes. From time to time, state regulators and the United
States Environmental Protection Agency consider the adoption of stricter
disposal standards for non-hazardous waste. Furthermore, it is possible that
some wastes that are currently classified as non-hazardous, which could include
wastes currently generated during pipeline or liquids or bulk terminal operations,
may in the future be designated as hazardous wastes. Hazardous wastes are
subject to more rigorous and costly disposal requirements than non-hazardous
wastes. Such changes in the regulations may result in additional capital
expenditures or operating expenses for us.

Superfund

The
Comprehensive Environmental Response, Compensation and Liability Act, also
known as the Superfund law or CERCLA, and analogous state laws, impose
joint and several liability, without regard to fault or the legality of the
original conduct, on certain classes of potentially responsible persons for
releases of hazardous substances into the environment. These persons include
the owner or operator of a site and companies that disposed or arranged for the
disposal of the hazardous substances found at the site. CERCLA authorizes the
U.S. EPA and, in some cases, third parties to take actions in response to
threats to the public health or the environment and to seek to recover from the
responsible classes of persons the costs they incur, in addition to
compensation for natural resource damages, if any. Although petroleum is
excluded from CERCLAs definition of a hazardous substance, in the course of
our ordinary operations, we have and will generate materials that may fall
within the definition of hazardous substance. By operation of law, if we are
determined to be a potentially responsible person, we may be responsible under
CERCLA for all or part of the costs required to clean up sites at which such
materials are present, in addition to compensation for natural resource
damages, if any.

Clean
Air Act

Our
operations are subject to the Clean Air Act, as amended, and analogous state
statutes. We believe that the operations of our pipelines, storage facilities
and terminals are in substantial compliance with such statutes. The Clean Air
Act, as amended, contains lengthy, complex provisions that may result in the
imposition over the next several years of certain pollution control requirements
with respect to air emissions from the operations of our pipelines, treating
facilities, storage facilities and terminals. Depending on the nature of those
requirements and any additional requirements that may be imposed by state and
local regulatory authorities, we may be required to incur certain capital and
operating expenditures over the next several years for air pollution control
equipment in connection with maintaining or obtaining operating permits and
approvals and addressing other air emission-related issues.

Due
to the broad scope and complexity of the issues involved and the resultant
complexity and nature of the regulations, full development and implementation
of many Clean Air Act regulations by the U.S. EPA and/or various state and
local regulators have been delayed. Therefore, until such time as the new Clean
Air Act requirements are implemented, we are unable to fully estimate the
effect on earnings or operations or the amount

35

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and timing of
such required capital expenditures. At this time, however, we do not believe
that we will be materially adversely affected by any such requirements.

Clean
Water Act

Our
operations can result in the discharge of pollutants. The Federal Water
Pollution Control Act of 1972, as amended, also known as the Clean Water Act,
and analogous state laws impose restrictions and controls regarding the
discharge of pollutants into state waters or waters of the United States. The
discharge of pollutants into regulated waters is prohibited, except in
accordance with the terms of a permit issued by applicable federal or state
authorities. The Oil Pollution Act was enacted in 1990 and amends provisions of
the Clean Water Act as they pertain to prevention and response to oil spills.
Spill prevention control and countermeasure requirements of the Clean Water Act
and some state laws require containment and similar structures to help prevent
contamination of navigable waters in the event of an overflow or release. We
believe we are in substantial compliance with these laws.

Other

KMGP
Services Company, Inc., Knight and Kinder Morgan Canada Inc. employ all persons
necessary for the operation of our business. Generally, we reimburse these
entities for the services of their employees. As of December 31, 2007, KMGP
Services Company, Inc., Knight and Kinder Morgan Canada Inc. had, in the
aggregate, approximately 7,600 full-time employees. Approximately 920 full-time
hourly personnel at certain terminals and pipelines are represented by labor
unions under collective bargaining agreements that expire between 2008 and
2012. KMGP Services Company, Inc., Knight and Kinder Morgan Canada Inc. each
consider relations with their employees to be good. For more information on our
related party transactions, see Note 12 of the notes to our consolidated
financial statements included elsewhere in this report.

We
believe that we have generally satisfactory title to the properties we own and
use in our businesses, subject to liens for current taxes, liens incident to
minor encumbrances, and easements and restrictions, which do not materially
detract from the value of such property or the interests in those properties or
the use of such properties in our businesses. We generally do not own the land
on which our pipelines are constructed. Instead, we obtain the right to
construct and operate the pipelines on other peoples land for a period of
time. Substantially all of our pipelines are constructed on rights-of-way
granted by the apparent record owners of such property. In many instances,
lands over which rights-of-way have been obtained are subject to prior liens,
which have not been subordinated to the right-of-way grants. In some cases, not
all of the apparent record owners have joined in the right-of-way grants, but
in substantially all such cases, signatures of the owners of majority interests
have been obtained. Permits have been obtained from public authorities to cross
over or under, or to lay facilities in or along, water courses, county roads,
municipal streets and state highways, and in some instances, such permits are
revocable at the election of the grantor, or, the pipeline may be required to
move its facilities at its own expense. Permits have also been obtained from
railroad companies to cross over or under lands or rights-of-way, many of which
are also revocable at the grantor's election. Some such permits require annual
or other periodic payments. In a few minor cases, property for pipeline
purposes was purchased in fee.

(d) Financial Information about
Geographic Areas

For
geographic information concerning our assets and operations, see Note 15 to our
consolidated financial statements.

(e)
Available Information

We make
available free of charge on or through our Internet website, at
www.kindermorgan.com, our annual report on Form 10-K, quarterly reports on Form
10-Q, current reports on Form 8-K, and amendments to those reports filed or
furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of
1934 as soon as reasonably practicable after we electronically file such
material with, or furnish it to, the Securities and Exchange Commission.

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Item 1A. Risk Factors.

You
should carefully consider the risks described below, in addition to the other
information contained in this document. Realization of any of the following
risks could have a material adverse effect on our business, financial
condition, cash flows and results of operations. There are also risks
associated with being an owner of common units in a partnership that are
different than being an owner of common stock in a corporation. Investors in
our common units must be aware that the realization of any of those risks could
result in a decline in the trading price of our common units, and they might
lose all or part of their investment.

Risks
Related to Our Business

Pending
Federal Energy Regulatory Commission and California Public Utilities Commission
proceedings seek substantial refunds and reductions in tariff rates on some of
our pipelines. If the proceedings are determined adversely to us, they could
have a material adverse impact on us.

Regulators
and shippers on our pipelines have rights to challenge the rates we charge
under certain circumstances prescribed by applicable regulations. Some shippers
on our pipelines have filed complaints with the Federal Energy Regulatory
Commission and California Public Utilities Commission that seek substantial
refunds for alleged overcharges during the years in question and prospective
reductions in the tariff rates on our Pacific operations pipeline system. We
may face challenges, similar to those described in Note 16 to our consolidated
financial statements included elsewhere in this report, to the rates we receive
on our pipelines in the future. Any successful challenge could adversely and
materially affect our future earnings and cash flows.

Rulemaking and
oversight, as well as changes in
regulations, by the Federal Energy Regulatory Commission or other regulatory
agencies having jurisdiction over our operations could adversely impact our
income and operations.

The
rates (which include reservation, commodity, surcharges, fuel and gas lost and
unaccounted for) we charge shippers on our natural gas pipeline systems are
subject to regulatory approval and oversight. Furthermore, regulators and
shippers on our natural gas pipelines have rights to challenge the rates
shippers are charged under certain circumstances prescribed by applicable
regulations. We can provide no assurance that we will not face challenges to
the rates we receive on our pipeline systems in the future. Any successful
challenge could materially adversely affect our future earnings and cash flows.
New laws or regulations or different interpretations of existing laws or
regulations applicable to our assets could have a material adverse impact on our
business, financial condition and results of operations.

Increased
regulatory requirements relating to the integrity of our pipelines will require
us to spend additional money to comply with these requirements.

Through
our regulated pipeline subsidiaries, we are subject to extensive laws and
regulations related to pipeline integrity. There are, for example, federal
guidelines for the U.S. Department of Transportation and pipeline companies in
the areas of testing, education, training and communication. Compliance with
laws and regulations requires significant expenditures. We have increased our
capital expenditures to address these matters and expect to significantly
increase these expenditures in the foreseeable future. Additional laws and
regulations that may be enacted in the future or a new interpretation of
existing laws and regulations could significantly increase the amount of these
expenditures.

Cost overruns and
delays on our expansion and new
build projects could adversely affect our business.

We
currently have several major expansion and new build projects planned or
underway, including the approximate $4.9 billion Rockies Express Pipeline and
the approximate $1.3 billion Midcontinent Express Pipeline. A variety of
factors outside our control, such as weather, natural disasters and
difficulties in obtaining permits and rights-of-way or other regulatory
approvals, as well as the performance by third party contractors has resulted
in, and may continue to result in, increased costs or delays in construction.
Cost overruns or delays in completing a project could have a material adverse
effect on our results of operations and cash flows.

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Our rapid growth
may cause difficulties integrating
and constructing new operations, and we may not be able to achieve the expected
benefits from any future acquisitions.

Part
of our business strategy includes acquiring additional businesses, expanding
existing assets, or constructing new facilities that will allow us to increase
distributions to our unitholders. If we do not successfully integrate
acquisitions, expansions, or newly constructed facilities, we may not realize
anticipated operating advantages and cost savings. The integration of companies
that have previously operated separately involves a number of risks, including:

| |   |                                                                                                                                     
| | - | ------------------------------------------------------------------------------------------------------------------------------------
| |  | demands on management related to
the
 increase in our size after an acquisition, an expansion, or a completed
 construction project;
| |   |                                                                                                                                     
| |  | the
 diversion of our managements attention from the management of daily
 operations;                                              
| |   |                                                                                                                                     
| |  | difficulties
 in implementing or unanticipated costs of accounting, estimating, reporting
 and other systems;                       
| |   |                                                                                                                                     
| |  | difficulties
 in the assimilation and retention of necessary employees; and                                                         
| |   |                                                                                                                                     
| |  | potential
 adverse effects on operating results.                                                                                    

We
may not be able to maintain the levels of operating efficiency that acquired
companies have achieved or might achieve separately. Successful integration of
each acquisition, expansion, or construction project will depend upon our
ability to manage those operations and to eliminate redundant and excess costs.
Because of difficulties in combining and expanding operations, we may not be
able to achieve the cost savings and other size-related benefits that we hoped
to achieve after these acquisitions, which would harm our financial condition
and results of operations.

Our acquisition
strategy and expansion programs
require access to new capital. Tightened credit markets or more expensive
capital would impair our ability to grow.

Part
of our business strategy includes acquiring additional businesses. We may need
new capital to finance these acquisitions. Limitations on our access to capital
will impair our ability to execute this strategy. We normally fund acquisitions
with short-term debt and repay such debt through the issuance of equity and
long-term debt. An inability to access the capital markets may result in a
substantial increase in our leverage and have a detrimental impact on our
credit profile.

Environmental
regulation and liabilities could result
in increased operating and capital costs.

Our
business operations are subject to federal, state, provincial and local laws
and regulations relating to environmental protection, pollution and human
health and safety in the United States and Canada. For example, if an
accidental leak, release or spill of liquid petroleum products, chemicals or
other products occurs at or from our pipelines or at or from our storage or
other facilities, we may experience significant operational disruptions and we
may have to pay a significant amount to clean up the leak, release or spill,
pay for government penalties, address natural resource damage, compensate for
human exposure or property damage, install costly pollution control equipment
or a combination of these and other measures. The resulting costs and
liabilities could materially and negatively affect our level of earnings and
cash flows. In addition, emission controls required under federal, state and
provincial environmental laws could require significant capital expenditures at
our facilities. The costs of environmental regulation are already significant,
and additional or more stringent regulation could increase these costs or could
otherwise negatively affect our business.

In
addition, our oil and gas development and production activities are subject to
certain federal, state and local laws and regulations relating to environmental
quality and pollution control. These laws and regulations increase the costs of
these activities and may prevent or delay the commencement or continuance of a
given operation. Specifically, we are subject to laws and regulations regarding
the acquisition of permits before drilling, restrictions on drilling activities
in restricted areas, emissions into the environment, water discharges, and
storage and disposition of hazardous wastes. In addition, legislation has been
enacted which requires well and facility sites to be

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abandoned and
reclaimed to the satisfaction of state authorities. The costs of environmental
regulation are already significant, and additional or more stringent regulation
could increase these costs or could otherwise negatively affect our business.

Energy
commodity transportation and storage activities involve numerous risks that may
result in accidents or otherwise adversely affect operations.

There
are a variety of hazards and operating risks inherent to natural gas
transmission and storage activities, and refined petroleum products and carbon
dioxide transportation activitiessuch as leaks, explosions and mechanical
problems that could result in substantial financial losses. In addition, these
risks could result in loss of human life, significant damage to property,
environmental pollution and impairment of operations, any of which also could
result in substantial losses. For pipeline and storage assets located near
populated areas, including residential areas, commercial business centers,
industrial sites and other public gathering areas, the level of damage
resulting from these risks could be greater. If losses in excess of our
insurance coverage were to occur, they could have a material adverse effect on
our business, financial condition and results of operations.

The future
success of our oil and gas development and
production operations depends in part upon our ability to develop additional
oil and gas reserves that are economically recoverable.

The rate of
production from oil and natural gas properties declines as reserves are
depleted. Without successful development activities, the reserves and revenues of our oil producing
assets within our CO2 business segment will decline. We may
not be able to develop or acquire additional reserves at an acceptable cost or
have necessary financing for these activities in the future. Additionally, if
we do not realize production volumes greater than, or equal to, our hedged
volumes, we will be liable to perform on hedges currently valued at greater
than $1.3 billion in favor of our counter-parties.

The
development of oil and gas properties involves risks that may result in a total
loss of investment.

The
business of developing and operating oil and gas properties involves a high
degree of business and financial risk that even a combination of experience,
knowledge and careful evaluation may not be able to overcome. Acquisition and
development decisions generally are based on subjective judgments and
assumptions that, while they may be reasonable, are by their nature
speculative. It is impossible to predict with certainty the production
potential of a particular property or well. Furthermore, a successful
completion of a well does not ensure a profitable return on the investment. A
variety of geological, operational, or market-related factors, including, but
not limited to, unusual or unexpected geological formations, pressures,
equipment failures or accidents, fires, explosions, blowouts, cratering,
pollution and other environmental risks, shortages or delays in the
availability of drilling rigs and the delivery of equipment, loss of
circulation of drilling fluids or other conditions may substantially delay or
prevent completion of any well, or otherwise prevent a property or well from
being profitable. A productive well may become uneconomic in the event water or
other deleterious substances are encountered, which impair or prevent the
production of oil and/or gas from the well. In addition, production from any
well may be unmarketable if it is contaminated with water or other deleterious
substances.

The
volatility of natural gas and oil prices could have a material adverse effect
on our business.

The
revenues, profitability and future growth of our CO2 business
segment and the carrying value of our oil and natural gas properties depend to
a large degree on prevailing oil and gas prices. Prices for oil and natural gas
are subject to large fluctuations in response to relatively minor changes in
the supply and demand for oil and natural gas, uncertainties within the market
and a variety of other factors beyond our control. These factors include, among
other things, weather conditions and events such as hurricanes in the United
States; the condition of the United States economy; the activities of the
Organization of Petroleum Exporting Countries; governmental regulation;
political stability in the Middle East and elsewhere; the foreign supply of oil
and natural gas; the price of foreign imports; and the availability of
alternative fuel sources.

A
sharp decline in the price of natural gas or oil prices would result in a
commensurate reduction in our revenues, income and cash flows from the
production of oil and natural gas and could have a material adverse effect on
the carrying value of our proved reserves. In the event prices fall
substantially, we may not be able to realize a

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profit from
our production and would operate at a loss. In recent decades, there have been
periods of both worldwide overproduction and underproduction of hydrocarbons
and periods of both increased and relaxed energy conservation efforts. Such
conditions have resulted in periods of excess supply of, and reduced demand
for, crude oil on a worldwide basis and for natural gas on a domestic basis.
These periods have been followed by periods of short supply of, and increased
demand for, crude oil and natural gas. The excess or short supply of crude oil
or natural gas has placed pressures on prices and has resulted in dramatic
price fluctuations even during relatively short periods of seasonal market
demand.

Our
use of hedging arrangements could result in financial losses or reduce our
income.

We
currently engage in hedging arrangements to reduce our exposure to fluctuations
in the prices of oil and natural gas. These hedging arrangements expose us to
risk of financial loss in some circumstances, including when production is less
than expected, when the counterparty to the hedging contract defaults on its
contract obligations, or when there is a change in the expected differential
between the underlying price in the hedging agreement and the actual prices
received. In addition, these hedging arrangements may limit the benefit we
would otherwise receive from increases in prices for oil and natural gas.

The
accounting standards regarding hedge accounting are complex, and even when we
engage in hedging transactions (for example, to mitigate our exposure to
fluctuations in commodity prices or to balance our exposure to fixed and
floating interest rates) that are effective economically, these transactions
may not be considered effective for accounting purposes. Accordingly, our
financial statements may reflect some volatility due to these hedges, even when
there is no underlying economic impact at that point. In addition, it is not
always possible for us to engage in a hedging transaction that completely
mitigates our exposure to commodity prices. Our financial statements may
reflect a gain or loss arising from an exposure to commodity prices for which
we are unable to enter into a completely effective hedge.

We
do not own approximately 97.5% of the land on which our pipelines are
constructed, and we are subject to the possibility of increased costs to retain
necessary land use.

We
obtain the right to construct and operate pipelines on other owners land for a
period of time. If we were to lose these rights or be required to relocate our
pipelines, our business could be affected negatively.

Whether
we have the power of eminent domain for our pipelines varies from state to
state depending upon the type of pipelinepetroleum liquids, natural gas or
carbon dioxideand the laws of the particular state. Our inability to exercise
the power of eminent domain could negatively affect our business if we were to
lose the right to use or occupy the property on which our pipelines are
located. For the year ended December 31, 2007, all of our right-of-way related
expenses totaled $14.6 million.

Our
debt instruments may limit our financial flexibility and increase our financing
costs.

The
instruments governing our debt contain restrictive covenants that may prevent
us from engaging in certain transactions that we deem beneficial and that may
be beneficial to us. The agreements governing our debt generally require us to
comply with various affirmative and negative covenants, including the
maintenance of certain financial ratios and restrictions on (i) incurring
additional debt; (ii) entering into mergers, consolidations and sales of
assets; (iii) granting liens; and (iv) entering into sale-leaseback
transactions. The instruments governing any future debt may contain similar or
more restrictive restrictions. Our ability to respond to changes in business
and economic conditions and to obtain additional financing, if needed, may be
restricted.

Because
a portion of our debt is subject to variable interest rates, if interest rates
increase, our earnings could be adversely affected.

As
of December 31, 2007, we had approximately $3.0 billion of debt, excluding the
value of interest rate swaps, subject to variable interest rates. This amount
included $2.3 billion of long-term fixed rate debt effectively converted to
variable rate debt through the use of interest rate swaps. Should interest
rates increase significantly, our earnings could be adversely affected. For
information on our interest rate risk, see Item 7A Quantitative and
Qualitative Disclosures About Market RiskInterest Rate Risk.

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Current
or future distressed financial conditions of customers could have an adverse
impact on us in the event these customers are unable to pay us for the services
we provide.

Some
of our customers are experiencing, or may experience in the future, severe
financial problems that have had or may have a significant impact on their
creditworthiness. We cannot provide assurance that one or more of our
financially distressed customers will not default on their obligations to us or
that such a default or defaults will not have a material adverse effect on our
business, financial position, future results of operations, or future cash flows.
Furthermore, the bankruptcy of one or more of our customers, or some other
similar proceeding or liquidity constraint, might make it unlikely that we
would be able to collect all or a significant portion of amounts owed by the
distressed entity or entities. In addition, such events might force such
customers to reduce or curtail their future use of our products and services,
which could have a material adverse effect on our results of operations and
financial condition.

The general
uncertainty associated with the current
world economic and political environments in which we exist may adversely
impact our financial performance.

Our
financial performance is impacted by overall marketplace spending and demand.
We are continuing to assess the effect that terrorism would have on our
businesses and in response, we have increased security with respect to our
assets. Recent federal legislation provides an insurance framework that should
cause current insurers to continue to provide sabotage and terrorism coverage
under standard property insurance policies. Nonetheless, there is no assurance
that adequate sabotage and terrorism insurance will be available at rates we
believe are reasonable throughout 2008.

Knights
recently completed going-private transaction resulted in substantially more
debt at Knight and could have an adverse effect on us, such as a downgrade in
the ratings of our debt securities.

On
May 30, 2007, Knight completed its going-private transaction. In connection
with the transaction, Knight incurred substantially more debt. In conjunction
with the going-private transaction, Moodys Investor Service, Inc. and Standard
& Poors Rating Services reviewed and adjusted the credit ratings of both
Knight and us. Following these adjustments, our senior unsecured debt is rated
BBB and Baa2 by Standard & Poors and Moodys, respectively. Though steps
have been taken which are intended to allow our senior unsecured indebtedness
to continue to be rated investment grade, we can provide no assurance that that
will be the case. Additionally, our rating was downgraded by Fitch Ratings from
BBB+ to BBB on April 11, 2007.

Our
senior managements attention may be diverted from our daily operations because
of recent significant transactions by Knight following the completion of the
going-private transaction.

The
investors in Knight Holdco LLC include members of Knights senior management,
most of whom are also senior officers of our general partner and of KMR. Prior
to consummation of the going-private transaction, KMI had publicly disclosed
that several significant transactions were being considered that, if pursued,
would require substantial management time and attention. As a result, our senior
managements attention may be diverted from the management of our daily
operations.

Competition
could ultimately lead to lower levels of profits and adversely impact our
ability to recontract for expiring transportation capacity at favorable rates.

Trans
Mountains pipeline to the West Coast of North America is one of several
pipeline alternatives for Western Canadian petroleum production. This pipeline,
like all our petroleum pipelines, competes against other pipeline companies who
could be in a position to offer different tolling structures, which may provide
them with a competitive advantage in new pipeline development. Throughput on
our pipelines may decline if tolls become uncompetitive compared to
alternatives.

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Future
business development of our products pipelines is dependent on the supply of,
and demand for, crude oil and other liquid hydrocarbons, particularly from the
Alberta oilsands.

Our
pipelines depend on production of natural gas, oil and other products in the
areas serviced by our pipelines. Without reserve additions, production will
decline over time as reserves are depleted and production costs may rise.
Producers may shut down production at lower product prices or higher production
costs, especially where the existing cost of production exceeds other
extraction methodologies, such as at the Alberta oilsands. Producers in areas
serviced by us may not be successful in exploring for and developing additional
reserves, and the gas plants and the pipelines may not be able to maintain
existing volumes of throughput. Commodity prices and tax incentives may not
remain at a level which encourages producers to explore for and develop
additional reserves, produce existing marginal reserves or renew transportation
contracts as they expire.

Changes
in the business environment, such as a decline in crude oil prices, an increase
in production costs from higher feedstock prices, supply disruptions, or higher
development costs, could result in a slowing of supply from the Alberta oilsands.
In addition, changes in the regulatory environment or governmental policies may
have an impact on the supply of crude oil. Each of these factors impact our
customers shipping through our pipelines, which in turn could impact the
prospects of new transportation contracts or renewals of existing contracts.

Throughput
on our products pipelines may also decline as a result of changes in business
conditions. Over the long term, business will depend, in part, on the level of
demand for oil and natural gas in the geographic areas in which deliveries are
made by pipelines and the ability and willingness of shippers having access or
rights to utilize the pipelines to supply such demand. The implementation of
new regulations or the modification of existing regulations affecting the oil
and gas industry could reduce demand for natural gas and crude oil, increase
our costs and may have a material adverse effect on our results of operations
and financial condition. We cannot predict the impact of future economic
conditions, fuel conservation measures, alternative fuel requirements,
governmental regulation or technological advances in fuel economy and energy
generation devices, all of which could reduce the demand for natural gas and
oil.

We
are subject to U.S. dollar/Canadian dollar exchange rate fluctuations.

As
a result of our acquisition of the Trans Mountain pipeline system, the
Vancouver Wharves terminal, the Cochin pipeline system, and our terminal
expansion projects located in Edmonton, Alberta, Canada, a portion of our
assets, liabilities, revenues and expenses are denominated in Canadian dollars.
We are a U.S. dollar reporting company. Fluctuations in the exchange rate
between United States and Canadian dollars could expose us to reductions in the
U.S. dollar value of our earnings and cash flows and a reduction in our
partners capital under applicable accounting rules.

Risks
Related to Our Common Units

The interests of
Knight may differ from our interests
and the interests of our unitholders.

Knight
indirectly owns all of the stock of our general partner and elects all of its
directors. Our general partner owns all of KMRs voting shares and elects all
of its directors. Furthermore, some of KMRs directors and officers are also
directors and officers of Knight and our general partner and have fiduciary
duties to manage the businesses of Knight in a manner that may not be in the
best interests of our unitholders. Knight has a number of interests that differ
from the interests of our unitholders. As a result, there is a risk that
important business decisions will not be made in the best interests of our
unitholders.

Common
unitholders have limited voting rights and limited control.

Holders
of common units have only limited voting rights on matters affecting us. Our
general partner manages partnership activities. Under a delegation of control
agreement, our general partner has delegated the management and control of our
and our subsidiaries business and affairs to KMR. Holders of common units have
no right to elect the general partner on an annual or other ongoing basis. If
the general partner withdraws, however, its successor may be elected by the
holders of a majority of the outstanding common units (excluding units owned by
the departing general partner and its affiliates).

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The
limited partners may remove the general partner only if (i) the holders of at
least 66 2/3% of the outstanding common units, excluding common units owned by the departing
general partner and its affiliates, vote to remove the general partner; (ii) a
successor general partner is approved by at least 66 2/3% of the outstanding common units, excluding common units
owned by the departing general partner and its affiliates; and (iii) we receive
an opinion of counsel opining that the removal would not result in the loss of
limited liability to any limited partner, or the limited partner of an
operating partnership, or cause us or the operating partnership to be taxed
other than as a partnership for federal income tax purposes.

A
person or group owning 20% or more of the common units cannot vote.

Any
common units held by a person or group that owns 20% or more of the common units
cannot be voted. This limitation does not apply to the general partner and its
affiliates. This provision may (i) discourage a person or group from attempting
to remove the general partner or otherwise change management; and (ii) reduce
the price at which the common units will trade under certain circumstances. For
example, a third party will probably not attempt to take over our management by
making a tender offer for the common units at a price above their trading
market price without removing the general partner and substituting an affiliate
of its own.

The general
partners liability to us and our
unitholders may be limited.

Our
partnership agreement contains language limiting the liability of the general
partner to us or the holders of common units. For example, our partnership
agreement provides that (i) the general partner does not breach any duty to us
or the holders of common units by borrowing funds or approving any borrowing
(the general partner is protected even if the purpose or effect of the
borrowing is to increase incentive distributions to the general partner); (ii)
the general partner does not breach any duty to us or the holders of common
units by taking any actions consistent with the standards of reasonable discretion
outlined in the definitions of available cash and cash from operations
contained in our partnership agreement; and (iii) the general partner does not
breach any standard of care or duty by resolving conflicts of interest unless
the general partner acts in bad faith.

Unitholders
may have liability to repay distributions.

Unitholders
will not be liable for assessments in addition to their initial capital
investment in the common units. Under certain circumstances, however, holders of
common units may have to repay us amounts wrongfully returned or distributed to
them. Under Delaware law, we may not make a distribution to unitholders if the
distribution causes our liabilities to exceed the fair value of our assets.
Liabilities to partners on account of their partnership interests and
non-recourse liabilities are not counted for purposes of determining whether a
distribution is permitted. Delaware law provides that for a period of three
years from the date of such a distribution, a limited partner who receives the
distribution and knew at the time of the distribution that the distribution
violated Delaware law will be liable to the limited partnership for the
distribution amount. Under Delaware law, an assignee who becomes a substituted
limited partner of a limited partnership is liable for the obligations of the
assignor to make contributions to the partnership. However, such an assignee is
not obligated for liabilities unknown to the assignee at the time the assignee
became a limited partner if the liabilities could not be determined from the
partnership agreement.

Unitholders may
be liable if we have not complied
with state partnership law.

We
conduct our business in a number of states. In some of those states the
limitations on the liability of limited partners for the obligations of a
limited partnership have not been clearly established. The unitholders might be
held liable for the partnerships obligations as if they were a general partner
if (i) a court or government agency determined that we were conducting business
in the state but had not complied with the states partnership statute; or (ii)
unitholders rights to act together to remove or replace the general partner or
take other actions under our partnership agreement constitute control of our
business.

The
general partner may buy out minority unitholders if it owns 80% of the units.

If
at any time the general partner and its affiliates own 80% or more of the
issued and outstanding common units, the general partner will have the right to
purchase all, and only all, of the remaining common units. Because of this
right, a unitholder could have to sell its common units at a time or price that
may be undesirable. The purchase price

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for such a
purchase will be the greater of (i) the 20-day average trading price for the
common units as of the date five days prior to the date the notice of purchase
is mailed; or (ii) the highest purchase price paid by the general partner or
its affiliates to acquire common units during the prior 90 days. The general
partner can assign this right to its affiliates or to us.

We may sell
additional limited partner interests,
diluting existing interests of unitholders.

Our
partnership agreement allows the general partner to cause us to issue
additional common units and other equity securities. When we issue additional
equity securities, including additional i-units to KMR when it issues
additional shares, unitholders proportionate partnership interest in us will
decrease. Such an issuance could negatively affect the amount of cash
distributed to unitholders and the market price of common units. Issuance of
additional common units will also diminish the relative voting strength of the previously
outstanding common units. Our partnership agreement does not limit the total
number of common units or other equity securities we may issue.

The general
partner can protect itself against
dilution.

Whenever
we issue equity securities to any person other than the general partner and its
affiliates, the general partner has the right to purchase additional limited
partnership interests on the same terms. This allows the general partner to
maintain its proportionate partnership interest in us. No other unitholder has
a similar right. Therefore, only the general partner may protect itself against
dilution caused by issuance of additional equity securities.

Our
partnership agreement and the KMR limited liability company agreement restrict
or eliminate a number of the fiduciary duties that would otherwise be owed by
our general partner and/or its delegate to our unitholders.

Modifications
of state law standards of fiduciary duties may significantly limit the ability
of our unitholders to successfully challenge the actions of our general partner
in the event of a breach of fiduciary duties. These state law standards include
the duties of care and loyalty. The duty of loyalty, in the absence of a
provision in the limited partnership agreement to the contrary, would generally
prohibit our general partner from taking any action or engaging in any
transaction as to which it has a conflict of interest. Our limited partnership
agreement contains provisions that prohibit limited partners from advancing
claims that otherwise might raise issues as to compliance with fiduciary duties
or applicable law. For example, that agreement provides that the general
partner may take into account the interests of parties other than us in resolving
conflicts of interest. It also provides that in the absence of bad faith by the
general partner, the resolution of a conflict by the general partner will not
be a breach of any duty. The provisions relating to the general partner apply
equally to KMR as its delegate. It is not necessary for a limited partner to
sign our limited partnership agreement in order for the limited partnership
agreement to be enforceable against that person.

We adopted
certain valuation methodologies that may
result in a shift of income, gain, loss and deduction between our general
partner and our unitholders. The IRS may challenge this treatment, which could
adversely affect the value of the common units.

When
we issue additional units or engage in certain other transactions, we determine
the fair market value of our assets and allocate any unrealized gain or loss
attributable to our assets to the capital accounts of our unitholders and our
general partner. This methodology may be viewed as understating the value of
our assets. In that case, there may be a shift of income, gain, loss and
deduction between certain unitholders and our general partner, which may be
unfavorable to such unitholders. Moreover, under our current valuation methods,
subsequent purchasers of common units may have a greater portion of their
Internal Revenue Code Section 743(b) adjustment allocated to our tangible
assets and a lesser portion allocated to our intangible assets. The IRS may
challenge these valuation methods, or our allocation of the Section 743(b)
adjustment attributable to our tangible and intangible assets, and allocations
of income, gain, loss and deduction between our general partner and certain of
our unitholders.

A
successful IRS challenge to these methods or allocations could adversely affect
the amount of taxable income or loss being allocated to our partners. It also
could affect the amount of gain from our unitholders sale of common units and
could have a negative impact on the value of the common units or result in
audit adjustments to our unitholders tax returns without the benefit of
additional deductions.

44

---



Our
treatment of a purchaser of common units as having the same tax benefits as the
seller could be challenged, resulting in a reduction in value of the common
units.

Because
we cannot match transferors and transferees of common units, we are required to
maintain the uniformity of the economic and tax characteristics of these units
in the hands of the purchasers and sellers of these units. We do so by adopting
certain depreciation conventions that do not conform to all aspects of the
United States Treasury regulations. A successful IRS challenge to these
conventions could adversely affect the tax benefits to a unitholder of ownership
of the common units and could have a negative impact on their value or result in
audit adjustments to unitholders tax returns.

Our tax treatment
depends on our status as a partnership for federal income tax purposes, as well
as our not being subject to a material amount of entity-level taxation by
individual states. If the Internal Revenue Service treats us as a corporation or
if we become subject to a material amount of entity-level taxation for state tax
purposes, it would substantially reduce the amount of cash available for
distribution to our partners.

The
anticipated after-tax economic benefit of an investment in us depends largely
on our being treated as a partnership for federal income tax purposes. In order
for us to be treated as a partnership for federal income tax purposes, current
law requires that 90% or more of our gross income for every taxable year
consist of qualifying income, as defined in Section 7704 of the Internal
Revenue Code. We may not meet this requirement or current law may change so as
to cause, in either event, us to be treated as a corporation for federal income
tax purposes or otherwise subject to federal income tax. We have not requested,
and do not plan to request, a ruling from the Internal Revenue Service on this
or any other matter affecting us.

If
we were to be treated as a corporation for federal income tax purposes, we
would pay federal income tax on our income at the corporate tax rate, which is
currently a maximum of 35%, and would pay state income taxes at varying rates.
Under current law, distributions to our partners would generally be taxed again
as corporate distributions, and no income, gain, losses or deductions would
flow through to our partners. Because a tax would be imposed on us as a
corporation, our cash available for distribution would be substantially
reduced. Therefore, treatment of us as a corporation would result in a material
reduction in the anticipated cash flow and after-tax return to our partners,
likely causing substantial reduction in the value of our units.

Current
law or our business may change so as to cause us to be treated as a corporation
for federal income tax purposes or otherwise subject us to entity-level
taxation. Members of Congress are considering substantive changes to the
existing federal income tax laws that affect certain publicly-traded
partnerships. For example, federal income tax legislation has been proposed
that would eliminate partnership tax treatment for certain publicly-traded
partnerships. Although the currently proposed legislation would not appear to
affect our tax treatment as a partnership, we are unable to predict whether any
of these changes, or other proposals, will ultimately be enacted. Any such changes
could negatively impact the value of an investment in our common units.

In
addition, because of widespread state budget deficits and other reasons,
several states are evaluating ways to subject partnerships to entity-level
taxation through the imposition of state income, franchise or other forms of
taxation. For example, we are now subject to a new entity-level tax on the
portion of our total revenue that is generated in Texas. Specifically, the
Texas margin tax is imposed at a maximum effective rate of 0.7% of our total
revenue that is apportioned to Texas. Imposition of such a tax on us by Texas,
or any other state, will reduce our cash available for distribution to our
partners.

Our
partnership agreement provides that if a law is enacted that subjects us to
taxation as a corporation or otherwise subjects us to entity-level taxation for
federal income tax purposes, the minimum quarterly distribution and the target
distribution levels will be adjusted to reflect the impact on us of that law.

The
issuance of additional i-units may cause more taxable income to be allocated to
the common units.

The
i-units we issue to KMR generally are not allocated income, gain, loss or
deduction for federal income tax purposes until such time as we are liquidated.
Therefore, the issuance of additional i-units may cause more taxable income and
gain to be allocated to the common unitholders.

45

---



Risks
Related to Ownership of Our Common Units if We or Knight Defaults on Debt

Unitholders may
have negative tax consequences if we
default on our debt or sell assets.

If
we default on any of our debt, the lenders will have the right to sue us for
non-payment. Such an action could cause an investment loss and cause negative
tax consequences for unitholders through the realization of taxable income by
unitholders without a corresponding cash distribution. Likewise, if we were to
dispose of assets and realize a taxable gain while there is substantial debt
outstanding and proceeds of the sale were applied to the debt, unitholders
could have increased taxable income without a corresponding cash distribution.

There is the
potential for a change of control if
Knight defaults on debt.

Knight
owns all of the outstanding capital stock of our general partner. Knight has
operations which provide cash independent of dividends that Knight receives
from our general partner. Nevertheless, if Knight defaults on its debt, in
exercising their rights as lenders, Knights lenders could acquire control of
our general partner or otherwise influence our general partner through control
of Knight.

|         |                           
|-------- | --------------------------
|Item 1B. | Unresolved Staff Comments.

None.

|        |                   
|------- | ------------------
|Item 3. | Legal Proceedings.

See
Note 16 of the notes to our consolidated financial statements included
elsewhere in this report.

|        |                                                     
|------- | ----------------------------------------------------
|Item 4. | Submission of Matters to a Vote of Security Holders.

There
were no matters submitted to a vote of our unitholders during the fourth
quarter of 2007.

46

---



PART II

|                                                                                                                       | 
|---------------------------------------------------------------------------------------------------------------------- | 
|Item 5. Market for Registrants Common Equity, Related Stockholder Matters
 and Issuer Purchases of Equity Securities.

The
following table sets forth, for the periods indicated, the high and low sale
prices per common unit, as reported on the New York Stock Exchange, the
principal market in which our common units are traded, the amount of cash
distributions declared per common and Class B unit, and the fractional i-unit
distribution declared per i-unit.

|                |  |             |       |     |   |                     |  |                       |        |  |  |          | 
|--------------- |  | ----------- | ----- | --- | - | ------------------- |  | --------------------- | ------ |  |  | -------- | 
|                |  | Price Range |       |     |   |                     |  |                       |       
|                |  |             |       |     |   |                     | 
|                |  | High        |       | Low |   | Cash
 Distributions |  | i-unit
 Distributions |       
|                |  |             |       |     |   |                     |  |                       |       
|2007            |  |             |       |     |   |                     |  |                       |        |  |  |          | 
|First
 Quarter  |  | $           | 53.50 |     | $ | 47.28               |  | $                     | 0.8300 |  |  | 0.015378 | 
|Second
 Quarter |  |             | 57.35 |     |   | 52.11               |  |                       | 0.8500 |  |  | 0.016331 | 
|Third
 Quarter  |  |             | 56.70 |     |   | 46.61               |  |                       | 0.8800 |  |  | 0.017686 | 
|Fourth Quarter  |  |             | 54.71 |     |   | 48.51               |  |                       | 0.9200 |  |  | 0.017312 | 
|                |  |             |       |     |   |                     |  |                       |        |  |  |          | 
|2006            |  |             |       |     |   |                     |  |                       |        |  |  |          | 
|First
 Quarter  |  | $           | 56.22 |     | $ | 44.70               |  | $                     | 0.8100 |  |  | 0.018566 | 
|Second
 Quarter |  |             | 48.80 |     |   | 43.62               |  |                       | 0.8100 |  |  | 0.018860 | 
|Third
 Quarter  |  |             | 46.53 |     |   | 42.80               |  |                       | 0.8100 |  |  | 0.018981 | 
|Fourth
 Quarter |  |             | 48.98 |     |   | 43.01               |  |                       | 0.8300 |  |  | 0.016919 | 

Distribution
information is for distributions declared with respect to that quarter. The
declared distributions were paid within 45 days after the end of the quarter.
We currently expect to declare cash distributions of at least $4.02 per unit
for 2008; however, no assurance can be given that we will be able to achieve
this level of distribution, and our expectation does not take into account any
capital costs associated with financing the payment of reparations sought by
shippers on our Pacific operations interstate pipelines.

As
of January 31, 2008, there were approximately 190,660 holders of our common
units (based on the number of record holders and individual participants in
security position listings), one holder of our Class B units and one holder of
our i-units.

For
information on our equity compensation plans, see Item 12 Security Ownership
of Certain Beneficial Owners and Management and Related Stockholder
MattersEquity Compensation Plan Information.

We did not
repurchase any units during 2007 or sell any unregistered units in the fourth
quarter of 2007.

47

---



|                                | 
|------------------------------- | 
|Item 6. Selected Financial Data

The
following tables set forth, for the periods and at the dates indicated, our
summary historical financial and operating data. The table is derived from our
consolidated financial statements and notes thereto, and should be read in
conjunction with those audited financial statements. See also Item 7
Managements Discussion and Analysis of Financial Condition and Results of
Operations in this report for more information.

|                                                                                                                       |  |                                               |          |         |   |          |   |         |          |          |   |          |   |   |         |  
|---------------------------------------------------------------------------------------------------------------------- |  | --------------------------------------------- | -------- | ------- | - | -------- | - | ------- | -------- | -------- | - | -------- | - | - | ------- | -
|                                                                                                                       |  | Year Ended December 31,                       |         
|                                                                                                                       |  |                                               |         
|                                                                                                                       |  | 2007(6)                                       |          | 2006(7) |   | 2005(8)  |   | 2004(9) |          | 2003(10) |  
|                                                                                                                       |  |                                               |          |         |   |          |   |         |          |          |  
|                                                                                                                       |  | (In millions, except per unit and ratio data) |         
|Income and
 Cash Flow Data:                                                                                            |  |                                               |          |         |   |          |   |         |          |          |   |          |   |   |         |  
|Revenues                                                                                                               |  | $                                             | 9,217.7  |         | $ | 9,048.7  |   | $       | 9,745.9  |          | $ | 7,893.0  |   | $ | 6,583.6 |  
|Costs, Expenses and Other:                                                                                             |  |                                               |          |         |   |          |   |         |          |          |   |          |   |   |         |  
|Gas purchases
and other costs of sales                                                                                 |  |                                               | 5,809.8  |         |   | 5,990.9  |   |         | 7,167.3  |          |   | 5,767.0  |   |   | 4,880.0 |  
|Operations and
maintenance                                                                                             |  |                                               | 1,024.6  |         |   | 777.0    |   |         | 719.5    |          |   | 488.6    |   |   | 388.6   |  
|Fuel and
power                                                                                                         |  |                                               | 237.5    |         |   | 223.7    |   |         | 178.5    |          |   | 146.4    |   |   | 102.2   |  
|Depreciation,
depletion and amortization                                                                               |  |                                               | 540.0    |         |   | 423.9    |   |         | 341.6    |          |   | 281.1    |   |   | 212.2   |  
|General and
administrative                                                                                             |  |                                               | 278.7    |         |   | 238.4    |   |         | 216.7    |          |   | 170.5    |   |   | 150.5   |  
|Taxes, other
than income taxes                                                                                         |  |                                               | 153.8    |         |   | 134.4    |   |         | 106.5    |          |   | 79.1     |   |   | 60.3    |  
|Other expense
(income)                                                                                                 |  |                                               | 365.6    |         |   | (31.2    | ) |         |         |          |   |         |   |   |        |  
|                                                                                                                       |  |                                               |          |         |   |          |   |         |          |          |   |          |   |   |         |  
|                                                                                                                       |  |                                               | 8,410.0  |         |   | 7,757.1  |   |         | 8,730.1  |          |   | 6,932.7  |   |   | 5,793.8 |  
|                                                                                                                       |  |                                               |          |         |   |          |   |         |          |          |   |          |   |   |         |  
|Operating income                                                                                                       |  |                                               | 807.7    |         |   | 1,291.6  |   |         | 1,015.8  |          |   | 960.3    |   |   | 789.8   |  
|                                                                                                                       |  |                                               |          |         |   |          |   |         |          |          |   |          |   |   |         |  
|Other income/(expense):                                                                                                |  |                                               |          |         |   |          |   |         |          |          |   |          |   |   |         |  
|Earnings from
equity investments                                                                                       |  |                                               | 69.7     |         |   | 74.0     |   |         | 89.6     |          |   | 81.8     |   |   | 91.2    |  
|Amortization of
excess cost of equity investments                                                                      |  |                                               | (5.8     | )       |   | (5.6     | ) |         | (5.5     | )        |   | (5.6     | ) |   | (5.5    | )
|Interest,
net                                                                                                          |  |                                               | (391.4   | )       |   | (337.8   | ) |         | (259.0   | )        |   | (192.9   | ) |   | (181.4  | )
|Other,
net                                                                                                             |  |                                               | 14.2     |         |   | 12.0     |   |         | 3.3      |          |   | 2.2      |   |   | 7.6     |  
|Minority
interest                                                                                                      |  |                                               | (7.0     | )       |   | (15.4    | ) |         | (7.3     | )        |   | (9.6     | ) |   | (9.0    | )
|Income tax
provision                                                                                                   |  |                                               | (71.0    | )       |   | (29.0    | ) |         | (24.5    | )        |   | (19.7    | ) |   | (16.6   | )
|                                                                                                                       |  |                                               |          |         |   |          |   |         |          |          |   |          |   |   |         |  
|Income from continuing
 operations                                                                                     |  |                                               | 416.4    |         |   | 989.8    |   |         | 812.4    |          |   | 816.5    |   |   | 676.1   |  
|Income (loss)
from discontinued operations(1)                                                                          |  |                                               | 173.9    |         |   | 14.3     |   |         | (0.2     | )        |   | 15.1     |   |   | 17.8    |  
|                                                                                                                       |  |                                               |          |         |   |          |   |         |          |          |   |          |   |   |         |  
|Income before
cumulative effect of a change in accounting principle                                                    |  |                                               | 590.3    |         |   | 1,004.1  |   |         | 812.2    |          |   | 831.6    |   |   | 693.9   |  
|Cumulative
effect of a change in accounting principle                                                                  |  |                                               |         |         |   |         |   |         |         |          |   |         |   |   | 3.4     |  
|                                                                                                                       |  |                                               |          |         |   |          |   |         |          |          |   |          |   |   |         |  
|Net income                                                                                                             |  | $                                             | 590.3    |         | $ | 1,004.1  |   | $       | 812.2    |          | $ | 831.6    |   | $ | 697.3   |  
|Less: General Partners
 interest in net income                                                                        |  |                                               | (611.6   | )       |   | (513.3   | ) |         | (477.3   | )        |   | (395.1   | ) |   | (326.5  | )
|                                                                                                                       |  |                                               |          |         |   |          |   |         |          |          |   |          |   |   |         |  
|Limited Partners interest
 in net income (loss)                                                                       |  | $                                             | (21.3    | )       | $ | 490.8    |   | $       | 334.9    |          | $ | 436.5    |   | $ | 370.8   |  
|                                                                                                                       |  |                                               |          |         |   |          |   |         |          |          |   |          |   |   |         |  
|                                                                                                                       |  |                                               |          |         |   |          |   |         |          |          |   |          |   |   |         |  
|Basic Limited Partners net
 income (loss) per unit:                                                                   |  |                                               |          |         |   |          |   |         |          |          |   |          |   |   |         |  
|Income (loss) per unit from
 continuing operations and before cumulative effect of a change in accounting principle(2) |  | $                                             | (0.82    | )       | $ | 2.12     |   | $       | 1.58     |          | $ | 2.14     |   | $ | 1.89    |  
|Income from discontinued
 operations                                                                                   |  |                                               | 0.73     |         |   | 0.07     |   |         |         |          |   | 0.08     |   |   | 0.09    |  
|Cumulative effect of a
 change in accounting principle                                                                 |  |                                               |         |         |   |         |   |         |         |          |   |         |   |   | 0.02    |  
|                                                                                                                       |  |                                               |          |         |   |          |   |         |          |          |   |          |   |   |         |  
|Net income (loss) per unit                                                                                             |  | $                                             | (0.09    | )       | $ | 2.19     |   | $       | 1.58     |          | $ | 2.22     |   | $ | 2.00    |  
|                                                                                                                       |  |                                               |          |         |   |          |   |         |          |          |   |          |   |   |         |  
|                                                                                                                       |  |                                               |          |         |   |          |   |         |          |          |   |          |   |   |         |  
|Diluted Limited Partners
 net income (loss) per unit:                                                                 |  |                                               |          |         |   |          |   |         |          |          |   |          |   |   |         |  
|Income (loss) per unit from
continuing operations and bef. cumulative
 effect of a change in acctg. principle(2)       |  | $                                             | (0.82    | )       | $ | 2.12     |   | $       | 1.58     |          | $ | 2.14     |   | $ | 1.89    |  
|Income from discontinued
 operations                                                                                   |  |                                               | 0.73     |         |   | 0.06     |   |         |         |          |   | 0.08     |   |   | 0.09    |  
|Cumulative effect of a
 change in accounting principle                                                                 |  |                                               |         |         |   |         |   |         |         |          |   |         |   |   | 0.02    |  
|                                                                                                                       |  |                                               |          |         |   |          |   |         |          |          |   |          |   |   |         |  
|Net income (loss) per unit                                                                                             |  | $                                             | (0.09    | )       | $ | 2.18     |   | $       | 1.58     |          | $ | 2.22     |   | $ | 2.00    |  
|                                                                                                                       |  |                                               |          |         |   |          |   |         |          |          |   |          |   |   |         |  
|                                                                                                                       |  |                                               |          |         |   |          |   |         |          |          |   |          |   |   |         |  
|Per unit cash distribution
 declared(3)                                                                                |  | $                                             | 3.48     |         | $ | 3.26     |   | $       | 3.13     |          | $ | 2.87     |   | $ | 2.63    |  
|Ratio of earnings to fixed
 charges(4)                                                                                 |  | $                                             | 2.13     |         | $ | 3.64     |   |         | 3.76     |          |   | 4.84     |   |   | 4.68    |  
|Additions to property,
 plant and equipment                                                                            |  | $                                             | 1,691.6  |         | $ | 1,182.1  |   | $       | 863.1    |          | $ | 747.3    |   | $ | 577.0   |  
|                                                                                                                       |  |                                               |          |         |   |          |   |         |          |          |   |          |   |   |         |  
|Balance
 Sheet Data (at end of period):                                                                                |  |                                               |          |         |   |          |   |         |          |          |   |          |   |   |         |  
|Net property, plant and
 equipment                                                                                     |  | $                                             | 11,591.3 |         | $ | 10,106.1 |   | $       | 8,864.6  |          | $ | 8,168.9  |   | $ | 7,091.6 |  
|Total assets                                                                                                           |  | $                                             | 15,177.8 |         | $ | 13,542.2 |   | $       | 11,923.5 |          | $ | 10,552.9 |   | $ | 9,139.2 |  
|Long-term debt(5)                                                                                                      |  | $                                             | 6,455.9  |         | $ | 4,384.3  |   | $       | 5,220.9  |          | $ | 4,722.4  |   | $ | 4,316.7 |  

48

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---

|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(1) | Represents
 income or loss from the operations of our North System natural gas liquids
 pipeline system. For 2007 only, also includes a gain of $152.8 million on
 disposal of our North System. For more information on our discontinued
 operations, see Note 3 to our consolidated financial statements included
 elsewhere in this report.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|(2) | Represents
 income from continuing operations before cumulative effect of a change in
 accounting principle per unit. Basic Limited Partners income per unit from
 continuing operations before cumulative effect of a change in accounting
 principle was computed by dividing the interest of our unitholders in income
 from continuing operations before cumulative effect of a change in accounting
 principle by the weighted average number of units outstanding during the
 period. Diluted Limited Partners net income per unit reflects the maximum
 potential dilution that could occur if units whose issuance depends on the
 market price of the units at a future date were considered outstanding, or
 if, by application of the treasury stock method, options to issue units were
 exercised, both of which would result in the issuance of additional units
 that would then share in our net income.                                                                                                                                                                                                                                                                                                                                                                                                                                      
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|(3) | Represents
 the amount of cash distributions declared with respect to that year.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|(4) | For the
 purpose of computing the ratio of earnings to fixed charges, earnings are
 defined as income from continuing operations before income taxes and
 cumulative effect of a change in accounting principle, and before minority
 interest in consolidated subsidiaries, equity earnings (including
 amortization of excess cost of equity investments) and unamortized
 capitalized interest, plus fixed charges and distributed income of equity
 investees. Fixed charges are defined as the sum of interest on all
 indebtedness (excluding capitalized interest), amortization of debt issuance
 costs and that portion of rental expense which we believe to be
 representative of an interest factor.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|(5) | Excludes
 value of interest rate swaps. Increases to long-term debt for value of
 interest rate swaps totaled $152.2 million as of December 31, 2007, $42.6
 million as of December 31, 2006, $98.5 million as of December 31, 2005,
 $130.2 million as of December 31, 2004, and $121.5 million as of December 31,
 2003.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|(6) | Includes
 results of operations for an approximate 50.2% interest in the Cochin
 pipeline system, the Vancouver Wharves marine terminal, and terminal assets
 acquired from Marine Terminals, Inc. since effective dates of acquisition. We
 acquired the remaining 50.2% interest in Cochin that we did not already own
 from affiliates of BP effective January 1, 2007. We acquired
 the Vancouver Wharves bulk marine terminal operations from British Columbia
 Railway Company effective May 30, 2007, and we acquired certain bulk terminal
 assets from Marine Terminals, Inc. effective September 1, 2007. Also includes
 Trans Mountain since January 1, 2007 as discussed below.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|(7) | Includes
 results of operations for the net assets of Trans Mountain acquired on April
 30, 2007 from Knight Inc. (formerly Kinder Morgan, Inc.) since January 1,
 2006. Also includes results of operations for the oil and gas properties
 acquired from Journey Acquisition-I, L.P. and Journey 2000, L.P., the
 terminal assets and operations acquired from A&L Trucking, L.P. and U.S.
 Development Group, Transload Services, LLC, and Devco USA L.L.C. since
 effective dates of acquisition. The April 5, 2006 acquisition of the Journey
 oil and gas properties were made effective March 1, 2006. The assets and
 operations acquired from A&L Trucking and U.S. Development Group were
 acquired in three separate transactions in April 2006. We acquired all of the
 membership interests in Transload Services, LLC effective November 20, 2006,
 and we acquired all of the membership interests in Devco USA L.L.C. effective
 December 1, 2006. We also acquired a 66 2/3% ownership interest in Entrega
 Pipeline LLC effective February 23, 2006, however, our earnings were not
 materially impacted during 2006 due to the fact that regulatory accounting
 provisions required capitalization of revenues and expenses until the second
 segment of the Entrega Pipeline was complete and in-service.                                   
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|(8) | Includes
 results of operations for the 64.5% interest in the Claytonville unit, the seven
 bulk terminal operations acquired from Trans-Global Solutions, Inc., the
 Kinder Morgan Staten Island terminal, the terminal facilities located in
 Hawesville, Kentucky and Blytheville, Arkansas, General Stevedores, L.P., the
 North Dayton natural gas storage facility, the Kinder Morgan Blackhawk
 terminal, the terminal repair shop acquired from Trans-Global Solutions,
 Inc., and the terminal assets acquired from Allied Terminals, Inc. since
 effective dates of acquisition. We acquired the 64.5% interest in the
 Claytonville unit effective January 31, 2005. We acquired the seven bulk
 terminal operations from Trans-Global Solutions, Inc. effective April 29,
 2005. The Kinder Morgan Staten Island terminal, the Hawesville, Kentucky
 terminal and the Blytheville, Arkansas terminal were each acquired separately
 in July 2005. We acquired all of the partnership interests in General
 Stevedores, L.P. effective July 31, 2005. We acquired the North Dayton
 natural gas storage facility effective August 1, 2005. We acquired the Kinder
 Morgan Blackhawk terminal in August 2005 and the terminal repair shop in
 September 2005. We acquired the terminal assets from Allied Terminals, Inc.
 effective November 4, 2005.
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|(9) | Includes
 results of operations for the seven refined petroleum products terminals
 acquired from ExxonMobil, Kinder Morgan Wink Pipeline, L.P., an additional 5%
 interest in the Cochin Pipeline System, Kinder Morgan River Terminals LLC and
 its consolidated subsidiaries, TransColorado Gas Transmission Company LLC, interests
 in nine refined petroleum products terminals acquired from Charter Terminal
 Company and Charter-Triad Terminals, LLC, and the Kinder Morgan                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            

49

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|     |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
|---- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|     | Fairless
 Hills terminal since effective dates of acquisition. We acquired the seven
 refined petroleum products terminals from ExxonMobil effective March 9, 2004.
 We acquired Kinder Morgan Wink Pipeline, L.P. effective August 31, 2004. The
 additional interest in Cochin was acquired effective October 1, 2004. We
 acquired Kinder Morgan River Terminals LLC and its consolidated subsidiaries
 effective October 6, 2004. We acquired TransColorado effective November 1,
 2004, the interests in the nine Charter Terminal Company and Charter-Triad
 Terminals, LLC refined petroleum products terminals effective November 5,
 2004, and the Kinder Morgan Fairless Hills terminal effective December 1,
 2004.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      
|     |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
|(10) | Includes
 results of operations for the bulk terminal operations acquired from M.J.
 Rudolph Corporation, the additional 12.75% interest in the SACROC unit, the
 five refined petroleum products terminals acquired from Shell, the additional
 42.5% interest in the Yates field unit, the crude oil gathering operations
 surrounding the Yates field unit, an additional 65% interest in the Pecos
 Carbon Dioxide Company, the remaining approximate 32% interest in MidTex Gas
 Storage Company, LLP, the seven refined petroleum products terminals acquired
 from ConocoPhillips and two bulk terminal facilities located in Tampa,
 Florida since dates of acquisition. We acquired certain bulk terminal
 operations from M.J. Rudolph effective January 1, 2003. The additional 12.75%
 interest in SACROC was acquired effective June 1, 2003. The five refined
 petroleum products terminals were acquired effective October 1, 2003. The
 additional 42.5% interest in the Yates field unit, the Yates gathering system
 and the additional 65% interest in Pecos Carbon Dioxide Company were acquired
 effective November 1, 2003. The additional 32% ownership interest in MidTex
 was acquired November 1, 2003. The seven refined petroleum products terminals
 were acquired December 11, 2003, and the two bulk terminal facilities located
 in Tampa, Florida were acquired effective December 10 and 23, 2003.

|                                                                                               | 
|---------------------------------------------------------------------------------------------- | 
|Item 7. Managements Discussion and Analysis of
Financial Condition and Results of Operations.

The
following discussion and analysis of our financial condition and results of
operations provides a narrative of our financial results. It contains a
discussion and analysis of the results of operations for each segment of our
business, followed by a discussion and analysis of our financial condition. The
following discussion and analysis is based on our consolidated financial
statements, which are included elsewhere in this report and were prepared in
accordance with accounting principles generally accepted in the United States
of America.

The
following discussion and analysis should be read in conjunction with our
consolidated financial statements included elsewhere in this report. Additional
sections in this report which should be helpful to the reading of our
discussion and analysis include the following: (i) a description of our
business strategy found in Items 1 and 2 Business and Properties(c) Narrative
Description of BusinessBusiness Strategy; (ii) a description of developments
during 2007, found in Items 1 and 2 Business and Properties(a) General
Development of BusinessRecent Developments; and (iii) a description of risk
factors affecting us and our business, found in Item 1A Risk Factors.

In
addition, as discussed in Note 3 of the accompanying notes to our consolidated
financial statements, our financial statements reflect:

| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | the April 30, 2007 transfer of
Trans Mountain as if such transfer had
 taken place on January 1, 2006, the effective date of common control pursuant
 to generally accepted accounting principles. The financial information
 contained in this Managements Discussion and Analysis of Financial Condition
 and Results of Operations includes the financial results of Trans Mountain
 for all periods subsequent to January 1, 2006; and                                                                                                                                           
| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       
| |  | the reclassifications necessary
to reflect the results of our North
 System as discontinued operations. However, due to the fact that the sale of
 our North System does not change the structure of our internal organization
 in a manner that causes a change to our reportable business segments pursuant
 to the provisions of SFAS No. 131, Disclosures about Segments of an
 Enterprise and Related Information, we have included the North Systems financial
 results within our Products Pipelines business segment disclosures for all
 periods presented in this report.

We
begin with a discussion of our Critical Accounting Polices and Estimates, those
areas that are both very important to the portrayal of our financial condition
and results and which require our managements most difficult, subjective or
complex judgments, often as a result of the need to make estimates about the
effect of matters that are inherently uncertain.

50

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Critical Accounting Policies and Estimates

Accounting
standards require information in financial statements about the risks and
uncertainties inherent in significant estimates, and the application of
generally accepted accounting principles involves the exercise of varying
degrees of judgment. Certain amounts included in or affecting our consolidated
financial statements and related disclosures must be estimated, requiring us to
make certain assumptions with respect to values or conditions that cannot be
known with certainty at the time the financial statements are prepared. These
estimates and assumptions affect the amounts we report for our assets and
liabilities, our revenues and expenses during the reporting period, and our
disclosure of contingent assets and liabilities at the date of our financial
statements.

We
routinely evaluate these estimates, utilizing historical experience,
consultation with experts and other methods we consider reasonable in the
particular circumstances. Nevertheless, actual results may differ significantly
from our estimates. Any effects on our business, financial position or results
of operations resulting from revisions to these estimates are recorded in the
period in which the facts that give rise to the revision become known.

In
preparing our consolidated financial statements and related disclosures,
examples of certain areas that require more judgment relative to others include
our use of estimates in determining:

| |   |                                                                                                            
| | - | -----------------------------------------------------------------------------------------------------------
| |  | the economic useful lives of our
assets;                                                                   
| |   |                                                                                                            
| |  | the fair values used to allocate
purchase price and to determine
 possible asset impairment charges;       
| |   |                                                                                                            
| |  | reserves for environmental
claims, legal fees, transportation rate
 cases and other litigation liabilities;
| |   |                                                                                                            
| |  | provisions for uncollectible
accounts receivables;                                                         
| |   |                                                                                                            
| |  | exposures under contractual
indemnifications; and                                                          
| |   |                                                                                                            
| |  | unbilled revenues.                                                                                         

For
a summary of our significant accounting policies, see Note 2 to our
consolidated financial statements included elsewhere in this report. We believe
that certain accounting policies are of more significance in our consolidated
financial statement preparation process than others, which policies are
discussed as follows.

Environmental
Matters

With
respect to our environmental exposure, we utilize both internal staff and
external experts to assist us in identifying environmental issues and in
estimating the costs and timing of remediation efforts. We expense or
capitalize, as appropriate, environmental expenditures that relate to current
operations, and we record environmental liabilities when environmental
assessments and/or remedial efforts are probable and we can reasonably estimate
the costs. We do not discount environmental liabilities to a net present value,
and we recognize receivables for anticipated associated insurance recoveries
when such recoveries are deemed to be probable.

Our
recording of our environmental accruals often coincides with our completion of
a feasibility study or our commitment to a formal plan of action, but
generally, we recognize and/or adjust our environmental liabilities following
routine reviews of potential environmental issues and claims that could impact
our assets or operations. These adjustments may result in increases in
environmental expenses and are primarily related to quarterly reviews of
potential environmental issues and resulting environmental liability estimates.

These
environmental liability adjustments are recorded pursuant to our managements
requirement to recognize contingent environmental liabilities whenever the
associated environmental issue is likely to occur and the amount of our
liability can be reasonably estimated. In making these liability estimations,
we consider the effect of environmental compliance, pending legal actions
against us, and potential third-party liability claims. For more information on
our environmental disclosures, see Note 16 to our consolidated financial
statements included elsewhere in this report.

51

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Legal
Matters

We
are subject to litigation and regulatory proceedings as a result of our
business operations and transactions. We utilize both internal and external
counsel in evaluating our potential exposure to adverse outcomes from orders,
judgments or settlements. To the extent that actual outcomes differ from our
estimates, or additional facts and circumstances cause us to revise our
estimates, our earnings will be affected. In general, we expense legal costs as
incurred. When we identify specific litigation that is expected to continue for
a significant period of time and require substantial expenditures, we identify
a range of possible costs expected to be required to litigate the matter to a
conclusion or reach an acceptable settlement. If no amount within this range is
a better estimate than any other amount, we record a liability equal to the low
end of the range. Any such liability recorded is revised as better information
becomes available.

As
of December 31, 2007, our most significant ongoing litigation proceedings
involve our SFPP, L.P, subsidiary, which is the limited partnership that owns
our Pacific operations pipelines, excluding CALNEV Pipe Line LLC. Tariffs
charged by our Pacific operations pipeline systems are subject to certain
proceedings at the FERC involving shippers complaints regarding the interstate
rates, as well as practices and the jurisdictional nature of certain facilities
and services. Generally, the interstate rates on our Pacific operations pipeline
systems are grandfathered under the Energy Policy Act of 1992 unless
substantially changed circumstances are found to exist. To the extent
substantially changed circumstances are found to exist, our Pacific
operations may be subject to substantial exposure under these FERC complaints
and could, therefore, owe reparations and/or refunds to complainants as
mandated by the FERC or the United States judicial system. For more
information on our Pacific operations regulatory proceedings, see Note 16 to
our consolidated financial statements included elsewhere in this report.

Intangible
Assets

Intangible
assets are those assets which provide future economic benefit but have no
physical substance. We account for our intangible assets according to the
provisions of Statement of Financial Accounting Standards No. 141, Business
Combinations and Statement of Financial Accounting Standards No. 142,
Goodwill and Other Intangible Assets. These accounting pronouncements
introduced the concept of indefinite life intangible assets and provided that
all identifiable intangible assets having indefinite useful economic lives,
including goodwill, will not be subject to regular periodic amortization. Such
assets are not to be amortized until their lives are determined to be finite.
Instead, the carrying amount of a recognized intangible asset with an
indefinite useful life must be tested for impairment annually or on an interim
basis if events or circumstances indicate that the fair value of the asset has
decreased below its carrying value. We have selected an impairment measurement
test date of January 1 of each year, and we have determined that our goodwill
was not impaired as of January 1, 2008.

As
of December 31, 2007, our goodwill was $1,077.8 million. Included in this
goodwill balance is $251.0 million related to our Trans Mountain business
segment, which we acquired from Knight on April 30, 2007. Following the
provisions of generally accepted accounting principles, this transaction caused
Knight to consider the fair value of the Trans Mountain pipeline system, and to
determine whether goodwill related to these assets was impaired. Knight
recorded a goodwill impairment charge of $377.1 million in the first quarter of
2007. This impairment is also reflected on our books due to the accounting
principles for transfers of assets between entities under common control, which
require us to account for Trans Mountain as if the transfer had taken place on
January 1, 2006.

Our
remaining intangible assets, excluding goodwill, include customer
relationships, contracts and agreements, technology-based assets and lease
value. These intangible assets have definite lives, are being amortized on a
straight-line basis over their estimated useful lives, and are reported
separately as Other intangibles, net in our accompanying consolidated balance
sheets. As of December 31, 2007 and 2006, these intangibles totaled $238.6
million and $213.2 million, respectively.

Estimated
Net Recoverable Quantities of Oil and Gas

We
use the successful efforts method of accounting for our oil and gas producing
activities. The successful efforts method inherently relies on the estimation
of proved reserves, both developed and undeveloped. The existence and the
estimated amount of proved reserves affect, among other things, whether certain
costs are

52

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capitalized or expensed, the
amount and timing of costs depleted or amortized into income and the
presentation of supplemental information on oil and gas producing activities.
The expected future cash flows to be generated by oil and gas producing
properties used in testing for impairment of such properties also rely in part
on estimates of net recoverable quantities of oil and gas.

Proved
reserves are the estimated quantities of oil and gas that geologic and
engineering data demonstrates with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating
conditions. Estimates of proved reserves may change, either positively or
negatively, as additional information becomes available and as contractual,
economic and political conditions change.

Hedging
Activities

We
engage in a hedging program that utilizes derivative contracts to mitigate
(offset) our exposure to fluctuations in energy commodity prices and to balance
our exposure to fixed and floating interest rates, and we believe that these
hedges are generally effective in realizing these objectives. However, the
accounting standards regarding hedge accounting are complex, and even when we
engage in hedging transactions that are effective economically, these
transactions may not be considered effective for accounting purposes.

According
to the provisions of current accounting standards, to be considered effective,
changes in the value of a derivative contract or its resulting cash flows must
substantially offset changes in the value or cash flows of the item being
hedged. A perfectly effective hedge is one in which changes in the value of the
derivative contract exactly offset changes in the value of the hedged item or
expected cash flow of the future transactions in reporting periods covered by
the derivative contract. The ineffective portion of the gain or loss and any
component excluded from the computation of the effectiveness of the derivative
contract must be reported in earnings immediately; accordingly, our financial
statements may reflect some volatility due to these hedges.

In
addition, it is not always possible for us to engage in a hedging transaction
that completely mitigates our exposure to unfavorable changes in commodity
prices. For example, when we purchase a commodity at one location and sell it
at another, we may be unable to hedge completely our exposure to a differential
in the price of the product between these two locations. Even when we cannot
enter into a completely effective hedge, we often enter into hedges that are
not completely effective in those instances where we believe to do so would be
better than not hedging at all, but due to the fact that the part of the
hedging transaction that is not effective in offsetting undesired changes in
commodity prices (the ineffective portion) is required to be recognized currently
in earnings, our financial statements may reflect a gain or loss arising from
an exposure to commodity prices for which we are unable to enter into a
completely effective hedge.

Results
of Operations

| |                                                                   |                                                                                                                           
| | ----------------------------------------------------------------- | --------------------------------------------------------------------------------------------------------------------------
| | Our business model is
 built to support two principal components:
| |                                                                   |                                                                                                                           
| |                                                                  | helping customers by
 providing energy, bulk commodity and liquids products transportation, storage
 and distribution; and
| |                                                                   |                                                                                                                           
| |                                                                  | creating long-term value
 for our unitholders.                                                                            

To
achieve these objectives, we focus on providing fee-based services to customers
from a business portfolio consisting of energy-related pipelines, bulk and
liquids terminal facilities, and carbon dioxide and petroleum reserves. Our
reportable business segments are based on the way our management organizes our
enterprise, and each of our five segments represents a component of our
enterprise that engages in a separate business activity and for which discrete
financial information is available.

53

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|                                                                                                                                |  |                         |               |      |   |         |   |   |         |  
|------------------------------------------------------------------------------------------------------------------------------- |  | ----------------------- | ------------- | ---- | - | ------- | - | - | ------- | -
|Consolidated                                                                                                                    |  |                         |               |      |   |         |   |   |         |  
|                                                                                                                                |  | Year Ended December 31, |              
|                                                                                                                                |  |                         |              
|                                                                                                                                |  | 2007                    |               | 2006 |   | 2005    |  
|                                                                                                                                |  |                         |               |      |   |         |  
|                                                                                                                                |  |                         | (In millions) |     
|Earnings before depreciation,
depletion and amortization
 expense and amortization of excess cost of equity investments(a)      |  |                         |               |      |   |         |   |   |         |  
|Products
Pipelines(b)                                                                                                           |  | $                       | 569.6         |      | $ | 491.2   |   | $ | 370.1   |  
|Natural Gas
Pipelines(c)                                                                                                        |  |                         | 600.2         |      |   | 574.8   |   |   | 500.3   |  
|CO2 (d)                                                                                                                         |  |                         | 537.0         |      |   | 488.2   |   |   | 470.9   |  
|Terminals(e)                                                                                                                    |  |                         | 416.0         |      |   | 408.1   |   |   | 314.6   |  
|Trans
Mountain(f)                                                                                                               |  |                         | (293.6        | )    |   | 76.5    |   |   |        |  
|                                                                                                                                |  |                         |               |      |   |         |   |   |         |  
|Segment earnings before
depreciation, depletion and amortization
 expense and amortization of excess cost of equity investments |  |                         | 1,829.2       |      |   | 2,038.8 |   |   | 1,655.9 |  
|                                                                                                                                |  |                         |               |      |   |         |   |   |         |  
|Depreciation,
depletion and amortization
 expense(g)                                                                            |  |                         | (547.0        | )    |   | (432.8  | ) |   | (349.8  | )
|Amortization of
excess cost of equity
 investments                                                                              |  |                         | (5.8          | )    |   | (5.7    | ) |   | (5.6    | )
|Interest and
corporate administrative
 expenses(h)                                                                              |  |                         | (686.1        | )    |   | (596.2  | ) |   | (488.3  | )
|                                                                                                                                |  |                         |               |      |   |         |   |   |         |  
|Net
income                                                                                                                      |  | $                       | 590.3         |      | $ | 1,004.1 |   | $ | 812.2   |  
|                                                                                                                                |  |                         |               |      |   |         |   |   |         |  



---

|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(a) | Includes revenues, earnings from
equity
 investments, allocable interest income and other, net, less operating
 expenses, allocable income taxes, and other expense (income). Operating
 expenses include natural gas purchases and other costs of sales, operations
 and maintenance expenses, fuel and power expenses, and taxes, other than income
 taxes.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         
|(b) | 2007 amount includes (i) a
$152.8 million
 gain from the sale of our North System; (ii) a $136.8 million increase in
 expense associated with rate case and other legal liability adjustments;
 (iii) a $15.9 million increase in expense associated with environmental
 liability adjustments; (iv) a $15.0 million expense for a litigation
 settlement reached with Contra Costa County, California; (v) a $3.2 million
 increase in expense from the settlement of certain litigation matters related
 to our West Coast refined products terminal operations; and (vi) a $1.8
 million increase in income resulting from unrealized foreign currency gains
 on long-term debt transactions. 2006 amount includes a $16.5 million increase
 in expense associated with environmental liability adjustments, and a $5.7
 million increase in income resulting from certain transmix contract
 settlements. 2005 amount includes a $105.0 million increase in expense
 resulting from a rate case liability adjustment, a $13.7 million increase in
 expense resulting from a North System liquids inventory reconciliation
 adjustment, and a $19.6 million increase in expense associated with
 environmental liability adjustments.
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         
|(c) | 2007 amount includes an expense
of $1.0
 million, reflecting our portion of a loss from the early extinguishment of
 debt by Red Cedar Gathering Company, and a $0.4 million decrease in expense
 associated with environmental liability adjustments. 2006 amount includes a
 $1.5 million increase in expense associated with environmental liability
 adjustments, a $15.1 million gain from the combined sale of our Douglas
 natural gas gathering system and Painter Unit fractionation facility, and a
 $6.3 million reduction in expense due to the release of a reserve related to
 a natural gas purchase/sales contract. 2005 amount includes a $0.1 million
 reduction in expense associated with environmental liability adjustments.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         
|(d) | 2007 amount includes a $0.2
million
 increase in expense associated with environmental liability adjustments. 2006
 amount includes a $1.8 million loss on derivative contracts used to hedge
 forecasted crude oil sales. 2005 amount includes a $0.3 million increase in
 expense associated with environmental liability adjustments.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         
|(e) | 2007 amount includes (i) a $25.0
million
 increase in expense from the settlement of certain litigation matters related
 to our Cora coal terminal; (ii) a $2.0 million increase in expense associated
 with environmental liability adjustments; (iii) an increase in income of $1.8
 million from property casualty gains associated with the 2005 hurricane
 season; and (iv) a $1.2 million increase in expense associated with legal
 liability adjustments. 2006 amount includes an $11.3 million net increase in
 income from the net effect of a property casualty insurance gain and
 incremental repair and clean-up expenses (both associated with the 2005
 hurricane season). 2005 amount includes a $3.5 million increase in expense
 associated with environmental liability adjustments.                                                                                                                                                                                                                                                                                                                                                                                                                                
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         
|(f) | As discussed in Note 3 to our
consolidated
 financial statements included elsewhere in this report, our consolidated
 financial statements, and all other financial information included in this
 report, are presented as though the April 30, 2007 transfer of Trans Mountain
 net assets had occurred on the date when both Trans Mountain and we met the
 accounting requirements for entities under common control (January 1, 2006).
 2007 amount includes losses of $349.2 million for periods prior to our
 acquisition date of April 30, 2007 (including a goodwill impairment expense
 of $377.1 million), and a $1.3 million decrease in income from an oil loss
 allowance. 2006 amount represents earnings for a period prior to our
 acquisition date of April 30, 2007.                                                                                                                                                                                                                                                                                                                                                                                                                                                  

54

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|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(g) | 2007 and
  2006 amounts include Trans Mountain expenses of $6.3 million and $19.0
  million, respectively, for periods prior to our acquisition date of April 30,
  2007.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         
|(h) | Includes
  unallocated interest income and income tax expense, interest and debt
  expense, general and administrative expenses (including unallocated
  litigation and environmental expenses), and minority interest expense. 2007
  amount includes the following: (i) a $26.2 million increase in expense,
  allocated to us from Knight, associated with closing the going-private
  transaction. Knight Inc. was responsible for the payment of the costs
  resulting from this transaction; (ii) a combined $6.7 million increase in
  expense, related to Trans Mountain interest and general and administrative
  expenses for periods prior to our acquisition date of April 30, 2007; (iii) a
  $2.4 million increase in interest expense related to our Cochin Pipeline
  acquisition; (iv) a $2.1 million expense due to the adjustment of certain
  insurance related liabilities; (v) a $1.7 million increase in expense
  associated with the 2005 hurricane season; (vi) a $1.5 million expense for
  certain Trans Mountain acquisition costs; (vii) a $0.8 million expense related
  to the cancellation of certain commercial insurance policies; and (viii) a
  total $3.9 million decrease in minority interest expense, related to the
  minority interest effect from all of the previously listed items. 2006 amount
  includes a combined $25.1 million expense related to Trans Mountain interest
  and general and administrative expenses, a $2.0 million increase in expense,
  primarily related to the cancellation of certain commercial insurance policies
  and a $3.5 million increase in minority interest expense, primarily related to
  the minority interest effect from the property casualty insurance gain
  described in footnote (e). 2005 amount includes a $25.0 million expense for a
  litigation settlement reached between us and a former joint venture partner
  on our Kinder Morgan Tejas natural gas pipeline system, a cumulative $8.4
  million expense related to settlements of environmental matters at certain of
  our operating sites located in the state of California, and a $3.0 million
  decrease in expense related to proceeds received in connection with the
  settlement of claims in the Enron Corp. bankruptcy proceeding.

For
the year 2007, our net income was $590.3 million on revenues of $9,217.7
million. This compares with net income of $1,004.1 million on revenues of
$9,048.7 million in 2006, and net income of $812.2 million on revenues of
$9,745.9 million in 2005. The certain items described in the footnotes to the
table above account for $483.3 million of the year-to-year decrease of $413.8
million. The remaining increase in net income is associated with better
performance from our operating segments.

The
primary reason for the decrease in our 2007 net income, when compared to last
year, was related to an impairment expense of $377.1 million associated with a
non-cash reduction in the carrying value of Trans Mountains goodwill. Included
within the certain items footnoted in the table above, and discussed above in
  Intangibles, the goodwill impairment charge was recognized by Knight in March
2007. Following our purchase of Trans Mountain from Knight on April 30, 2007,
the financial results of Trans Mountain since January 1, 2006, including the
impact of the goodwill impairment, are reflected in our results. Also, our
overall carrying value for the net assets of Trans Mountain reflects Knights
carrying value, which is considerably higher than the cash price we paid. For
more information on this acquisition and the goodwill impairment, see Notes 3
and 8 to our consolidated financial statements included elsewhere in this report.

Segment
earnings before depreciation, depletion and amortization expenses

Because
our partnership agreement requires us to distribute 100% of our available cash
to our partners on a quarterly basis (available cash consists primarily of all
our cash receipts, less cash disbursements and changes in reserves), we
consider each periods earnings before all non-cash depreciation, depletion and
amortization expenses, including amortization of excess cost of equity
investments, to be an important measure of our success in maximizing returns to
our partners. We also use segment
earnings before depreciation, depletion and amortization expenses (defined in
the table above and sometimes referred to in this report as EBDA) internally as
a measure of profit and loss used for evaluating segment performance and for
deciding how to allocate resources to our five reportable business segments.

Combined,
the certain items described in the footnotes to the table above decreased total
segment earnings before depreciation, depletion and amortization by $489.1
million in 2007, relative to 2006 (combining to decrease total segment EBDA by
$394.0 million in 2007 and to increase segment EBDA by $95.1 million in 2006).
The remaining $279.5 million (14%) increase in segment earnings before
depreciation, depletion and amortization in 2007 versus 2006 was driven by
strong financial results from increased margins on natural gas transport,
storage and processing activities, incremental earnings from dry-bulk product
and petroleum liquids terminal operations, higher crude oil and natural gas
liquids revenues, incremental earnings from completed expansion projects, and
our acquisition of the Trans Mountain pipeline system and the remaining
interest in the Cochin pipeline system that we did not already own.

55

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In
2006, the certain items described above combined to increase total segment
earnings before depreciation, depletion and amortization by$237.1 million, compared to the previous
year (combining to increase total segment EBDA by $95.1 million in 2006 and to
decrease segment EBDA by $142.0 million in 2005). The remaining $145.8 million
(8%) increase in segment earnings before depreciation, depletion and
amortization in 2006 versus 2005 was primarily attributable to internal growth
and expansion across our business portfolio and to incremental contributions
from assets and operations acquired since the end of 2005.

Products Pipelines

|                                                                                                                            |  |                                            |        |      |   |        |   |   |        |  
|--------------------------------------------------------------------------------------------------------------------------- |  | ------------------------------------------ | ------ | ---- | - | ------ | - | - | ------ | -
|                                                                                                                            |  | Year Ended December 31,                    |       
|                                                                                                                            |  |                                            |       
|                                                                                                                            |  | 2007                                       |        | 2006 |   | 2005   |  
|                                                                                                                            |  |                                            |        |      |   |        |  
|                                                                                                                            |  | (In millions, except operating statistics) |       
|Revenues                                                                                                                    |  | $                                          | 844.4  |      | $ | 776.3  |   | $ | 711.8  |  
|Operating expenses(a)                                                                                                       |  |                                            | (451.8 | )    |   | (308.3 | ) |   | (366.0 | )
|Other income(b)                                                                                                             |  |                                            | 154.8  |      |   |       |   |   |       |  
|Earnings from equity
investments(c)                                                                                         |  |                                            | 32.5   |      |   | 16.3   |   |   | 28.5   |  
|Interest income and Other,
net-income
  (expense)(d)                                                                        |  |                                            | 9.4    |      |   | 12.1   |   |   | 6.1    |  
|Income tax benefit
(expense)(e)                                                                                             |  |                                            | (19.7  | )    |   | (5.2   | ) |   | (10.3  | )
|                                                                                                                            |  |                                            |        |      |   |        |   |   |        |  
|Earnings
before depreciation, depletion and
  amortization 
  expense and amortization of excess cost of equity investments |  | $                                          | 569.6  |      | $ | 491.2  |   | $ | 370.1  |  
|                                                                                                                            |  |                                            |        |      |   |        |   |   |        |  
|                                                                                                                            |  |                                            |        |      |   |        |   |   |        |  
|Gasoline (MMBbl)                                                                                                            |  |                                            | 435.5  |      |   | 449.8  |   |   | 452.1  |  
|Diesel fuel (MMBbl)                                                                                                         |  |                                            | 164.1  |      |   | 158.2  |   |   | 163.1  |  
|Jet fuel (MMBbl)                                                                                                            |  |                                            | 125.1  |      |   | 119.5  |   |   | 118.1  |  
|                                                                                                                            |  |                                            |        |      |   |        |   |   |        |  
|Total refined
product volumes (MMBbl)                                                                                       |  |                                            | 724.7  |      |   | 727.5  |   |   | 733.3  |  
|Natural gas liquids
(MMBbl)                                                                                                 |  |                                            | 30.4   |      |   | 34.0   |   |   | 33.5   |  
|                                                                                                                            |  |                                            |        |      |   |        |   |   |        |  
|Total delivery
volumes (MMBbl)(f)                                                                                           |  |                                            | 755.1  |      |   | 761.5  |   |   | 766.8  |  
|                                                                                                                            |  |                                            |        |      |   |        |   |   |        |  



---

|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(a) | 2007, 2006
  and 2005 amounts include increases in expense of $15.9 million, $13.5 million
  and $19.6 million, respectively, associated with environmental liability
  adjustments. 2007 amount also includes a $136.7 million increase in expense
  associated with rate case and other legal liability adjustments, a $15.0
  million expense for a litigation settlement reached with Contra Costa County,
  California, and a $3.2 million increase in expense from the settlement of
  certain litigation matters related to our West Coast refined products
  terminal operations. 2005 amount also includes a $105.0 million increase in
  expense associated with a rate case liability adjustment, and a $13.7 million
  increase in expense associated with a North System liquids inventory
  reconciliation adjustment.
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
|(b) | 2007 amount
  includes a $152.8 million gain from the sale of our North System.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
|(c) | 2007 amount
  includes a $0.1 million increase in expense associated with our proportional
  share of legal liability adjustments on Plantation Pipe Line Company. 2006
  amount includes a $4.9 million increase in expense associated with our
  proportional share of environmental liability adjustments on Plantation Pipe
  Line Company.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
|(d) | 2007 amount
  includes a $1.8 million increase in income resulting from unrealized foreign
  currency gains on long-term debt transactions. 2006 amount includes a $5.7
  million increase in income resulting from transmix contract settlements.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
|(e) | 2006 amount
  includes a $1.9 million decrease in expense associated with our proportional
  share of the tax effect on our share of environmental expenses incurred by
  Plantation Pipe Line Company and described in footnote (c).                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
|(f) | Includes
  Pacific, Plantation, CALNEV, Central Florida, Cochin, and Cypress pipeline
  volumes.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    

Our
Products Pipelines segments primary businesses include transporting refined
petroleum products and natural gas liquids through pipelines and operating
liquid petroleum products terminals and petroleum pipeline transmix processing
facilities. Combined, the certain items described in the footnotes to the table
above decreased earnings before depreciation, depletion and amortization by
$5.5 million in 2007 compared to 2006, and increased earnings before
depreciation, depletion and amortization by $127.5 million in 2006 compared to
2005.

Following
is information related to the remaining increases and decreases in the
segments (i) earnings before depreciation, depletion and amortization expenses
(EBDA); and (ii) operating revenues in both 2007 and 2006, when compared to the
respective prior year:

56

---



|                                                                   |  |                                   |      |                     |  |     |   |   |       |   |  |     |   
|------------------------------------------------------------------ |  | --------------------------------- | ---- | ------------------- |  | --- | - | - | ----- | - |  | --- | --
|Year Ended December 31, 2007 versus Year Ended December 31,
  2006
|                                                                   |  | EBDA                              |      | Revenues            | 
|                                                                   |  | increase/(decrease)               |      | Increase/(decrease) | 
|                                                                   |  |                                   |      |                     | 
|                                                                   |  | (In millions, except percentages) |     
|Cochin Pipeline
System                                             |  | $                                 | 30.0 |                     |  | 212 | % | $ | 39.2  |   |  | 110 | % 
|West Coast Terminals                                               |  |                                   | 12.3 |                     |  | 34  | % |   | 7.5   |   |  | 12  | % 
|Plantation Pipeline                                                |  |                                   | 8.6  |                     |  | 27  | % |   | 1.0   |   |  | 2   | % 
|Transmix operations                                                |  |                                   | 8.0  |                     |  | 36  | % |   | 10.6  |   |  | 32  | % 
|Pacific operations                                                 |  |                                   | 5.8  |                     |  | 2   | % |   | 18.4  |   |  | 5   | % 
|CALNEV Pipeline                                                    |  |                                   | 5.1  |                     |  | 11  | % |   | 3.4   |   |  | 5   | % 
|Southeast Terminals                                                |  |                                   | 5.0  |                     |  | 13  | % |   | (12.9 | ) |  | (16 | )%
|North System                                                       |  |                                   | 4.9  |                     |  | 21  | % |   | (2.6  | ) |  | (6  | )%
|All other (including
eliminations)                                 |  |                                   | 4.2  |                     |  | 11  | % |   | 3.5   |   |  | 7   | % 
|                                                                   |  |                                   |      |                     |  |     |   |   |       |   |  |     |   
|Total Products
Pipelines                                           |  | $                                 | 83.9 |                     |  | 17  | % | $ | 68.1  |   |  | 9   | % 
|                                                                   |  |                                   |      |                     |  |     |   |   |       |   |  |     |   

|                                                                   |  |                                   |      |                     |  |     |    |   |      |   |  |    |   
|------------------------------------------------------------------ |  | --------------------------------- | ---- | ------------------- |  | --- | -- | - | ---- | - |  | -- | --
|Year Ended December 31, 2006 versus Year Ended December 31,
  2005
|                                                                   |  | EBDA                              |      | Revenues            | 
|                                                                   |  | Increase/(decrease)               |      | increase/(decrease) | 
|                                                                   |  |                                   |      |                     | 
|                                                                   |  | (In millions, except percentages) |     
|Cochin Pipeline
System                                             |  | $                                 | (5.2 | )                   |  | (27 | )% | $ | (0.5 | ) |  | (1 | )%
|Southeast Terminals                                                |  |                                   | 4.9  |                     |  | 15  | %  |   | 24.5 |   |  | 43 | % 
|Plantation Pipeline                                                |  |                                   | (4.2 | )                   |  | (12 | )% |   | 1.5  |   |  | 4  | % 
|Pacific operations                                                 |  |                                   | (5.4 | )                   |  | (2  | )% |   | 16.2 |   |  | 5  | % 
|West Coast Terminals                                               |  |                                   | (2.6 | )                   |  | (7  | )% |   | 6.5  |   |  | 11 | % 
|Transmix operations                                                |  |                                   | 2.6  |                     |  | 13  | %  |   | 3.9  |   |  | 13 | % 
|All other (including
eliminations)                                 |  |                                   | 3.5  |                     |  | 3   | %  |   | 12.4 |   |  | 8  | % 
|                                                                   |  |                                   |      |                     |  |     |    |   |      |   |  |    |   
|Total Products
Pipelines                                           |  | $                                 | (6.4 | )                   |  | (1  | )% | $ | 64.5 |   |  | 9  | % 
|                                                                   |  |                                   |      |                     |  |     |    |   |      |   |  |    |   

All
of the assets in our Products Pipelines business segment produced higher
earnings before depreciation, depletion and amortization expenses in 2007 than
in the previous year. The overall increase in segment earnings before
depreciation, depletion and amortization in 2007 compared to 2006 was driven
largely by incremental earnings from our Cochin pipeline system. The higher
earnings and revenues from Cochin were largely attributable to our January 1,
2007 acquisition of the remaining approximate 50.2% ownership interest that we
did not already own. Upon closing of the transaction, we became the operator of
the pipeline. For more information on this acquisition, see Note 3 to our
consolidated financial statements included elsewhere in this report.

The
year-to-year earnings increase from our West Coast terminal operations in 2007
was due to higher operating revenues, lower operating expenses and incremental
gains from asset sales. The increases in terminal revenues were driven by
higher throughput volumes from our combined Carson/Los Angeles Harbor terminal
system, partly due to completed storage expansion projects since the end of
2006, and from our Linnton and Willbridge terminals located in Portland,
Oregon. The decrease in operating expenses in 2007 versus 2006 was largely
related to higher environmental expenses recognized in 2006, due to adjustments
to accrued environmental liabilities (these incremental environmental expenses
were not associated with the expenses described in footnote (a) to the table
above).

The
increase in earnings in 2007 from our approximate 51% equity investment in
Plantation Pipe Line Company was due to higher overall net income earned by
Plantation, largely resulting from both higher pipeline revenues and lower
period-to-period operating expenses. The increase in revenues was largely due
to a higher oil loss allowance percentage in 2007, relative to last year, and
the drop in operating expensesincluding fuel, power and pipeline maintenance
expenses, was due to decreases in both refined products delivery volumes and
pipeline integrity expenses in 2007 versus 2006 (pipeline integrity expenses
are discussed more fully below).

The
year-to-year increase in earnings before depreciation, depletion and
amortization from our petroleum pipeline transmix operations was directly
related to higher revenues, reflecting incremental revenues from our
Greensboro, North Carolina facility and higher processing revenues from our
Colton, California facility. In May 2006, we completed construction and placed
into service the Greensboro facility, and during 2007, the plant

57

---



processed greater volumes
than in 2006. In 2007, our Greensboro facility contributed incremental earnings
before depreciation, depletion and amortization of $4.5 million and incremental
revenues of $5.4 million in 2007 compared to 2006. The increases in earnings
and revenues from our Colton facility, which processes transmix generated from
volumes transported to the Southern California and Arizona markets by our
Pacific operations pipelines, were primarily due to year-to-year increases in
average processing contract rates.

We
also benefited from higher earnings before depreciation, depletion and
amortization from our Pacific operations, our CALNEV Pipeline and our North
System in 2007, when compared to last year. The increase in our Pacific
operations earnings was largely revenue related, attributable to increases in
both transportation volumes and average tariff rates. Combined mainline
delivery and terminal revenues increased 5% in 2007, compared to 2006, due
largely to higher delivery volumes to Arizona, the completed expansion of our
East Line pipeline during the summer of 2006, and higher deliveries to various
West Coast military bases. The increase from CALNEV was also driven by higher
year-over-year revenues, due to increased military and commercial tariff rates
in 2007, and higher terminal revenues associated with ethanol blending at our
Las Vegas terminal that more than offset a 2% drop in refined products delivery
volumes. The increase from our North System was mainly due to lower combined
operating expense, due to its sale in the fourth quarter of 2007 (the decline
in expense was greater than the associated decline in revenue).

Effective
October 5, 2007, we sold our North System common carrier natural gas liquids
pipeline and our 50% ownership interest in the Heartland Pipeline Company to
ONEOK Partners, L.P. for approximately $298.6 million, and we used the proceeds
we received to pay down short-term debt borrowings. We accounted for our North
System business as a discontinued operation pursuant to generally accepted
accounting principles which require that the income statement be formatted to
separate the divested business from our continuing operations; however,
consistent with the management approach of identifying and reporting financial
information on operating segments, we have included the North Systems
financial results within our Products Pipelines business segment disclosures
for all periods presented in this discussion and analysis. This decision was
based on the way our management organizes segments internally to make operating
decisions and assess performance. We do not expect the impact of the
discontinued operations to materially affect our overall business, financial
position, results of operations or cash flows. For information on our
reconciliation of segment information with our consolidated general-purpose
financial statements, see Note 15 to our consolidated financial statements
included elsewhere in this report.

Combining
all of the segments operations, while revenues from refined petroleum products
deliveries increased 6.2% in 2007, compared to last year, total refined
products delivery volumes decreased 0.4%. Compared to last year, gasoline
delivery volumes decreased 3.2% (primarily due to Plantation), while diesel and
jet fuel volumes were up 3.7% and 4.7%, respectively. Excluding Plantation,
which continued to be impacted by a competing pipeline that began service in
mid-2006, total refined products delivery volumes increased by 0.8% in 2007,
when compared to 2006. Volumes on our Pacific operations and our Central Florida
pipelines were up 1% and 2%, respectively, in 2007, and while natural gas
liquids delivery volumes were down in 2007 versus 2006, revenues were up
substantially due to our increased ownership in the Cochin pipeline system.

The
$6.4 million (1%) decrease in earnings before depreciation, depletion and
amortization expenses in 2006, when compared to 2005, was largely due to a
combined decrease in earnings of $24.2 million in 2006due to incremental
pipeline maintenance expenses recognized in the last half of the year.
Beginning in the third quarter of 2006, the refined petroleum products
pipelines and associated terminal operations included within our Products
Pipelines segment (including Plantation Pipe Line Company, our 51%-owned equity
investee) began recognizing certain costs incurred as part of their pipeline
integrity management program as maintenance expense in the period incurred, and
in addition, recorded an expense for costs previously capitalized during the
first six months of 2006. Combined, this change reduced the segments earnings
before depreciation, depletion and amortization expenses by $24.2 million in
2006increasing maintenance expenses by $20.1 million, decreasing earnings from
equity investments by $6.6 million, and decreasing income tax expenses by $2.5
million.

Pipeline
integrity costs encompass those costs incurred as part of an overall pipeline
integrity management program, which is a process for assessing and mitigating
pipeline risks in order to reduce both the likelihood and consequences of
incidents. Our pipeline integrity program is designed to provide our management
the information needed to effectively allocate resources for appropriate
prevention, detection and mitigation activities.

58

---



The
remaining $17.8 million (4%) increase in earnings before depreciation,
depletion and amortization expenses in 2006 compared with 2005, primarily
consisted of the following items:

| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | a $4.9 million (15%)
  increase from our Southeast refined products terminal operations, driven by
  higher liquids throughput volumes at higher rates, relative to 2005, and
  higher margins from ethanol blending and sales activities;                                                                                                                                                                                                                                                                                                        
| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   
| |  | a $4.1 million (1%)
  increase from our combined Pacific and CALNEV Pipeline operations, primarily due
  to a $22.6 million (6%) increase in operating revenues, which more than
  offset an $18.3 million (18%) increase in combined operating expenses. The
  increase in operating revenues consisted of a $14.7 million (5%) increase
  from refined products deliveries and a $7.9 million (8%) increase from
  terminal and other fee revenue. The increase in operating expenses was
  primarily due to higher fuel and power expenses; and
| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   
| |  | a $3.7 million (12%)
  increase from our Central Florida Pipeline, mainly due to higher product
  delivery revenues in 2006 driven by higher average tariff and terminal rates.                                                                                                                                                                                                                                                                                                                                                                   

Combining
all of the segments operations, while total delivery volumes of refined
petroleum products decreased 0.8% in 2006 compared to 2005, total delivery
volumes from our Pacific operations were up 1.7% compared to 2005, due in part
to the East Line expansion which was in service for the last seven months of
2006. The expansion project substantially increased pipeline capacity from El
Paso, Texas to Tucson and Phoenix, Arizona. In addition, our CALNEV Pipeline
delivery volumes were up 4.2% in 2006 versus 2005, due primarily to strong
demand from the Southern California and Las Vegas, Nevada markets. The overall
decrease in year-to-year segment deliveries of refined petroleum products was
largely related to a 6.8% drop in volumes from the Plantation Pipeline in 2006,
as described above.

Natural Gas Pipelines

|                                                                                                                            |  |                                            |          |      |   |          |   |   |          |  
|--------------------------------------------------------------------------------------------------------------------------- |  | ------------------------------------------ | -------- | ---- | - | -------- | - | - | -------- | -
|                                                                                                                            |  | Year Ended December 31,                    |         
|                                                                                                                            |  |                                            |         
|                                                                                                                            |  | 2007                                       |          | 2006 |   | 2005     |  
|                                                                                                                            |  |                                            |          |      |   |          |  
|                                                                                                                            |  | (In millions, except operating statistics) |         
|Revenues                                                                                                                    |  | $                                          | 6,466.5  |      | $ | 6,577.7  |   | $ | 7,718.4  |  
|Operating expenses(a)                                                                                                       |  |                                            | (5,882.9 | )    |   | (6,057.8 | ) |   | (7,255.0 | )
|Other income(b)                                                                                                             |  |                                            | 3.2      |      |   | 15.1     |   |   |         |  
|Earnings from equity
investments(c)                                                                                         |  |                                            | 19.2     |      |   | 40.5     |   |   | 36.8     |  
|Interest income and Other,
net-income
  (expense)                                                                           |  |                                            | 0.2      |      |   | 0.7      |   |   | 2.7      |  
|Income tax benefit
(expense)                                                                                                |  |                                            | (6.0     | )    |   | (1.4     | ) |   | (2.6     | )
|                                                                                                                            |  |                                            |          |      |   |          |   |   |          |  
|Earnings
before depreciation, depletion and
  amortization 
  expense and amortization of excess cost of equity investments |  | $                                          | 600.2    |      | $ | 574.8    |   | $ | 500.3    |  
|                                                                                                                            |  |                                            |          |      |   |          |   |   |          |  
|                                                                                                                            |  |                                            |          |      |   |          |   |   |          |  
|Natural gas transport volumes
(Trillion
  Btus)(d)                                                                          |  |                                            | 1,577.3  |      |   | 1,440.9  |   |   | 1,317.9  |  
|                                                                                                                            |  |                                            |          |      |   |          |   |   |          |  
|Natural gas sales volumes
(Trillion
  Btus)(e)                                                                              |  |                                            | 865.5    |      |   | 909.3    |   |   | 924.6    |  
|                                                                                                                            |  |                                            |          |      |   |          |   |   |          |  



---

|    |                                                                                                                                                                                                                                                                                                                                                                                
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(a) | 2007, 2006
  and 2005 amounts include a $0.4 million decrease in expense, a $1.5 million
  increase in expense and a $0.1 million decrease in expense, respectively,
  associated with environmental liability adjustments. 2006 amount also
  includes a $6.3 million reduction in expense due to the release of a reserve
  related to a natural gas purchase/sales contract.
|    |                                                                                                                                                                                                                                                                                                                                                                                
|(b) | 2006 amount
  represents a $15.1 million gain from the combined sale of our Douglas natural
  gas gathering system and Painter Unit fractionation facility.                                                                                                                                                                                                                    
|    |                                                                                                                                                                                                                                                                                                                                                                                
|(c) | 2007 amount
  includes an expense of $1.0 million reflecting our portion of a loss from the
  early extinguishment of debt by Red Cedar Gathering Company.                                                                                                                                                                                                                     
|    |                                                                                                                                                                                                                                                                                                                                                                                
|(d) | Includes
  Rocky Mountain pipeline group and Texas intrastate natural gas pipeline group
  pipeline volumes.                                                                                                                                                                                                                                                                   
|    |                                                                                                                                                                                                                                                                                                                                                                                
|(e) | Represents
  Texas intrastate natural gas pipeline group.                                                                                                                                                                                                                                                                                                                      

Our
Natural Gas Pipelines segments primary businesses involve marketing,
transporting, storing, gathering, treating and processing natural gas through
both intrastate and interstate pipeline systems and related facilities.
Combined, the certain items described in the footnotes to the table above
decreased earnings before depreciation, depletion and amortization by $20.5
million in 2007, relative to 2006, and increased earnings before depreciation,
depletion and amortization by $19.8 million in 2006, relative to 2005.

59

---



Following
is information related to the remaining increases and decreases in the
segments (i) earnings before depreciation, depletion and amortization expenses
(EBDA); and (ii) operating revenues in both 2007 and 2006, when compared to the
respective prior year:

|                                                                 |  |                                    |       |                               |  |     |    |   |        |   |  |     |   
|---------------------------------------------------------------- |  | ---------------------------------- | ----- | ----------------------------- |  | --- | -- | - | ------ | - |  | --- | --
|Year Ended December 31, 2007 versus Year Ended December 31,
2006 | 
|                                                                 | 
|                                                                 |  | EBDA
 increase/(decrease)          |       | Revenues
 increase/(decrease) | 
|                                                                 |  |                                    |       |                               | 
|                                                                 |  | (In
 millions, except percentages) |      
|Texas
 Intrastate Natural Gas Pipeline Group                     |  | $                                  | 57.0  |                               |  | 19  | %  | $ | (142.2 | ) |  | (2  | )%
|Casper and
 Douglas gas processing                               |  |                                    | 8.6   |                               |  | 67  | %  |   | 5.6    |   |  | 6   | % 
|Rocky
 Mountain Pipeline Group                                   |  |                                    | (11.6 | )                             |  | (6  | )% |   | 29.0   |   |  | 10  | % 
|Red Cedar
 Gathering Company                                     |  |                                    | (7.4  | )                             |  | (20 | )% |   |       |   |  |    |   
|All others                                                       |  |                                    | (0.7  | )                             |  | (15 | )% |   | (3.8   | ) |  | (94 | )%
|Intrasegment
 Eliminations                                       |  |                                    |      |                               |  |    |    |   | 0.2    |   |  | 11  | % 
|                                                                 |  |                                    |       |                               |  |     |    |   |        |   |  |     |   
|Total Natural
Gas Pipelines                                      |  | $                                  | 45.9  |                               |  | 8   | %  | $ | (111.2 | ) |  | (2  | )%
|                                                                 |  |                                    |       |                               |  |     |    |   |        |   |  |     |   

|                                                                 |  |                                    |      |                               |  |     |    |   |          |   |  |     |   
|---------------------------------------------------------------- |  | ---------------------------------- | ---- | ----------------------------- |  | --- | -- | - | -------- | - |  | --- | --
|Year Ended December 31, 2006 versus Year Ended December 31,
2005 | 
|                                                                 | 
|                                                                 |  | EBDA
 Increase/(decrease)          |      | Revenues
 increase/(decrease) | 
|                                                                 |  |                                    |      |                               | 
|                                                                 |  | (In
 millions, except percentages) |     
|Texas
 Intrastate Natural Gas Pipeline Group                     |  | $                                  | 34.6 |                               |  | 13  | %  | $ | (1,165.7 | ) |  | (16 | )%
|Rocky
 Mountain Pipeline Group                                   |  |                                    | 14.3 |                               |  | 8   | %  |   | 27.9     |   |  | 11  | % 
|Red Cedar
 Gathering Company                                     |  |                                    | 4.3  |                               |  | 13  | %  |   |         |   |  |    |   
|Casper and
 Douglas gas processing                               |  |                                    | 2.9  |                               |  | 30  | %  |   | (6.4     | ) |  | (6  | )%
|All others                                                       |  |                                    | (1.4 | )                             |  | (21 | )% |   | 2.5      |   |  | 167 | % 
|Intrasegment
 Eliminations                                       |  |                                    |     |                               |  |    |    |   | 1.0      |   |  | 39  | % 
|                                                                 |  |                                    |      |                               |  |     |    |   |          |   |  |     |   
|Total Natural
Gas Pipelines                                      |  | $                                  | 54.7 |                               |  | 11  | %  | $ | (1,140.7 | ) |  | (15 | )%
|                                                                 |  |                                    |      |                               |  |     |    |   |          |   |  |     |   

The
segments overall increases in earnings before depreciation, depletion and
amortization expenses in both 2007 and 2006 were driven by strong
year-over-year performances from our Texas intrastate natural gas pipeline
group, which includes the operations of the following four natural gas pipeline
systems: Kinder Morgan Tejas (including Kinder Morgan Border Pipeline), Kinder
Morgan Texas Pipeline, Kinder Morgan North Texas Pipeline and our
Mier-Monterrey Mexico Pipeline. Collectively, our Texas intrastate group serves
the Texas Gulf Coast region by transporting, buying, selling, processing,
treating and storing natural gas from multiple onshore and offshore supply
sources.

The
higher earnings in both 2007 and 2006, when compared to the respective prior
years, were primarily due to higher sales margins on renewal and incremental
contracts, increased transportation revenue from higher volumes and rates,
greater value from natural gas storage activities, and higher natural gas processing
margins. Our Texas intrastate natural gas pipeline group also benefited, in
2007, from higher sales of cushion gas, due to the termination of a storage
facility lease, and from incremental natural gas storage revenues, due to a
long-term contract with one of its largest customers that became effective
April 1, 2007. Although natural gas sales volumes were down almost 5% in 2007
compared to 2006, natural gas transport volumes on our Texas intrastate systems
increased 21% in 2007 and 5% in 2006, resulting in higher year-over-year
transportation revenues. Because the group also buys and sells natural gas,
the variances from period to period in both segment revenues and segment
operating expenses (which include natural gas costs of sales) are due to changes
in our intrastate groups average prices and volumes for natural gas purchased
and sold.

The
increase in earnings from our Casper and Douglas natural gas processing
operations in 2007, when compared to 2006, was driven by an overall 6% increase
in operating revenues. The increase was primarily attributable to higher
natural gas liquids sales revenues, due to increases in both prices and volume.
The 2006 increase in earnings was primarily related to incremental earnings
associated with favorable hedge settlements from our natural gas gathering and
processing operations. We benefited from comparative differences in hedge
settlements associated with the rolling-off of older low price crude oil and
propane positions at December 31, 2005.

60

---



The
decrease in earnings in 2007 from our Rocky Mountain interstate natural gas
pipeline group, which is comprised of Kinder Morgan Interstate Gas Transmission
LLC, Trailblazer Pipeline Company LLC, TransColorado Gas Transmission Company
LLC, and our current 51% equity investment in Rockies Express Pipeline LLC,
resulted primarily from a $12.6 million decrease in equity earnings from our
investment in Rockies Express. The decrease in earnings from Rockies Express,
which began interim service in February 2006, reflected lower net income due
primarily to incremental depreciation and interest expense allocable to a
segment of the project that was placed in service in February 2007 and, until
the completion of the Rockies Express-West project, had limited natural gas
reservation revenues and volumes. Rockies Express-West is a 713-mile, 42-inch
diameter natural gas pipeline that extends eastward from the Cheyenne Hub in
Weld County, Colorado to Audrain County, Missouri. It has the capacity to
transport up to 1.5 billion cubic feet of natural gas per day and it began
interim service for up to 1.4 billion cubic feet per day on approximately 500
miles of line on January 12, 2008. Rockies Express-West is expected to become
fully operational in mid-March 2008.

The
$14.3 million (8%) increase in earnings in 2006, relative to 2005, from our
Rocky Mountain interstate natural gas pipeline group was driven by a $10.2
million (10%) increase in earnings from our Kinder Morgan Interstate Gas
Transmission system and a $3.8 million (10%) increase from TransColorado
Pipeline. The increase from KMIGT was due largely to higher revenues earned in
2006 from both operational sales of natural gas and natural gas park and loan
services. KMIGTs operational gas sales are primarily made possible by its
collection of fuel in-kind pursuant to its transportation tariffs and recovery
of storage cushion gas volumes. The increase from TransColorado was largely due
to higher natural gas transmission revenues earned in 2006 compared to 2005,
chiefly related to higher natural gas delivery volumes resulting from both
system improvements and the successful negotiation of incremental firm
transportation contracts. The pipeline system improvements were associated with
an expansion, completed since the end of the first quarter of 2005, on the
northern portion of the pipeline.

Both
the drop, in 2007, and the increase, in 2006, in earnings before depreciation,
depletion and amortization from our 49% equity investment in the Red Cedar
Gathering Company were mainly due to higher prices on incremental sales of
excess fuel gas and to higher natural gas gathering revenues in 2006, relative
to both 2007 and 2005.

CO2

|                                                                                                                        |  |                                             |   |        |   |      |  |   |        |   |  |  |   |        |   | 
|----------------------------------------------------------------------------------------------------------------------- |  | ------------------------------------------- | - | ------ | - | ---- |  | - | ------ | - |  |  | - | ------ | - | 
|                                                                                                                        |  | Year Ended
 December 31,                    |  
|                                                                                                                        |  |                                             |  
|                                                                                                                        |  | 2007                                        |   | 2006   |   | 2005 | 
|                                                                                                                        |  |                                             |   |        |   |      | 
|                                                                                                                        |  | (In
 millions, except operating statistics) |  
|Revenues(a)                                                                                                             |  |                                             | $ | 824.1  |   |      |  | $ | 736.5  |   |  |  | $ | 657.6  |   | 
|Operating expenses(b)                                                                                                   |  |                                             |   | (304.2 | ) |      |  |   | (268.1 | ) |  |  |   | (212.6 | ) | 
|Other income                                                                                                            |  |                                             |   |       |   |      |  |   |       |   |  |  |   |       |   | 
|Earnings from equity
investments                                                                                        |  |                                             |   | 19.2   |   |      |  |   | 19.2   |   |  |  |   | 26.3   |   | 
|Other, net-income
(expense)                                                                                             |  |                                             |   |       |   |      |  |   | 0.8    |   |  |  |   |       |   | 
|Income tax benefit
(expense)                                                                                            |  |                                             |   | (2.1   | ) |      |  |   | (0.2   | ) |  |  |   | (0.4   | ) | 
|                                                                                                                        |  |                                             |   |        |   |      |  |   |        |   |  |  |   |        |   | 
|Earnings before depreciation,
depletion and
 amortization expense and amortization of excess cost of equity investments |  |                                             | $ | 537.0  |   |      |  | $ | 488.2  |   |  |  | $ | 470.9  |   | 
|                                                                                                                        |  |                                             |   |        |   |      |  |   |        |   |  |  |   |        |   | 
|                                                                                                                       
|Carbon dioxide delivery volumes
(Bcf)(c)                                                                                |  |                                             |   | 637.3  |   |      |  |   | 669.2  |   |  |  |   | 649.3  |   | 
|                                                                                                                        |  |                                             |   |        |   |      |  |   |        |   |  |  |   |        |   | 
|SACROC oil production
(gross)(MBbl/d)(d)                                                                                |  |                                             |   | 27.6   |   |      |  |   | 30.8   |   |  |  |   | 32.1   |   | 
|                                                                                                                        |  |                                             |   |        |   |      |  |   |        |   |  |  |   |        |   | 
|SACROC oil production
(net)(MBbl/d)(e)                                                                                  |  |                                             |   | 23.0   |   |      |  |   | 25.7   |   |  |  |   | 26.7   |   | 
|                                                                                                                        |  |                                             |   |        |   |      |  |   |        |   |  |  |   |        |   | 
|Yates oil production
(gross)(MBbl/d)(d)                                                                                 |  |                                             |   | 27.0   |   |      |  |   | 26.1   |   |  |  |   | 24.2   |   | 
|                                                                                                                        |  |                                             |   |        |   |      |  |   |        |   |  |  |   |        |   | 
|Yates oil production
(net)(MBbl/d)(e)                                                                                   |  |                                             |   | 12.0   |   |      |  |   | 11.6   |   |  |  |   | 10.8   |   | 
|                                                                                                                        |  |                                             |   |        |   |      |  |   |        |   |  |  |   |        |   | 
|Natural gas liquids sales volumes
 (net)(MBbl/d)(e)                                                                     |  |                                             |   | 9.6    |   |      |  |   | 8.9    |   |  |  |   | 9.4    |   | 
|                                                                                                                        |  |                                             |   |        |   |      |  |   |        |   |  |  |   |        |   | 
|Realized weighted average oil
price per
 Bbl(f)(g)                                                                      |  |                                             | $ | 36.05  |   |      |  | $ | 31.42  |   |  |  | $ | 27.36  |   | 
|                                                                                                                        |  |                                             |   |        |   |      |  |   |        |   |  |  |   |        |   | 
|Realized weighted average
natural gas
 liquids price per Bbl(g)(h)                                                      |  |                                             | $ | 52.91  |   |      |  | $ | 43.90  |   |  |  | $ | 38.98  |   | 
|                                                                                                                        |  |                                             |   |        |   |      |  |   |        |   |  |  |   |        |   | 

|    |                                                                                                                                                         
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|   
|(a) | 2006 amount
 includes a $1.8 million loss (from a decrease in revenues) on derivative
 contracts used to hedge forecasted crude oil sales.              
|    |                                                                                                                                                         
|(b) | 2007 and 2005 amounts include increases in expense associated with environmental
liability
 adjustments of $0.2 million and
 $0.3 million, respectively.

61

---



|    |                                                                                                                                                                              
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(c) | Includes
 Cortez, Central Basin, Canyon Reef Carriers, Centerline and Pecos pipeline
 volumes.                                                                               
|    |                                                                                                                                                                              
|(d) | Represents
 100% of the production from the field. We own an approximate 97% working
 interest in the SACROC unit and an approximate 50% working interest in the
 Yates unit.
|    |                                                                                                                                                                              
|(e) | Net to
 Kinder Morgan, after royalties and outside working interests.                                                                                                        
|    |                                                                                                                                                                              
|(f) | Includes all
 Kinder Morgan crude oil production properties.                                                                                                                 
|    |                                                                                                                                                                              
|(g) | Hedge
 gains/losses for crude oil and natural gas liquids are included with crude
 oil.                                                                                      
|    |                                                                                                                                                                              
|(h) | Includes
 production attributable to leasehold ownership and production attributable to
 our ownership in processing plants and third party processing agreements.           

Our CO2
segment consists of Kinder Morgan CO2 Company, L.P. and its
consolidated affiliates. The segments primary businesses involve the
production, marketing and transportation of both carbon dioxide (commonly
called CO2) and crude oil, and the production and marketing of
natural gas and natural gas liquids.

Combined,
the certain items described in the footnotes to the table above increased
earnings before depreciation, depletion and amortization by $1.6 million in
2007, relative to 2006, and decreased earnings before depreciation, depletion
and amortization by $1.5 million in 2006, relative to 2005. For each of the
segments two primary businesses, the following is information related to the
remaining year-to-year increases and decreases in the segments (i) earnings
before depreciation, depletion and amortization (EBDA); and (ii) operating
revenues:

Year Ended December 31, 2007 versus Year Ended December 31, 2006EBDA
        
        
        
        Revenuesincrease/(decrease)
        
        
        
        increase/(decrease)(In millions, except percentages)Sales and Transportation Activities
        
        $
        (9.3
        )
        (5
        )%
        
        
        $
        (8.8
        )
        (4
        )%Oil and Gas Producing Activities
        
        
        56.5
        
        19
        %
        
        
        
        81.6
        
        14
        %Intrasegment Eliminations
        
        
        
        
        
        
        
        
        
        13.0
        
        21
        %Total CO2
        
        $
        47.2
        
        10
        %
        
        
        $
        85.8
        
        12
        %








Year Ended December 31, 2006 versus Year Ended December 31, 2005EBDA
        
        
        
        Revenuesincrease/(decrease)
        
        
        
        increase/(decrease)(In millions, except percentages)Sales and Transportation Activities
        
        $
        24.4
        
        15
        %
        
        
        $
        35.78
        
        22
        %Oil and Gas Producing Activities
        
        
        (5.6
        )
        (2
        )%
        
        
        
        57.1
        
        10
        %Intrasegment Eliminations
        
        
        
        
        
        
        
        
        
        (12.1
        )
        (25
        )%Total CO2
        
        $
        18.8
        
        4
        %
        
        
        $
        80.7
        
        12
        %


The
overall $47.2 million (10%) increase in segment earnings before depreciation,
depletion and amortization expenses in 2007 versus 2006 was driven by higher
earnings from the segments oil and gas producing activities, which include its
ownership interests in oil-producing fields and natural gas processing plants.
The increase was largely due to higher oil production at the Yates oil field
unit, higher realized average oil prices in 2007 relative to 2006, and higher
earnings from natural gas liquids salesdue largely to increased recoveries at
the Snyder, Texas gas plant and to an increase in our realized weighted average
price per barrel.

The
year-to-year decrease in earnings before depreciation, depletion and
amortization from the segments sales and transportation activities was
primarily due to a decrease in carbon dioxide sales revenues, resulting mainly
from lower average prices for carbon dioxide in 2007, and partly from a 3% drop
in average carbon dioxide delivery volumes. The segments average price
received for all carbon dioxide sales decreased 9% in 2007, when compared to
2006. The decrease was mainly attributable to the expiration of a significantly
high-priced sales contract in December 2006.

The
segments $18.8 million (4%) increase in earnings before depreciation,
depletion and amortization in 2006 compared with 2005 was driven by higher
earnings from the segments carbon dioxide sales and transportation activities,
largely due to higher revenuesfrom both carbon dioxide sales and deliveries,
and from crude oil pipeline transportation. The overall increase in segment
earnings before depreciation, depletion and amortization was partly offset by
lower earnings from oil and gas producing activities and by lower equity
earnings from the segments 50% ownership interest in Cortez Pipeline Company.

62

---



The
decrease in earnings from oil and gas producing activities in 2006 compared
with 2005 was primarily due to higher combined operating expenses and to the
previously disclosed drop in crude oil production at the SACROC oil field unit,
discussed below. The higher operating expenses included higher field operating
and maintenance expenses (including well workover expenses), higher property
and severance taxes, and higher fuel and power expenses. The increases in
expenses more than offset higher overall crude oil and natural gas plant
product sales revenues, which increased primarily from higher realized sales
prices and partly from higher crude oil production at the Yates field unit.

The
overall increases in segment revenues in 2007 and 2006, when compared to
respective prior years, were mainly due to higher revenues from the segments
oil and gas producing activities crude oil sales and natural gas liquids
sales. Combined, crude oil and plant product sales revenues increased $77.9
million (14%) in 2007 compared to 2006, and $63.9 million (12%) in 2006
compared to 2005.

The
year-over-year increases in revenues from the sales of natural gas liquids were
driven by favorable sales price variancesour realized weighted average price per
barrel increased 21% in 2007 and 13% in 2006, when compared to the respective
prior year. The year-over-year increases in revenues from the sales of crude
oil reflected annual increases in our realized weighted average price per
barrel of 15% in both 2007 and 2006, and although total crude oil sales volumes
were relatively flat in 2006 compared to 2005, sales volumes decreased 6% in
2007 compared to 2006. Average gross oil production for 2007 was
27.0 thousand barrels per day at the Yates unit, up 3% from 2006, and 27.6
thousand barrels per day at SACROC, a decline of 10% versus 2006.

The
year-to-year decline in crude oil production at the SACROC field unit is
attributable to lower observed recoveries from recent project areas and due to
an intentional slow down in development pace given this reduction in
recoveries. For more information on our ownership interests in the net
quantities of proved oil and gas reserves and our measures of discounted future
net cash flows from oil and gas reserves, please see Note 20 to our consolidated
financial statements included elsewhere in this report.

In
addition, because our CO2 segment is exposed to commodity price risk
related to the price volatility of crude oil and natural gas liquids, we
mitigate this risk through a long-term hedging strategy that is intended to
generate more stable realized prices by using derivative contracts as hedges to
the exposure of fluctuating expected future cash flows produced by changes in
commodity sales prices. All of our hedge gains and losses for crude oil and
natural gas liquids are included in our realized average price for oil. Had we
not used energy derivative contracts to transfer commodity price risk, our
crude oil sales prices would have averaged $69.63 per barrel in 2007, $63.27
per barrel in 2006 and $54.45 per barrel in 2005. For more information on our
hedging activities, see Note 14 to our consolidated financial statements
included elsewhere in this report.

Terminals

|                                                                                                                        |  |                                             |   |        |   |      |  |   |        |   |  |  |   |        |   | 
|----------------------------------------------------------------------------------------------------------------------- |  | ------------------------------------------- | - | ------ | - | ---- |  | - | ------ | - |  |  | - | ------ | - | 
|                                                                                                                        |  | Year Ended
 December 31,                    |  
|                                                                                                                        |  |                                             |  
|                                                                                                                        |  | 2007                                        |   | 2006   |   | 2005 | 
|                                                                                                                        |  |                                             |   |        |   |      | 
|                                                                                                                        |  | (In
 millions, except operating statistics) |  
|Revenues                                                                                                                |  |                                             | $ | 963.7  |   |      |  | $ | 864.8  |   |  |  | $ | 699.3  |   | 
|Operating expenses(a)                                                                                                   |  |                                             |   | (536.4 | ) |      |  |   | (461.9 | ) |  |  |   | (373.4 | ) | 
|Other income(b)                                                                                                         |  |                                             |   | 6.3    |   |      |  |   | 15.2   |   |  |  |   |       |   | 
|Earnings from equity
investments                                                                                        |  |                                             |   | 0.6    |   |      |  |   | 0.2    |   |  |  |   | 0.1    |   | 
|Other, net-income
(expense)                                                                                             |  |                                             |   | 1.0    |   |      |  |   | 2.1    |   |  |  |   | (0.2   | ) | 
|Income tax benefit
(expense)(c)                                                                                         |  |                                             |   | (19.2  | ) |      |  |   | (12.3  | ) |  |  |   | (11.2  | ) | 
|                                                                                                                        |  |                                             |   |        |   |      |  |   |        |   |  |  |   |        |   | 
|Earnings before depreciation,
depletion and
 amortization expense and amortization of excess cost of equity investments |  |                                             | $ | 416.0  |   |      |  | $ | 408.1  |   |  |  | $ | 314.6  |   | 
|                                                                                                                        |  |                                             |   |        |   |      |  |   |        |   |  |  |   |        |   | 
|                                                                                                                        |  |                                             |   |        |   |      |  |   |        |   |  |  |   |        |   | 
|Bulk transload tonnage
(MMtons)(d)                                                                                      |  |                                             |   | 87.1   |   |      |  |   | 95.1   |   |  |  |   | 85.5   |   | 
|                                                                                                                        |  |                                             |   |        |   |      |  |   |        |   |  |  |   |        |   | 
|Liquids leaseable capacity
(MMBbl)                                                                                      |  |                                             |   | 47.5   |   |      |  |   | 43.5   |   |  |  |   | 42.4   |   | 
|                                                                                                                        |  |                                             |   |        |   |      |  |   |        |   |  |  |   |        |   | 
|Liquids utilization %                                                                                                   |  |                                             |   | 95.9   | % |      |  |   | 96.3   | % |  |  |   | 95.4   | % | 
|                                                                                                                        |  |                                             |   |        |   |      |  |   |        |   |  |  |   |        |   | 

63

---



|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(a) | 2007 and 2005 amounts include increases in expense associated with environmental
liability
 adjustments of $2.0 million and
 $3.5 million, respectively.2007 amount also includes a $25.0
 million increase in expense from the settlement of certain litigation matters
 related to our Cora coal terminal, and a $1.2 million increase in expense
 associated with legal liability adjustments. 2006 amount includes a $2.8 million increase in expense related to
 hurricane clean-up and repair activities.
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                
|(b) | 2007 and 2006 amounts
 include increases in income of $1.8 million and $15.2 million, respectively,
 from property casualty gains associated with the 2005 hurricane season.                                                                                                                                                                                                                                                                                                                                   
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                
|(c) | 2006 amount
 includes a $1.1 million increase in expense associated with hurricane
 expenses and casualty gain.                                                                                                                                                                                                                                                                                                                                                                                                
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                
|(d) | Volumes for
 acquired terminals are included for 2007 and 2006.                                                                                                                                                                                                                                                                                                                                                                                                                                                

Our
Terminals segment includes the operations of our petroleum, chemical and other
liquids terminal facilities (other than those included in our Products
Pipelines segment), and all of our coal, petroleum coke, fertilizer, steel,
ores and other dry-bulk material services facilities.

Combined,
the certain items described in the footnotes to the table above decreased
earnings before depreciation, depletion and amortization by $37.7 million in
2007, relative to 2006, and increased earnings before depreciation, depletion
and amortization by $14.8 million in 2006, relative to 2005. The segments
remaining $45.6 million (11%) increase in earnings before depreciation,
depletion and amortization expenses in 2007 compared with 2006, and its
remaining $78.7 million (25%) increase in 2006 compared to 2005, were driven by
a combination of internal expansions and strategic acquisitions completed since
the end of 2005. We have made and continue to seek terminal acquisitions in
order to gain access to new markets, to complement and/or enlarge our existing
terminal operations, and to benefit from the economies of scale resulting from
increases in storage, handling and throughput capacity.

In
2007, we invested approximately $158.9 million to acquire terminal assets and
equity investments, and our significant terminal acquisitions since the fourth
quarter of 2006 included the following:

| |   |                                                                                                                                                                                                                                                                                                                                                                                                                  
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | all of the
 membership interests of Transload Services, LLC, which provides material
 handling and steel processing services at 14 steel-related terminal
 facilities located in the Chicago metropolitan area and various cities in the
 United States, acquired November 20, 2006;                                                                                                                             
| |   |                                                                                                                                                                                                                                                                                                                                                                                                                  
| |  | all of the
 membership interests of Devco USA L.L.C., which includes a proprietary
 technology that transforms molten sulfur into solid pellets that are
 environmentally friendly and easier to transport, acquired December 1, 2006;                                                                                                                                                                           
| |   |                                                                                                                                                                                                                                                                                                                                                                                                                  
| |  | the
 Vancouver Wharves bulk marine terminal, which includes five deep-sea vessel
 berths and terminal assets located on the north shore of the Port of
 Vancouvers main harbor. The assets include significant rail infrastructure,
 dry bulk and liquid storage, and material handling systems, and were acquired
 May 30, 2007; and                                                                           
| |   |                                                                                                                                                                                                                                                                                                                                                                                                                  
| |  | the terminal
 assets and operations acquired from Marine Terminals, Inc., which are
 primarily involved in the handling and storage of steel and alloys and
 consist of two separate facilities located in Blytheville, Arkansas, and
 individual terminal facilities located in Decatur, Alabama, Hertford, North
 Carolina, and Berkley, South Carolina. The assets were acquired effective
 September 1, 2007.

Combined,
these operations accounted for incremental amounts of earnings before
depreciation, depletion and amortization of $31.2 million, revenues of $83.9
million, operating expenses of $53.2 million and equity earnings of $0.5
million, respectively, in 2007. All of the incremental amounts represent the
earnings, revenues and expenses from the acquired terminals operations during
the additional months of ownership in 2007, and do not include increases or
decreases during the same months we owned the assets in 2006.

In
2006, we also benefited significantly from the incremental contributions attributable to the bulk and
liquids terminal businesses we acquired during 2005 and 2006. In
addition to the two acquisitions acquired in the fourth quarter of 2006 and
referred to above, these acquisitions included the following significant
businesses:

| |   |                                                                                                                                  
| | - | ---------------------------------------------------------------------------------------------------------------------------------
| |  | our Texas
 Petcoke terminals, located in and around the Ports of Houston and Beaumont,
 Texas, acquired effective April 29, 2005;

64

---



| |   |                                                                                                                                                                                                                         
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | three
 terminals acquired separately in July 2005: our Kinder Morgan Staten Island
 terminal, a dry-bulk terminal located in Hawesville, Kentucky and a
 liquids/dry-bulk facility located in Blytheville, Arkansas; and
| |   |                                                                                                                                                                                                                         
| |  | all of the
 ownership interests in General Stevedores, L.P., which operates a break-bulk
 terminal facility located along the Houston Ship Channel, acquired effective
 July 31, 2005.                                  

Combined,
these terminal acquisitions accounted for incremental amounts of earnings
before depreciation, depletion and amortization of $33.5 million, revenues of
$68.8 million and operating expenses of $35.3 million, respectively, in 2006. A
majority of these increases in earnings, revenues and expenses were
attributable to the inclusion of our Texas petroleum coke terminals, which we
acquired from Trans-Global Solutions, Inc. on April 29, 2005 for an aggregate
consideration of approximately $247.2 million. The primary assets acquired
included facilities and railway equipment located at the Port of Houston, the
Port of Beaumont and the TGS Deepwater terminal located on the Houston Ship
Channel.

For
all other terminal operations (those owned during identical periods in both
2007 and 2006), earnings before depreciation, depletion and amortization
expenses increased $14.4 million (4%) in 2007, and $45.2 million (14%) in 2006,
when compared to the respective prior years. The increases in earnings
represent net changes in terminal results at various locations, but the
year-over-year increase in 2007 compared to 2006 was largely due to higher
earnings in 2007 from our two large Gulf Coast liquids terminal facilities
located along the Houston Ship Channel in Pasadena and Galena Park, Texas. The
two terminals continued to benefit from both recent expansions that have added
new liquids tank and truck loading rack capacity since 2006, and incremental
business from ethanol and biodiesel storage and transfer activity (for the
entire segment, our expansion projects and acquisitions completed since the end
of 2006 have increased our liquids terminals leaseable capacity by 9%, more
than offsetting a less than 1% drop in our overall utilization percentage).
Higher earnings in 2007 also resulted from (i) the combined operations of our
Argo and Chicago, Illinois liquids terminals, due to increased ethanol
throughput and incremental liquids storage and handling business; (ii) our
Texas Petcoke terminals, due largely to higher petroleum coke throughput
volumes at our Port of Houston facility; and (iii) our Pier IX bulk terminal,
located in Newport News, Virginia, largely due to a 19% year-to-year increase
in coal transfer volumes and higher rail incentives.

The
increase in earnings in 2006 compared to 2005 from terminals owned during both
years included higher earnings in 2006 from (i) our Pasadena and Galena Park
Gulf Coast liquids terminals, driven by higher revenues, in 2006, from new and
incremental customer agreements, additional liquids tank capacity from capital
expansions completed at our Pasadena terminal since the end of 2005, higher
truck loading rack service fees, higher ethanol throughput, and incremental
revenues from customer deficiency charges; (ii) our Shipyard River terminal,
located in Charleston, South Carolina, due to higher revenues from liquids
warehousing and coal and cement handling; (iii) our Texas Petcoke terminals,
mainly resulting from an increase in petroleum coke handling volumes; and (iv)
our Lower Mississippi River (Louisiana) terminals, primarily due to incremental
earnings from our Amory and DeLisle Mississippi bulk terminals. Our Amory
terminal began operations in July 2005. The higher earnings from our DeLisle
terminal, which was negatively impacted by hurricane damage in 2005, was
primarily due to higher bulk transfer revenues in 2006.

Trans
Mountain

|                                                                                                                           |  |                                             |   |         |   |      |  |   |       |   |  |  |   |   |  | 
|-------------------------------------------------------------------------------------------------------------------------- |  | ------------------------------------------- | - | ------- | - | ---- |  | - | ----- | - |  |  | - | - |  | 
|                                                                                                                           |  | Year Ended
 December 31,                    |  
|                                                                                                                           |  |                                             |  
|                                                                                                                           |  | 2007                                        |   | 2006(c) |   | 2005 | 
|                                                                                                                           |  |                                             |   |         |   |      | 
|                                                                                                                           |  | (In
 millions, except operating statistics) |  
|Revenues                                                                                                                   |  |                                             | $ | 160.8   |   |      |  | $ | 137.8 |   |  |  | $ |  |  | 
|Operating expenses                                                                                                         |  |                                             |   | (65.9   | ) |      |  |   | (53.3 | ) |  |  |   |  |  | 
|Other income
(expense)(a)                                                                                                  |  |                                             |   | (377.1  | ) |      |  |   | 0.9   |   |  |  |   |  |  | 
|Earnings from equity
investments                                                                                           |  |                                             |   |        |   |      |  |   |      |   |  |  |   |  |  | 
|Other, net-income
(expense)                                                                                                |  |                                             |   | 8.0     |   |      |  |   | 1.0   |   |  |  |   |  |  | 
|Income tax benefit
(expense)                                                                                               |  |                                             |   | (19.4   | ) |      |  |   | (9.9  | ) |  |  |   |  |  | 
|                                                                                                                           |  |                                             |   |         |   |      |  |   |       |   |  |  |   |   |  | 
|Earnings before depreciation,
depletion and
 amortization expense and amortization of excess cost of equity investments(b) |  |                                             | $ | (293.6  | ) |      |  | $ | 76.5  |   |  |  | $ |  |  | 
|                                                                                                                           |  |                                             |   |         |   |      |  |   |       |   |  |  |   |   |  | 
|                                                                                                                           |  |                                             |   |         |   |      |  |   |       |   |  |  |   |   |  | 
|Transport volumes
(MMBbl)                                                                                                  |  |                                             |   | 94.4    |   |      |  |   | 83.7  |   |  |  |   |  |  | 
|                                                                                                                           |  |                                             |   |         |   |      |  |   |       |   |  |  |   |   |  | 

65

---



|    |                                                                                                                                                                                
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(a) | 2007 amount
 represents a goodwill impairment expense recorded by Knight in the first
 quarter of 2007.                                                                        
|    |                                                                                                                                                                                
|(b) | 2007 amount
 includes losses of $349.2 million for periods prior to our acquisition date
 of April 30, 2007, and a $1.3 million decrease in income from an oil loss
 allowance.
|    |                                                                                                                                                                                
|(c) | 2006 amounts
 relate to periods prior to our acquisition date of April 30, 2007. See
 discussion below.                                                                        

Our
Trans Mountain segment includes the operations of the Trans Mountain Pipeline,
which we acquired from Knight effective April 30, 2007. Trans Mountain
transports crude oil and refined products from Edmonton, Alberta to marketing
terminals and refineries in British Columbia and the state of Washington. An
additional 35,000 barrel per day expansion that will increase capacity on the
pipeline to approximately 300,000 barrels per day is currently under
construction and is expected to be in service by late 2008.

According
to the provisions of generally accepted accounting principles that prescribe
the standards used to account for business combinations, due to the fact that
our acquisition of Trans Mountain from Knight represented a transfer of assets
between entities under common control, we initially recorded the assets and
liabilities of Trans Mountain transferred to us from Knight at their carrying
amounts in the accounts of Knight. Furthermore, our accompanying financial
statements included in this report, and the information in the table above,
reflect the results of operations for both 2007 and 2006 as though the transfer
of Trans Mountain from Knight had occurred at the beginning of the period
(January 1, 2006 for us).

After
taking into effect the certain items described in the footnotes to the table
above, the remaining increase in earnings before depreciation, depletion and
amortization in 2007 versus 2006 totaled $56.9 million, and related entirely to
our acquisition of Trans Mountain effective April 30, 2007.

Other

Year EndedDecember 31,
        
        
        Earnings2007
        
        2006
        
        
        increase/(decrease)(In millions-income (expense), except
percentages)General and administrative expenses(a)
        $
        (278.7
        )
        
        $
        (238.4
        )
        
        
        $
        (40.3
        )
        
        (17
        )%Interest expense, net of unallocable interest income(b)
        
        (395.8
        )
        
        
        (342.4
        )
        
        
        
        (53.4
        )
        
        (16
        )%Unallocable income tax benefit (expense)
        
        (4.6
        )
        
        
        
        
        
        
        
        (4.6
        )
        
        Minority interest(c)
        
        (7.0
        )
        
        
        (15.4
        )
        
        
        
        8.4
        
        
        55
        %Total interest and corporate administrative expenses
        $
        (686.1
        )
        
        $
        (596.2
        )
        
        
        $
        (89.9
        )
        
        (15
        )%








Year EndedDecember 31,
        
        
        Earnings2006
        
        2005
        
        
        increase/(decrease)(In millions-income (expense), except
percentages)General and administrative expenses(a)
        $
        (238.4
        )
        
        $
        (216.7
        )
        
        
        $
        (21.7
        )
        
        (10
        )%Interest expense, net of unallocable interest income(b)
        
        (342.4
        )
        
        
        (264.3
        )
        
        
        
        (78.1
        )
        
        (30
        )%Minority interest(c)
        
        (15.4
        )
        
        
        (7.3
        )
        
        
        
        (8.1
        )
        
        (111
        )%Total interest and corporate administrative expenses
        $
        (596.2
        )
        
        $
        (488.3
        )
        
        
        $
        (107.9
        )
        
        (22
        )%


|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(a) | 2007 amount
 includes (i) a $26.2 million increase in expense, allocated to us from
 Knight, associated with closing the going-private transaction. Knight Inc. was
 responsible for the payment of the costs resulting from this transaction;
 (ii) a $5.5 million expense related to Trans Mountain expenses for periods
 prior to our acquisition date of April 30, 2007; (iii) a $2.1 million expense
 due to the adjustment of certain insurance related liabilities; (iv) a $1.7
 million increase in expense associated with the 2005 hurricane season; (v) a
 $1.5 million expense for certain Trans Mountain acquisition costs; and (vi) a
 $0.8 million expense related to the cancellation of certain commercial
 insurance policies. 2006 amount includes Trans Mountain expenses of $18.8
 million, a $2.4 million increase in expense related to the cancellation of
 certain commercial insurance policies, and a $0.4 million decrease in expense
 related to the allocation of general and administrative expenses on hurricane
 related capital expenditures for the replacement and repair of assets. 2005
 amount includes a $25.0 million expense for a litigation settlement reached
 between us and a former joint venture partner on our Kinder Morgan Tejas
 natural gas pipeline system, a cumulative $8.4 million expense related to
 settlements of environmental matters at certain of our operating sites located
 in the state of California, and a $3.0 million decrease in expense related to
 proceeds received in connection with the settlement of claims in the Enron
 Corp. bankruptcy proceeding.
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         

66

---



|    |                                                                                                                                                                                                                                                                                                                                                                  
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(b) | 2007 amount includes a $2.4 million
 increase in expense related to imputed interest on our Cochin Pipeline
 acquisition, and Trans Mountain expenses of $1.2 million for periods prior to
 our acquisition date of April 30, 2007. 2006 amount includes Trans Mountain
 expenses of $6.3 million.                                                               
|    |                                                                                                                                                                                                                                                                                                                                                                  
|(c) | 2007 amount includes a $3.9 million
 decrease in expense, related to the minority interest effect from all of the
 2007 items listed in footnotes (a) and (b). 2006 amount includes a $3.5
 million increase in expense, primarily related to the minority interest
 effect from the property casualty insurance gain associated
 with the 2005 hurricane season.

Items not
attributable to any segment include general and administrative expenses,
unallocable interest income and income tax expense, interest expense and
minority interest. Our general and administrative expenses
include such items as salaries and employee-related expenses, payroll taxes,
insurance, office supplies and rentals, unallocated litigation and
environmental expenses, and shared corporate servicesincluding accounting,
information technology, human resources and legal services.

Compared
to 2006, the certain items described in footnote (a) to the tables above
increased our 2007 general and administrative expenses by $17.0 million. The
remaining $23.3 million (11%) increase in expenses was largely due to (i)
higher shared services expenses, which include legal, corporate secretary, tax,
information technology and other shared services; and (ii) higher payroll-related
expenses resulting from the acquisitions and incremental expansions we have
made since the end of 2006.

Compared
to 2005, the certain items described in footnote (a) decreased our 2006 general
and administrative expenses by $9.6 million. The remaining $31.3 million (17%)
increase in overall general and
administrative expenses in 2006 compared to 2005 was primarily due to higher
corporate service charges and higher corporate and employee-related insurance
expenses in 2006. The increase in corporate services was largely due to
higher corporate overhead expenses associated with the business operations we
acquired since the end of 2005. The increase in insurance expenses was partly
due to incremental expenses related to the cancellation of certain commercial
insurance polices, as well as to the overall variability in year-to-year
commercial property and medical insurance costs. Pursuant to certain provisions
that gave us the right to cancel certain commercial policies prior to maturity,
we took advantage of the opportunity to reinsure at lower rates.

Interest
expense, net of unallocable interest income, totaled $395.8 million in 2007,
$342.4 million in 2006 and $264.3 million in 2005. Compared to 2006, net
interest expense decreased $2.7 million in 2007 due to the items described in
footnote (b) to the tables above. The remaining $56.1 million (17%) increase in
expense in 2007 compared to 2006 was due to both a 4% increase in average
borrowing rates (the weighted average interest rate on all of our borrowings
was approximately 6.40% during 2007 and 6.18% during 2006) and a 17% increase
in average borrowings (excluding
the market value of interest rate swaps). The increase in average
borrowings was mainly due to capital spending in 2007, and the
acquisition of external assets and businesses since the end of 2006.

We incurred
incremental net interest expense of $6.3 million in 2006 due to the inclusion
of Trans Mountain, and the remaining $71.8 million (27%) increase in expense in
2006 compared to 2005 was due to both higher average debt levels
and higher effective interest rates. In 2006, average borrowings increased 10%
and the weighted average interest rate on all of our borrowings increased 17%,
when compared to 2005 (the weighted average
interest rate on all of our borrowings was approximately6.18% during 2006 and 5.30%
during 2005).

Generally,
we initially fund both our capital spending (including payments for pipeline
project construction costs) and our acquisition outlays from borrowings under
our commercial paper program. From time to time, we issue senior notes in order
to refinance our commercial paper borrowings. For more information on our
capital expansion and acquisition expenditures, see Liquidity and Capital
ResourcesInvesting Activities.

The
year-to-year increases in our average borrowing rates in 2007 and 2006 reflect
a general rise in variable interest rates since the end of 2005. We use
interest rate swap agreements to help manage our interest rate risk. The swaps
are contractual agreements we enter into in order to transform a portion of the
underlying cash flows related to our long-term fixed rate debt securities into
variable rate debt in order to achieve our desired mix of fixed and variable
rate debt. However, in a period of rising interest rates, these swaps will
result in period-to-period increases in our interest expense. For more
information on our interest rate swaps, see Note 14 to our consolidated
financial statements, included elsewhere in this report.

67

---



Liquidity and Capital Resources

Capital
Structure

We
attempt to maintain a conservative overall capital structure, with a long-term
target mix of approximately 50% equity and 50% debt. In addition to our results
of operations, our debt and capital balances are affected by our financing
activities, as discussed below in Financing Activities. The following table
illustrates the sources of our invested capital (dollars in millions):

|                                                                                              |  |              |          |      |   |          |   |   |         |  
|--------------------------------------------------------------------------------------------- |  | ------------ | -------- | ---- | - | -------- | - | - | ------- | -
|                                                                                              |  | December 31, |         
|                                                                                              |  |              |         
|                                                                                              |  | 2007         |          | 2006 |   | 2005     |  
|                                                                                              |  |              |          |      |   |          |  
|Long-term
 debt, excluding market value of interest rate swaps                                |  | $            | 6,455.9  |      | $ | 4,384.3  |   | $ | 5,220.9 |  
|Minority interest                                                                             |  |              | 54.2     |      |   | 60.2     |   |   | 42.3    |  
|Partners capital, excluding
 accumulated other comprehensive loss                            |  |              | 5,712.3  |      |   | 5,814.4  |   |   | 4,693.5 |  
|                                                                                              |  |              |          |      |   |          |   |   |         |  
|Total
capitalization                                                                          |  |              | 12,222.4 |      |   | 10,258.9 |   |   | 9,956.7 |  
|Short-term debt, less cash and
 cash equivalents                                              |  |              | 551.3    |      |   | 1,352.4  |   |   | (12.1   | )
|                                                                                              |  |              |          |      |   |          |   |   |         |  
|Total invested
capital                                                                        |  | $            | 12,773.7 |      | $ | 11,611.3 |   | $ | 9,944.6 |  
|                                                                                              |  |              |          |      |   |          |   |   |         |  
|                                                                                              |  |              |          |      |   |          |   |   |         |  
|Capitalization:                                                                               |  |              |          |      |   |          |   |   |         |  
|Long-term debt,
excluding
 market value of interest rate swaps                                |  |              | 52.8     | %    |   | 42.7     | % |   | 52.4    | %
|Minority
interest                                                                             |  |              | 0.5      | %    |   | 0.6      | % |   | 0.4     | %
|Partners
capital, excluding
 accumulated other comprehensive loss                            |  |              | 46.7     | %    |   | 56.7     | % |   | 47.2    | %
|                                                                                              |  |              |          |      |   |          |   |   |         |  
|                                                                                              |  |              | 100.0    | %    |   | 100.0    | % |   | 100.0   | %
|                                                                                              |  |              |          |      |   |          |   |   |         |  
|Invested Capital:                                                                             |  |              |          |      |   |          |   |   |         |  
|Total debt,
less cash and cash
 equivalents and excluding market value of interest rate swaps |  |              | 54.9     | %    |   | 49.4     | % |   | 52.4    | %
|Partners
capital and minority
 interest, excluding accumulated other comprehensive loss      |  |              | 45.1     | %    |   | 50.6     | % |   | 47.6    | %
|                                                                                              |  |              |          |      |   |          |   |   |         |  
|                                                                                              |  |              | 100.0    | %    |   | 100.0    | % |   | 100.0   | %
|                                                                                              |  |              |          |      |   |          |   |   |         |  

Our
primary cash requirements, in addition to normal operating expenses, are debt
service, sustaining capital expenditures, expansion capital expenditures and
quarterly distributions to our common unitholders, Class B unitholders and
general partner. In addition to utilizing cash generated from operations, we could
meet our cash requirements for expansion capital expenditures through
borrowings under our credit facility, issuing short-term commercial paper,
long-term notes or additional common units or the proceeds from purchases of
additional i-units by KMR with the proceeds from issuances of KMR shares.

In
general, we expect to fund:

| |   |                                                                                                                                                                                                                                                                                                                                                                                             
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | cash
 distributions and sustaining capital expenditures with existing cash and cash
 flows from operating activities;                                                                                                                                                                                                                                                                       
| |   |                                                                                                                                                                                                                                                                                                                                                                                             
| |  | expansion
 capital expenditures and working capital deficits with retained cash
 (resulting from including i-units in the determination of cash distributions
 per unit but paying quarterly distributions on i-units in additional i-units
 rather than cash), additional borrowings, the issuance of additional common
 units or the proceeds from purchases of additional i-units by KMR;
| |   |                                                                                                                                                                                                                                                                                                                                                                                             
| |  | interest
 payments with cash flows from operating activities; and                                                                                                                                                                                                                                                                                                                           
| |   |                                                                                                                                                                                                                                                                                                                                                                                             
| |  | debt principal payments
 with additional borrowings, as such debt principal payments become due, or by
 the issuance of additional common units or the proceeds from purchases of
 additional i-units by KMR.                                                                                                                                                                               
| |   |                                                                                                                                                                                                                                                                                                                                                                                             

As
a publicly traded limited partnership, our common units are attractive
primarily to individual investors, although such investors represent a small
segment of the total equity capital market. We believe that some institutional
investors prefer shares of KMR over our common units due to tax and other
regulatory considerations. We are able to access this segment of the capital
market through KMRs purchases of i-units issued by us with the proceeds from
the sale of KMR shares to institutional investors.

68

---



As
part of our financial strategy, we try to maintain an investment-grade credit
rating, which involves, among other things, the issuance of additional limited
partner units in connection with our acquisitions and internal growth
activities in order to maintain acceptable financial ratios.

On May 30, 2006,
Standard & Poors Rating Services and Moodys Investors Service each placed
our ratings on credit watch pending the resolution of KMIs going-private
transaction. On January 5, 2007, in anticipation of the buyout closing, S&P
downgraded us one level to BBB and removed our rating from credit watch with
negative implications. Currently, our debt credit rating is still rated
BBB by S&P.
As
previously noted by Moodys in its credit opinion dated November 15, 2006, it
downgraded our credit rating from Baa1 to Baa2 on May 30, 2007, following the
closing of the going-private transaction. Additionally, our rating was
downgraded by Fitch Ratings from BBB+ to BBB on April 11, 2007.

Short-term
Liquidity

We
employ a centralized cash management program that essentially concentrates the
cash assets of our operating partnerships and their subsidiaries in joint
accounts for the purpose of providing financial flexibility and lowering the
cost of borrowing. Our centralized cash management program provides that funds
in excess of the daily needs of our operating partnerships and their
subsidiaries are concentrated, consolidated, or otherwise made available for
use by other entities within our consolidated group. We place no restrictions
on the ability to move cash between entities, payment of inter-company balances
or the ability to upstream dividends to parent companies other than
restrictions that may be contained in agreements governing the indebtedness of
those entities. However, our cash and the cash of our subsidiaries is not
concentrated into accounts of Knight or any company not in our consolidated
group of companies, and Knight has no rights with respect to our cash except as
permitted pursuant to our partnership agreement.

Furthermore,
certain of our operating subsidiaries are subject to FERC enacted reporting
requirements for oil and natural gas pipeline companies that participate in
cash management programs. FERC-regulated entities subject to these rules must,
among other things, place their cash management agreements in writing, maintain
current copies of the documents authorizing and supporting their cash
management agreements, and file documentation establishing the cash management
program with the FERC.

Our
principal sources of short-term liquidity are (i) our $1.85 billion five-year
senior unsecured revolving credit facility that matures August 18, 2010; (ii)
our $1.85 billion short-term commercial paper program (which is supported by
our bank credit facility, with the amount available for borrowing under our
credit facility being reduced by our outstanding commercial paper borrowings);
and (iii) cash from operations (discussed following).

Borrowings
under our five-year credit facility can be used for general partnership
purposes and as a backup for our commercial paper program. The facility can be
amended to allow for borrowings up to $2.1 billion. There were no borrowings
under our credit facility as of December 31, 2007. As of December 31, 2007, we
had $589.1 million of commercial paper outstanding.

We
provide for additional liquidity by maintaining a sizable amount of excess
borrowing capacity related to our commercial paper program and long-term
revolving credit facility. After reduction for our outstanding commercial paper
borrowings and letters of credit, the remaining available borrowing capacity
under our bank credit facility was $723.1 million as of December 31, 2007. As
of December 31, 2007, our outstanding short-term debt was $610.2 million.
Currently, we believe our liquidity to be adequate. For more information on our
commercial paper program and our credit facility, see Note 9 to our consolidated
financial statements included elsewhere in this report.

Long-term
Financing

In
addition to our principal sources of short-term liquidity listed above, we
could meet our cash requirements (other than distributions to our common
unitholders, Class B unitholders and general partner) through issuing long-term
notes or additional common units, or the proceeds from purchases of additional
i-units by KMR with the proceeds from issuances of KMR shares.

We
are subject, however, to changes in the equity and debt markets for our limited
partner units and long-term notes, and there can be no assurance we will be
able or willing to access the public or private markets for our limited

69

---



partner units and/or
long-term notes in the future. If we were unable or unwilling to issue
additional limited partner units, we would be required to either restrict
potential future acquisitions or pursue other debt financing alternatives, some
of which could involve higher costs or negatively affect our credit ratings.
Our ability to access the public and private debt markets is affected by our
credit ratings. See Capital Structure above for a discussion of our credit
ratings.

Equity
Issuances

On
May 17, 2007, KMR issued 5,700,000 of its shares in a public offering at a
price of $52.26 per share. The net
proceeds from the offering were used by KMR to buy additional i-units from us,
and we received net proceeds of $297.9 million for the issuance of 5,700,000
i-units.

On December
5, 2007, we completed a public offering of 7,130,000 of our common units,
including common units sold pursuant to the underwriters over-allotment
option, at a price of $48.09 per unit, less commissions and underwriting
expenses. We received net proceeds of $342.9 million for the issuance of these
7,130,000 common units.

We
used the proceeds from each of these two equity issuances to reduce the
borrowings under our commercial paper program. In addition, pursuant to our
purchase and sale agreement with Trans-Global Solutions, Inc., we issued
266,813 common units in May 2007 to TGS to settle a purchase price liability
related to our acquisition of bulk terminal operations from TGS in April 2005.
As agreed between TGS and us, the units were valued at $15.0 million.

On
February 12, 2008, we completed an additional offering of 1,080,000 of our
common units at a price of $55.65 per unit in a privately negotiated
transaction with two investors. We received net proceeds of $60.1 million for
the issuance of these 1,080,000 common units, and we used the proceeds to
reduce the borrowings under our commercial paper program.

Debt
Issuances

From
time to time we issue long-term debt securities. All of our long-term debt
securities issued to date, other than those issued under our long-term
revolving credit facility or those issued by our subsidiaries and operating
partnerships, generally have the same terms except for interest rates, maturity
dates and prepayment premiums. All of our outstanding debt securities are
unsecured obligations that rank equally with all of our other senior debt
obligations; however, a modest amount of secured debt has been incurred by some
of our operating partnerships and subsidiaries. Our fixed rate notes provide
that we may redeem the notes at any time at a price equal to 100% of the
principal amount of the notes plus accrued interest to the redemption date plus
a make-whole premium.

During
2007, we completed three separate public offerings of senior notes. We received
proceeds, net of underwriting discounts and commissions, as follows:

| |   |                                                                                                                                                                                                                                                
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | $992.8
 million from a January 30, 2007 public offering of a total of $1.0 billion in
 principal amount of senior notes, consisting of $600 million of 6.00% notes
 due February 1, 2017, and $400 million of 6.50% notes due February 1, 2037;
| |   |                                                                                                                                                                                                                                                
| |  | $543.9
 million from a June 21, 2007 public offering of $550 million in principal
 amount of 6.95% senior notes due January 15, 2038; and                                                                                                      
| |   |                                                                                                                                                                                                                                                
| |  | $497.8
 million from an August 28, 2007 public offering of $500 million in principal
 amount of 5.85% senior notes due September 15, 2012.                                                                                                     
| |   |                                                                                                                                                                                                                                                

We used the
proceeds from each of these three debt offerings to reduce the borrowings under
our commercial paper program. In addition, on August 15, 2007, we repaid $250
million of 5.35% senior notes that matured on that date. As of December 31,
2007, our total liability balance due on the various series of our senior notes
was $6,288.8 million, and the total liability balance due on the various
borrowings of our operating partnerships and subsidiaries was $188.2 million.
For additional information regarding our debt securities, see Note 9 to our
consolidated financial statements included elsewhere in this report.

70

---



On
February 12, 2008, we completed a public offering of senior notes.
We issued a total of $900 million in principal amount of senior notes,
consisting of $600 million of 5.95% notes due February 15, 2018, and $300
million of 6.95% notes due January 15, 2038. We received proceeds from the
issuance of the notes, after underwriting discounts and commissions, of
approximately $894.1 million, and we used the proceeds to reduce the borrowings
under our commercial paper program.

Capital
Requirements for Recent Transactions

During
2007, our cash outlays for the acquisition of assets and investments totaled
$713.3 million. We utilized our commercial paper program to fund our 2007
acquisitions. We then reduced our short-term borrowings with the proceeds from
our issuances of additional limited partnership units and senior notes, as
described above. We intend to refinance the remainder of our current short-term
debt and any additional short-term debt incurred during 2008 through a
combination of long-term debt, equity and the issuance of additional commercial
paper to replace maturing commercial paper borrowings.

We
are committed to maintaining a cost effective capital structure and we intend
to finance new acquisitions using a mix of approximately 50% equity financing
and 50% debt financing. For more information on our capital requirements during
2007 in regard to our acquisition expenditures, see Note 3 to our consolidated
financial statements included elsewhere in this report.

Off
Balance Sheet Arrangements

We
have invested in entities that are not consolidated in our financial
statements. As of December 31, 2007, our obligations with respect to these
investments, as well as our obligations with respect to a letter of credit, are
summarized below (dollars in millions):

|                                                              |  |                  |                    |                          |     |                                   |  |                          |                                                             |                     |  |                                           |         |  |  |  |   |         |  |  |  |   |         |     | 
|------------------------------------------------------------- |  | ---------------- | ------------------ | ------------------------ | --- | --------------------------------- |  | ------------------------ | ----------------------------------------------------------- | ------------------- |  | ----------------------------------------- | ------- |  |  |  | - | ------- |  |  |  | - | ------- | --- | 
|Entity                                                        |  | Investment
 Type |                    | Our
 Ownership
 Interest |     | Remaining
 Interest(s)
 Ownership |  | Total
 Entity
 Assets(5) |                                                             | Total
 Entity
 Debt |  | Our
 Contingent
 Share of
 Entity Debt(6) |        
|                                                              |  |                  |                    |                          |     |                                   |  |                          |                                                             |                     |  |                                           |        
|Cortez Pipeline Company                                       |  |                  | General
 Partner   |                          | 50  | %                                 |  |                          | (1)                                                         |                     |  | $                                         | 79.9    |  |  |  | $ | 157.3   |  |  |  | $ | 78.7    | (2) | 
|                                                              |  |                  |                    |                          |     |                                   |  |                          |                                                             |                     |  |                                           |         |  |  |  |   |         |  |  |  |   |         |     | 
|                                                              |  |                  |                    |                          |     |                                   |  |                          |                                                             |                     |  |                                           |         |  |  |  |   |         |  |  |  |   |         |     | 
|West2East Pipeline LLC(3)                                     |  |                  | Limited
 Liability |                          | 51  | %                                 |  |                          | ConocoPhillips
 and
 Sempra Energy                          |                     |  | $                                         | 2,730.2 |  |  |  | $ | 2,225.4 |  |  |  | $ | 1,135.0 |     | 
|                                                              |  |                  |                    |                          |     |                                   |  |                          |                                                             |                     |  |                                           |         |  |  |  |   |         |  |  |  |   |         |     | 
|Nassau
County,
 Florida Ocean Highway
 And Port Authority (4) |  |                  | N/A                |                          | N/A |                                   |  |                          | Nassau
 County,
 Florida Ocean
 Highway and
 Port Authority |                     |  |                                           | N/A     |  |  |  |   | N/A     |  |  |  | $ | 22.5    |     | 

| | 
| | 
| | 

|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(1) | The remaining general
 partner interests are owned by ExxonMobil Cortez Pipeline, Inc., an indirect
 wholly-owned subsidiary of Exxon Mobil Corporation and Cortez Vickers
 Pipeline Company, an indirect subsidiary of M.E. Zuckerman Energy Investors
 Incorporated.                                                                                                                                                                                                                                                                                                                                                                                                                                                                       
|   
|(2) | We are severally liable for
 our percentage ownership share (50%) of the Cortez Pipeline Company debt. As
 of December 31, 2007, Shell Oil Company shares our several guaranty
 obligations jointly and severally for $64.3 million of Cortezs debt balance;
 however, we are obligated to indemnify Shell for the liabilities it incurs in
 connection with such guaranty. Accordingly, as of December 31, 2007 we have a
 letter of credit in the amount of $37.5 million issued by JP Morgan Chase, in
 order to secure our indemnification obligations to Shell for 50% of the
 Cortez debt balance of $64.3 million.                                                                                                                   
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              
|    | Further, pursuant to a
 Throughput and Deficiency Agreement, the partners of Cortez Pipeline Company
 are required to contribute capital to Cortez in the event of a cash
 deficiency. The agreement contractually supports the financings of Cortez
 Capital Corporation, a wholly-owned subsidiary of Cortez Pipeline Company, by
 obligating the partners of Cortez Pipeline to fund cash deficiencies at
 Cortez Pipeline, including anticipated deficiencies and cash deficiencies
 relating to the repayment of principal and interest on the debt of Cortez
 Capital Corporation. The partners respective parent or other companies
 further severally guarantee the obligations of the Cortez Pipeline owners
 under this agreement.

71

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|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(3) | West2East Pipeline LLC is a
 limited liability company and is the sole owner of Rockies Express Pipeline
 LLC. As of December 31, 2007, the remaining limited liability member
 interests in West2East Pipeline LLC are owned by ConocoPhillips (24%) and
 Sempra Energy (25%). We owned a 66 2/3% ownership interest in West2East
 Pipeline LLC from October 21, 2005 until June 30, 2006, and we included its
 results in our consolidated financial statements until June 30, 2006. On June
 30, 2006, our ownership interest was reduced to 51%, West2East Pipeline LLC
 was deconsolidated, and we subsequently accounted for our investment under
 the equity method of accounting. Upon completion of the pipeline, our
 ownership percentage is expected to be reduced to 50%.                                                                                                                                                                                                                                                                                                                                                                   
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          
|(4) | Arose from our Vopak
 terminal acquisition in July 2001. Nassau County, Florida Ocean Highway and
 Port Authority is a political subdivision of the state of Florida. During
 1990, Ocean Highway and Port Authority issued its Adjustable Demand Revenue
 Bonds in the aggregate principal amount of $38.5 million for the purpose of
 constructing certain port improvements located in Fernandino Beach, Nassau
 County, Florida. A letter of credit was issued as security for the Adjustable
 Demand Revenue Bonds and was guaranteed by the parent company of Nassau
 Terminals LLC, the operator of the port facilities. In July 2002, we acquired
 Nassau Terminals LLC and became guarantor under the letter of credit
 agreement. In December 2002, we issued a $28 million letter of credit under
 our credit facilities and the former letter of credit guarantee was
 terminated. As of December 31, 2007, the face amount of this letter of credit
 outstanding under our credit facility was $22.5 million. Principal payments
 on the bonds are made on the first of December each year and reductions are
 made to the letter of credit.
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          
|(5) | Principally property, plant
 and equipment.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          
|(6) | Represents the portion of
 the entitys debt that we may be responsible for if the entity cannot satisfy
 the obligation.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                

We
account for our investments in Cortez Pipeline Company and West2East Pipeline
LLC under the equity method of accounting. For the year ended December 31,
2007, our share of earnings, based on our ownership percentage and before
amortization of excess investment cost was $19.2 million from Cortez Pipeline
Company and a loss of $12.4 million from West2East Pipeline LLC. Additional
information regarding the nature and business purpose of these investments is
included in Notes 7 and 9 to our consolidated financial statements included
elsewhere in this report.

Summary of Certain
Contractual Obligations

|                                              |  |                                            |          |                 |   |               |  |           |   |                |  |  |  |   |         |  |  |   |         | 
|--------------------------------------------- |  | ------------------------------------------ | -------- | --------------- | - | ------------- |  | --------- | - | -------------- |  |  |  | - | ------- |  |  | - | ------- | 
|                                              |  | Amount of Commitment Expiration per Period |         
|                                              |  |                                            |         
|                                              |  | Total                                      |          | 1 Year
 or Less |   | 2-3 Years     |  | 4-5 Years |   | After 5
 Years | 
|                                              |  |                                            |          |                 |   |               |  |           |   |                | 
|                                              |  |                                            |          |                 |   | (In millions) |  |           |   |                |  |  | 
|Contractual
 Obligations:                     |  |                                            |          |                 |   |               |  |           |   |                |  |  |  |   |         | 
|Commercial paper
 outstanding                 |  | $                                          | 589.1    |                 | $ | 589.1         |  |           | $ |               |  |  |  | $ |        |  |  | $ |        | 
|Other debt
 borrowings-principal payments     |  |                                            | 6,488.2  |                 |   | 21.1          |  |           |   | 537.0          |  |  |  |   | 1,681.4 |  |  |   | 4,248.7 | 
|Interest payments(a)                          |  |                                            | 5,947.2  |                 |   | 443.7         |  |           |   | 788.0          |  |  |  |   | 633.9   |  |  |   | 4,081.6 | 
|Lease obligations(b)                          |  |                                            | 130.7    |                 |   | 31.7          |  |           |   | 42.7           |  |  |  |   | 28.1    |  |  |   | 28.2    | 
|Pension and post-retirement
 welfare plans(c) |  |                                            | 62.1     |                 |   | 4.6           |  |           |   | 9.7            |  |  |  |   | 10.9    |  |  |   | 36.9    | 
|Other obligations(d)                          |  |                                            | 146.1    |                 |   | 44.9          |  |           |   | 84.1           |  |  |  |   | 17.1    |  |  |   |        | 
|                                              |  |                                            |          |                 |   |               |  |           |   |                |  |  |  |   |         |  |  |   |         | 
|Total                                         |  | $                                          | 13,363.4 |                 | $ | 1,135.1       |  |           | $ | 1,461.5        |  |  |  | $ | 2,371.4 |  |  | $ | 8,395.4 | 
|                                              |  |                                            |          |                 |   |               |  |           |   |                |  |  |  |   |         |  |  |   |         | 
|                                              |  |                                            |          |                 |   |               |  |           |   |                |  |  |  |   |         |  |  |   |         | 
|Other
 commercial commitments:                |  |                                            |          |                 |   |               |  |           |   |                |  |  |  |   |         |  |  |   |         | 
|Standby letters of
 credit(e)                 |  | $                                          | 672.4    |                 | $ | 634.9         |  |           | $ |               |  |  |  | $ |        |  |  | $ | 37.5    | 
|                                              |  |                                            |          |                 |   |               |  |           |   |                |  |  |  |   |         |  |  |   |         | 
|Capital expenditures(f)                       |  | $                                          | 250.5    |                 | $ | 250.5         |  |           |   |               |  |  |  |   |        |  |  |   |        | 
|                                              |  |                                            |          |                 |   |               |  |           |   |                |  |  |  |   |         |  |  |   |         | 

| | 
| | 
| | 

|    |                                                                                                                                                                                                                                                                                                                                                                                              
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(a) | Interest payment
 obligations exclude adjustments for interest rate swap agreements.                                                                                                                                                                                                                                                                                                         
|    |                                                                                                                                                                                                                                                                                                                                                                                              
|(b) | Represents commitments for
 capital leases, including interest, and operating leases.                                                                                                                                                                                                                                                                                                        
|    |                                                                                                                                                                                                                                                                                                                                                                                              
|(c) | Represents expected benefit
 payments from pension and post-retirement welfare plans as of December 31,
 2007.                                                                                                                                                                                                                                                                               
|    |                                                                                                                                                                                                                                                                                                                                                                                              
|(d) | Consist of payments due
 under carbon dioxide take-or-pay contracts.                                                                                                                                                                                                                                                                                                                         
|    |                                                                                                                                                                                                                                                                                                                                                                                              
|(e) | The $672.4 million in
 letters of credit outstanding as of December 31 2007 consisted of the
 following: (i) a combined $298.0 million in three letters of credit
 supporting our hedging of energy commodity price risks; (ii) a $100 million
 letter of credit that supports certain proceedings with the California Public
 Utilities Commission involving refined products tariff charges

72

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|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|    | on the intrastate common
 carrier operations of our Pacific operations pipelines in the state of
 California; (iii) a combined $58.3 million in ten letters of credit
 supporting our Trans Mountain pipeline system operations; (iv) a $37.5
 million letter of credit supporting our indemnification obligations on the
 Series D note borrowings of Cortez Capital Corporation; (v) our $30.3 million
 guarantee under letters of credit totaling $45.5 million supporting our
 International Marine Terminals Partnership Plaquemines, Louisiana Port,
 Harbor, and Terminal Revenue Bonds; (vi) a $25.3 million letter of credit
 supporting our Kinder Morgan Liquids Terminals LLC New Jersey Economic
 Development Revenue Bonds; (vii) a $24.1 million letter of credit supporting
 our Kinder Morgan Operating L.P. B tax-exempt bonds; (viii) a $22.5 million
 letter of credit supporting Nassau County, Florida Ocean Highway and Port
 Authority tax-exempt bonds; (ix) a $19.9 million letter of credit supporting
 the construction of our Kinder Morgan Louisiana Pipeline; (x) a $15.5 million
 letter of credit supporting our pipeline and terminal operations in Canada;
 (xi) a $5.4 million letter of credit supporting our Arrow Terminals, L.P.
 Illinois Development Revenue Bonds; and (xii) a combined $20.4 million in
 eight letters of credit supporting environmental and other obligations of us
 and our subsidiaries.
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            
|(f) | Represents commitments for
 the purchase of plant, property and equipment as of December 31, 2007.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            
|    | Operating Activities                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       

Net
cash provided by operating activities was $1,741.8 million in 2007, versus
$1,363.9 million in 2006. The overall year-to-year increase of $377.9 million
(28%) in cash flow from operations principally consisted of:

| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | a $159.1
 million increase in cash attributable to changes in the reserves related to the
 legal fees, transportation rate cases and other litigation liabilities of our
 pipeline and terminal operations (consisting of an incremental $140.0 million
 non-cash operating expense accrued in 2007, and payments of $19.1 million
 made in June 2006 to certain shippers on our Pacific operations pipelines).
 The expense was associated with a liability adjustment made in December 2007,
 and the payments related to a settlement agreement reached in May 2006 that
 resolved certain challenges by complainants with regard to delivery tariffs
 and gathering enhancement fees at our Pacific operations Watson Station,
 located in Carson, California;                                                                                                                                                                                                                                                                                                                                                                                                
| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
| |  | a $139.1
 million increase in cash inflows relative to changes in (i) other non-current
 assets and liabilities, including, among other things, incremental
 transportation and dock prepayments received from pipeline customers (due
 primarily to timing differences); and (ii) other incremental non-cash
 expenses, including higher non-cash operating expenses in 2007 associated
 with environmental liability adjustments, and higher non-cash general and
 administrative expenses related to the activities required to complete KMIs
 going-private transaction (with regard to the going-private transaction
 expenses, we were required to recognize the full amounts allocated to us from
 Knight as expense on our income statement; however, due to the fact that
 almost all of the allocated expenses were associated with the acceleration of
 cashouts of grants of both KMI restricted stock and options on KMI stock, we
 were not responsible for paying these buyout expenses, and accordingly,
 recognized the unpaid amount as both a contribution to Partners Capital
 and an increase to Minority interest on our balance sheet);
| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
| |  | a $95.1
 million increase in cash inflows relative to net changes in working capital
 items, mainly due to timing differences that resulted in higher 2007 net cash
 inflows from the collection and payment of trade and related party
 receivables and payables, and from lower payments on accrued tax and interest
 liabilities; and                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            
| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
| |  | a $51.6
 million decrease in cash from overall lower partnership incomenet of the
 following non-cash items: (i) depreciation, depletion and amortization
 expenses; (ii) gains and losses on property sales and casualty
 indemnifications; (iii) earnings from equity investees; and (iv) a $377.1
 million goodwill impairment charge recognized in the first quarter of 2007.
 The increases and decreases in our partnership income in 2007 compared to
 2006 are discussed above in Results of Operations.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                

Investing
Activities

Net
cash used in investing activities was $2,428.5 million for the year ended
December 31, 2007, compared to $1,501.9 million for the prior year. The $926.6
million (62%) overall increase in funds utilized in investing activities was
primarily attributable to the following:

73

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| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | a $326.1
 million increase due to higher expenditures made for strategic business
 acquisitions. In 2007, our acquisition outlays for assets and investments
 totaled $713.3 million, primarily consisting of $549.1 million for net
 payments made to Knight for our acquisition of the Trans Mountain pipeline
 system, $100.3 million for the acquisition of bulk terminal assets from
 Marine Terminals, Inc., and $38.8 million for the purchase of the Vancouver
 Wharves bulk marine terminal. In 2006, our acquisition outlays totaled $387.2
 million, primarily consisting of $244.6 million for the acquisition of
 Entrega Gas Pipeline LLC and $89.1 million for the acquisition of bulk,
 liquids and refined products terminal operations and related assets. Both our
 2007 and 2006 acquisition expenditures are discussed more fully in Note 3 to
 our consolidated financial statements included elsewhere in this report;
| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              
| |  | a $509.5
 million increase from higher capital expenditureslargely due to increased
 investments undertaken to expand and improve our bulk and liquids
 terminalling operations, and our Trans Mountain pipeline system. Our
 sustaining capital expenditures, defined as capital expenditures that do not
 increase the capacity of an asset, totaled $152.6 million in 2007 and $125.5
 million in 2006. The above amounts do not include the sustaining capital
 expenditures of our Trans Mountain business segment for periods prior to our
 acquisition date of April 30, 2007. Additionally, our forecasted expenditures
 for sustaining capital expenditures for 2008 are approximately $196.2
 million. All of our capital expenditures, with the exception of sustaining
 capital expenditures, are discretionary;                                                                                                                
| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              
| |  | a $273.6
 million increase from incremental contributions to equity investments in
 2007, largely driven by incremental investments of $202.7 million and $61.6
 million, respectively, for our proportionate share of construction costs of
 the Rockies Express and Midcontinent Express pipelines; and                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              
| |  | a $231.8
 million decrease in cash used due to higher net proceeds received from the
 sales of property, plant and equipment and other net assets (net of salvage
 and removal costs). The increase from sales proceeds in 2007 versus 2006 was
 driven by the approximately $298.6 million we received for the sale of our
 North System operations in October 2007. In April 2006, we received $42.5
 million from Momentum Energy Group, LLC for the combined sale of our Douglas
 natural gas gathering system and Painter Unit fractionation facility, and in
 the first half of 2006, we received $27.1 million from the sale of certain
 oil and gas properties originally acquired from Journey Acquisition  I, L.P.
 and Journey 2000, L.P.                                                                                                                                                                                        

Financing
Activities

Net
cash provided by financing activities amounted to $735.7 million in 2007; while
in the prior year, our financing activities provided net cash of $132.4
million. The $603.3 million (456%) overall increase in cash inflows provided by
financing activities was primarily due to:

| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | a $334.5
 million increase from overall debt financing activitieswhich include our
 issuances and payments of debt and our debt issuance costs. The year-to-year
 increase in cash from financing activities was primarily due to (i) a
 $1,784.5 million net increase in cash inflows from the issuances and payments
 of senior notes in 2007; and (ii) a $1,453.6 million decrease in cash from
 lower overall net commercial paper borrowings in 2007, relative to 2006.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         
| |   | The decrease
 in commercial paper borrowings includes a decrease of $412.5 million from
 borrowings under the commercial paper program of Rockies Express Pipeline LLC
 in the first half of 2006. We held and consolidated a 66 2/3% ownership
 interest in Rockies Express Pipeline LLC until June 30, 2006. Effective June
 30, 2006, ConocoPhillips exercised its option to acquire a 25% ownership
 interest in West2East Pipeline LLC (and its subsidiary Rockies Express
 Pipeline LLC), and West2East Pipeline LLC was then deconsolidated and
 accounted for under the equity method of accounting. Generally accepted
 accounting principles required us to include its cash inflows and outflows in
 our consolidated statement of cash flows for the six months ended June 30,
 2006; however, following the change from full consolidation to the equity
 method, Rockies Express debt balances were not included in our consolidated
 balance sheet as of or subsequent to June 30, 2006.
| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         
| |   | The $1,784.5
 million increase in cash inflows from changes in senior notes outstanding was
 associated with public debt offerings completed on January 30, 2007, June 21,
 2007 and August 28, 2007. On these dates, we                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                

74

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| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |   | completed
 offerings of $1.0 billion, $550 million and $500 million, respectively, in
 principal amount of senior notes in four separate series: (i) $600 million of
 6.00% notes due February 1, 2017; (ii) $400 million of 6.50% notes due
 February 1, 2037; (iii) $550 million of 6.95% notes due January 15, 2038; and
 (iv) $500 million of 5.85% notes due September 15, 2012. Combined, we
 received proceeds, net of underwriting discounts and commissions, of $2,034.5
 million from these long-term debt offerings and we used the proceeds from
 each of these offerings to reduce the borrowings under our commercial paper
 program. In addition, on August 15, 2007, we repaid $250 million of 5.35%
 senior notes that matured on that date;                        
| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      
| |  | a $392.4
 million increase from overall equity financing activitieswhich include our
 issuances of limited partner units. In May 2007, we received proceeds of
 $297.9 million, after commissions and underwriting expenses, for our issuance
 of 5,700,000 i-units to KMR, and in December 2007, we received net proceeds of $342.9 million from a public offering of
 7,130,000 common units. In 2006, we received proceeds of $248.4 million from
 the issuance of additional common units, primarily related to our August 2006
 public offering of 5,750,000 of our common units at a price of $44.80, less
 commissions and underwriting expenses. We used the proceeds from each of
 these equity issuances to reduce the borrowings under our commercial paper
 program; and
| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      
| |  | a $100.9
 million decrease from lower contributions from minority interestsprincipally
 due to contributions of $104.2 million received in 2006 from Sempra Energy
 with regard to their ownership interest in Rockies Express. The contributions
 from Sempra included an $80.0 million contribution for its 33 1/3% share of
 the purchase price of Entrega Gas Pipeline LLC, discussed above in
 Investing Activities.                                                                                                                                                                                                                                                                                                                                                        
| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      

Partnership
Distributions

Our
partnership agreement requires that we distribute 100% of Available Cash, as
defined in our partnership agreement, to our partners within 45 days following
the end of each calendar quarter in accordance with their respective percentage
interests. Available Cash consists generally of all of our cash receipts,
including cash received by our operating partnerships and net reductions in
reserves, less cash disbursements and net additions to reserves and amounts
payable to the former general partner of SFPP, L.P. in respect of its remaining
0.5% interest in SFPP.

Our
general partner is granted discretion by our partnership agreement, which discretion
has been delegated to KMR, subject to the approval of our general partner in
certain cases, to establish, maintain and adjust reserves for future operating
expenses, debt service, maintenance capital expenditures, rate refunds and
distributions for the next four quarters. These reserves are not restricted by
magnitude, but only by type of future cash requirements with which they can be
associated. When KMR determines our quarterly distributions, it considers
current and expected reserve needs along with current and expected cash flows
to identify the appropriate sustainable distribution level. For 2007, 2006 and
2005, we distributed approximately 100%, 103% and 101%, respectively, of the
total of cash receipts less cash disbursements (calculations assume that KMR
unitholders received cash). The difference between these numbers and 100% of
distributable cash flow reflects net changes in reserves.

Our
general partner and owners of our common units and Class B units receive
distributions in cash, while KMR, the sole owner of our i-units, receives
distributions in additional i-units. We do not distribute cash to i-unit owners
but instead retain the cash for use in our business. However, the cash
equivalent of distributions of i-units is treated as if it had actually been
distributed for purposes of determining the distributions to our general
partner. Each time we make a distribution, the number of i-units owned by KMR
and the percentage of our total units owned by KMR increase automatically under
the provisions of our partnership agreement.

Available
cash is initially distributed 98% to our limited partners and 2% to our general
partner. These distribution percentages are modified to provide for incentive
distributions to be paid to our general partner in the event that quarterly
distributions to unitholders exceed certain specified targets.

Available
cash for each quarter is distributed:

| |   |                                                                                                                                                                                                                               
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | first, 98% to the owners of all
classes of
 units pro rata and 2% to our general partner until the owners of all classes
 of units have received a total of $0.15125 per unit in cash or equivalent
 i-units for such quarter;

75

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| |   |                                                                                                                                                                                                                                                                          
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | second, 85% of any available
cash then
 remaining to the owners of all classes of units pro rata and 15% to our
 general partner until the owners of all classes of units have received a
 total of $0.17875 per unit in cash or equivalent i-units for such quarter;    
| |   |                                                                                                                                                                                                                                                                          
| |  | third, 75% of any available cash
then
 remaining to the owners of all classes of units pro rata and 25% to our
 general partner until the owners of all classes of units have received a
 total of $0.23375 per unit in cash or equivalent i-units for such quarter;
 and
| |   |                                                                                                                                                                                                                                                                          
| |  | fourth, 50% of any available
cash then
 remaining to the owners of all classes of units pro rata, to owners of common
 units and Class B units in cash and to owners of i-units in the equivalent
 number of i-units, and 50% 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. Our general partners incentive distribution that we
declared for 2007 was $611.9 million, while the incentive distribution paid to
our general partner during 2007 was $559.6 million. The difference between
declared and paid distributions is due to the fact that our distributions for
the fourth quarter of each year are declared and paid in the first quarter of
the following year. In addition, our general partner waived $20.1 million of
its 2006 incentive distribution for the fourth quarter of 2006, which was paid
in the first quarter of 2007, in order to fund the annual bonus for
employees.

On
February 14, 2008, we paid a quarterly distribution of $0.92 per unit for the
fourth quarter of 2007. This distribution was 11% greater than the $0.83
distribution per unit we paid for both the fourth quarter of 2006 and the first
quarter of 2007. We paid this distribution in cash to our common unitholders
and to our Class B unitholders. KMR, our sole i-unitholder, received additional
i-units based on the $0.92 cash distribution per common unit. We believe that
future operating results will continue to support similar levels of quarterly
cash and i-unit distributions; however, no assurance can be given that future
distributions will continue at such levels.

Litigation
and Environmental

As
of December 31, 2007, we have recorded a total reserve for environmental claims,
without discounting and without regard to anticipated insurance recoveries, in
the amount of $92.0 million. In addition, we have recorded a receivable of
$37.8 million for expected cost recoveries that have been deemed probable. The
reserve is primarily established to address and clean up soil and ground water
impacts from former releases to the environment at facilities we have acquired
or accidental spills or releases at facilities that we own. Reserves for each
project are generally established by reviewing existing documents, conducting
interviews and performing site inspections to determine the overall size and
impact to the environment. Reviews are made on a quarterly basis to determine
the status of the cleanup and the costs associated with the effort. In
assessing environmental risks in conjunction with proposed acquisitions, we
review records relating to environmental issues, conduct site inspections,
interview employees, and, if appropriate, collect soil and groundwater samples.
As of December 31, 2006, our total reserve for environmental claims, without
discounting and without regard to anticipated insurance recoveries, amounted to
$64.2 million.

Additionally,
as of December 31, 2007, we have recorded a total reserve for legal fees, transportation
rate cases and other litigation liabilities in the amount of $247.9 million.
The reserve is primarily related to various claims from lawsuits arising from
our Pacific operations, and the contingent amount is based on both the
circumstances of probability and reasonability of dollar estimates. We
regularly assess the likelihood of adverse outcomes resulting from these claims
in order to determine the adequacy of our liability provision, and in December
2007, we recorded a non-cash increase in operating expense of $140.0 million
related to our litigation matters. As of December 31, 2006, our total reserve
for legal fees, transportation rate cases and other litigation liabilities
amounted to $112.0 million.

Though
no assurance can be given, we believe we have established adequate
environmental and legal reserves such that the resolution of pending
environmental matters and litigation will not have a material adverse impact on
our business, cash flows, financial position or results of operations.

76

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Pursuant
to our continuing commitment to operational excellence and our focus on safe,
reliable operations, we have implemented, and intend to implement in the
future, enhancements to certain of our operational practices in order to
strengthen our environmental and asset integrity performance. These
enhancements have resulted and may result in higher operating costs and
sustaining capital expenditures; however, we believe these enhancements will
provide us the greater long term benefits of improved environmental and asset
integrity performance.

Please
refer to Notes 16 and 17 of our consolidated financial statements included
elsewhere in this report for additional information regarding pending
litigation and environmental matters, respectively.

Regulation

The
Pipeline Safety Improvement Act of 2002 requires pipeline companies to perform
integrity tests on natural gas transmission pipelines that exist in high
population density areas that are designated as High Consequence Areas.
Pipeline companies are required to perform the integrity tests within ten years
of December 17, 2002, the date of enactment, and must perform subsequent
integrity tests on a seven year cycle. At least 50% of the highest risk segments
must be tested within five years of the enactment date. The risk ratings are
based on numerous factors, including the population density in the geographic
regions served by a particular pipeline, as well as the age and condition of
the pipeline and its protective coating. Testing will consist of hydrostatic
testing, internal electronic testing, or direct assessment of the piping. A
similar integrity management rule for refined petroleum products pipelines
became effective May 29, 2001. All baseline assessments for products pipelines
must be completed by March 31, 2008 and we expect to meet this deadline. We
have included all incremental expenditures estimated to occur during 2008
associated with the Pipeline Safety Improvement Act of 2002 and the integrity
management of our products pipelines in our 2008 budget and capital expenditure
plan.

Please
refer to Note 17 to our consolidated financial statements included elsewhere in
this report for additional information regarding regulatory matters.

Recent Accounting Pronouncements

Please refer
to Note 18 to our consolidated financial statements included elsewhere in this
report for information concerning recent accounting pronouncements.

Information Regarding Forward-Looking Statements

This filing
includes forward-looking statements. These forward-looking statements are
identified as any statement that does not relate strictly to historical or
current facts. They use words such as anticipate, believe, intend,
plan, projection, forecast, strategy, position, continue,
estimate, expect, may, or the negative of those terms or other variations
of them or comparable terminology. In particular, statements, express or
implied, concerning future actions, conditions or events, future operating
results or the ability to generate sales, income or cash flow or to make
distributions are forward-looking statements. Forward-looking statements are
not guarantees of performance. They involve risks, uncertainties and assumptions.
Future actions, conditions or events and future results of operations may
differ materially from those expressed in these forward-looking statements.
Many of the factors that will determine these results are beyond our ability to
control or predict. Specific factors which could cause actual results to differ
from those in the forward-looking statements include:

| |   |                                                                                                                                                                                       
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | price trends and overall demand
for natural
 gas liquids, refined petroleum products, oil, carbon dioxide, natural gas,
 coal and other bulk materials and chemicals in North America;
| |   |                                                                                                                                                                                       
| |  | economic activity, weather,
alternative
 energy sources, conservation and technological advances that may affect price
 trends and demand;                                            
| |   |                                                                                                                                                                                       
| |  | changes in our tariff rates
implemented by
 the Federal Energy Regulatory Commission or the California Public Utilities
 Commission;                                                  
| |   |                                                                                                                                                                                       
| |  | our ability to acquire new
businesses and
 assets and integrate those operations into our existing operations, as well
 as our ability to make expansions to our facilities;          

77

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| |   |                                                                                                                                                                                                                                                                                         
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | difficulties or delays
experienced by
 railroads, barges, trucks, ships or pipelines in delivering products to or
 from our terminals or pipelines;                                                                                                                                     
| |   |                                                                                                                                                                                                                                                                                         
| |  | our ability
 to successfully identify and close acquisitions and make cost-saving changes
 in operations;                                                                                                                                                                               
| |   |                                                                                                                                                                                                                                                                                         
| |  | shut-downs or cutbacks at major
refineries,
 petrochemical or chemical plants, ports, utilities, military bases or other
 businesses that use our services or provide services or products to us;                                                                                       
| |   |                                                                                                                                                                                                                                                                                         
| |  | crude oil and natural gas
production from
 exploration and production areas that we serve, including, among others, the
 Permian Basin area of West Texas;                                                                                                                              
| |   |                                                                                                                                                                                                                                                                                         
| |  | changes in laws or regulations,
third-party
 relations and approvals, decisions of courts, regulators and governmental bodies
 that may adversely affect our business or our ability to compete;                                                                                        
| |   |                                                                                                                                                                                                                                                                                         
| |  | changes in accounting
pronouncements that
 impact the measurement of our results of operations, the timing of when such
 measurements are to be made and recorded, and the disclosures surrounding
 these activities;                                                                   
| |   |                                                                                                                                                                                                                                                                                         
| |  | our ability to offer and sell
equity
 securities and debt securities or obtain debt financing in sufficient amounts
 to implement that portion of our business plan that contemplates growth
 through acquisitions of operating businesses and assets and expansions of our
 facilities;
| |   |                                                                                                                                                                                                                                                                                         
| |  | our indebtedness could make us
vulnerable
 to general adverse economic and industry conditions, limit our ability to
 borrow additional funds, and/or place us at competitive disadvantages
 compared to our competitors that have less debt or have other adverse
 consequences;       
| |   |                                                                                                                                                                                                                                                                                         
| |  | interruptions of electric power
supply to
 our facilities due to natural disasters, power shortages, strikes, riots,
 terrorism, war or other causes;                                                                                                                                   
| |   |                                                                                                                                                                                                                                                                                         
| |  | our ability
 to obtain insurance coverage without significant levels of self-retention of
 risk;                                                                                                                                                                                        
| |   |                                                                                                                                                                                                                                                                                         
| |  | acts of
 nature, sabotage, terrorism or other similar acts causing damage greater than
 our insurance coverage limits;                                                                                                                                                                  
| |   |                                                                                                                                                                                                                                                                                         
| |  | capital
 markets conditions;                                                                                                                                                                                                                                                            
| |   |                                                                                                                                                                                                                                                                                         
| |  | the
 political and economic stability of the oil producing nations of the world;                                                                                                                                                                                                        
| |   |                                                                                                                                                                                                                                                                                         
| |  | national, international,
regional and local
 economic, competitive and regulatory conditions and developments;                                                                                                                                                                          
| |   |                                                                                                                                                                                                                                                                                         
| |  | the ability
 to achieve cost savings and revenue growth;                                                                                                                                                                                                                                
| |   |                                                                                                                                                                                                                                                                                         
| |  | inflation;                                                                                                                                                                                                                                                                              
| |   |                                                                                                                                                                                                                                                                                         
| |  | interest rates;                                                                                                                                                                                                                                                                         
| |   |                                                                                                                                                                                                                                                                                         
| |  | the
 pace of deregulation of retail natural gas and electricity;                                                                                                                                                                                                                        
| |   |                                                                                                                                                                                                                                                                                         
| |  | foreign exchange
 fluctuations;                                                                                                                                                                                                                                                         
| |   |                                                                                                                                                                                                                                                                                         
| |  | the timing
 and extent of changes in commodity prices for oil, natural gas, electricity
 and certain agricultural products;                                                                                                                                                             
| |   |                                                                                                                                                                                                                                                                                         
| |  | the extent of our success in
discovering,
 developing and producing oil and gas reserves, including the risks inherent
 in exploration and development drilling, well completion and other
 development activities;                                                                     

78

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| |   |                                                                                                                                                                         
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | engineering and mechanical or
technological
 difficulties with operational equipment, in well completions and workovers,
 and in drilling new wells;                    
| |   |                                                                                                                                                                         
| |  | the uncertainty inherent in
estimating future oil and natural gas production or reserves;                                                                               
| |   |                                                                                                                                                                         
| |  | the ability to complete
 expansion projects on time and on budget;                                                                                                      
| |   |                                                                                                                                                                         
| |  | the timing and success of business
 development efforts; and                                                                                                            
| |   |                                                                                                                                                                         
| |  | unfavorable results of
litigation and the
 fruition of contingencies referred to in Note 16 to our consolidated
 financial statements included elsewhere in this report.

There
is no assurance that any of the actions, events or results of the
forward-looking statements will occur, or if any of them do, what impact they
will have on our results of operations or financial condition. Because of these
uncertainties, you should not put undue reliance on any forward-looking
statements.

See
Item 1A Risk Factors for a more detailed description of these and other
factors that may affect the forward-looking statements. When considering
forward-looking statements, one should keep in mind the risk factors described
in Risk Factors above. The risk factors could cause our actual results to
differ materially from those contained in any forward-looking statement. We
disclaim any obligation, other than as required by applicable law, to update
the above list or to announce publicly the result of any revisions to any of
the forward-looking statements to reflect future events or developments.

Item 7A. Quantitative
and Qualitative Disclosures About Market Risk.

Generally,
our market risk sensitive instruments and positions have been determined to be
other than trading. Our exposure to market risk as discussed below includes
forward-looking statements and represents an estimate of possible changes in
fair value or future earnings that would occur assuming hypothetical future
movements in interest rates or commodity prices. Our views on market risk are
not necessarily indicative of actual results that may occur and do not
represent the maximum possible gains and losses that may occur, since actual
gains and losses will differ from those estimated based on actual fluctuations
in commodity prices or interest rates and the timing of transactions.

Energy Commodity Market Risk

We
are exposed to commodity market risk and other external risks, such as
weather-related risk, in the ordinary course of business. However, we take
steps to hedge, or limit our exposure to, these risks in order to maintain a
more stable and predictable earnings stream. Stated another way, we execute a
hedging strategy that seeks to protect our financial position against adverse
price movements and serves to minimize potential losses. Our strategy involves
the use of certain energy commodity derivative contracts to reduce and minimize
the risks associated with unfavorable changes in the market price of natural
gas, natural gas liquids and crude oil. The derivative contracts we use include
energy products traded on the New York Mercantile Exchange and over-the-counter
markets, including, but not limited to, futures and options contracts, fixed
price swaps and basis swaps.

Fundamentally,
our hedging strategy involves taking a simultaneous position in the futures
market that is equal and opposite to our position in the cash market (or
physical product) in order to minimize the risk of financial loss from an
adverse price change. For example, as sellers of crude oil and natural gas, we
often enter into fixed price swaps and/or futures contracts to guarantee or lock-in
the sale price of our oil or the margin from the sale and purchase of our
natural gas at the time of market delivery, thereby directly offsetting any
change in prices, either positive or negative. A hedge is successful when gains
or losses in the cash market are neutralized by losses or gains in the futures
transaction.

Our risk
management policies prohibit us from engaging in speculative trading and we are
not a party to leveraged derivatives. Furthermore, our policies require that we
only enter into derivative contracts with carefully selected major financial
institutions or similar counterparties based upon their credit ratings and
other factors, and we

79

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maintain strict dollar and term limits that correspond to our
counterparties credit ratings. While we enter into derivative transactions
only with investment grade counterparties and actively monitor their credit
ratings, it is nevertheless possible that losses will result from counterparty
credit risk in the future. The credit ratings of the primary parties from whom
we purchase energy commodity derivative contracts are as follows
(credit ratings per Standard & Poors Rating Services):

|                                  |  |  |               | 
|--------------------------------- |  |  | ------------- | 
|                                  |  |  | Credit Rating | 
|                                  |  |  |               | 
|BNP Paribas                       |  |  | AA+           | 
|J. Aron & Company / Goldman Sachs |  |  | AA           | 
|Morgan Stanley                    |  |  | AA           | 

We account
for our energy commodity risk management derivative contracts according to the
provisions of Statement of Financial Accounting Standards No. 133, Accounting
for Derivative Instruments and Hedging Activities (after amendment by SFAS No.
137, SFAS No. 138, and SFAS No. 149). According to the provisions of SFAS No.
133, derivatives are measured at fair value and recognized on the balance sheet
as either assets or liabilities, and in general, gains and losses on
derivatives are reported on the income statement.

However, as
discussed above, our principal use of energy commodity derivative contracts is
to mitigate the market price risk associated with anticipated transactions for
the purchase and sale of natural gas, natural gas liquids and crude oil. Using
derivative contracts for this purpose helps provide us increased certainty with
regard to our operating cash flows and helps us undertake further capital
improvement projects, attain budget results and meet distribution targets to
our partners. SFAS No. 133 categorizes such use of energy commodity derivative
contracts as cash flow hedges, because the derivative contract is used to hedge
the anticipated future cash flow of a transaction that is expected to occur but
whose value is uncertain. Cash flow hedges are defined as hedges made with the
intention of decreasing the variability in cash flows related to future
transactions, as opposed to the value of an asset, liability or firm
commitment, and SFAS No. 133 prescribes special hedge accounting treatment for
such derivatives.

In
accounting for cash flow hedges, gains and losses on the derivative contracts
are reported in other comprehensive income, outside Net Income reported in
our consolidated statements of income, but only to the extent that the gains
and losses from the change in value of the derivative contracts can later
offset the loss or gain from the change in value of the hedged future cash
flows during the period in which the hedged cash flows affect net income. That
is, for cash flow hedges, all effective components of the derivative contracts
gains and losses are recorded in other comprehensive income, pending occurrence
of the expected transaction. Other comprehensive income consists
of those financial items that are included in Accumulated other comprehensive
loss in our accompanying consolidated balance sheets but not included in our
net income. Thus, in highly
effective cash flow hedges, where there is no ineffectiveness, other
comprehensive income changes by exactly as much as the derivative contracts and
there is no impact on earnings.

All
remaining gains and losses on the derivative contracts (the ineffective
portion) are included in current net income. The ineffective portion of the
gain or loss on the derivative contracts is the difference between the gain or
loss from the change in value of the derivative contract and the effective
portion of that gain or loss. In addition, when the hedged
forecasted transaction does take place and affects earnings, the effective part
of the hedge is also recognized in the income statement, and the earlier
recognized effective amounts are removed from Accumulated other comprehensive
loss. If the forecasted transaction results in an asset or liability, amounts
in Accumulated other comprehensive loss should be reclassified into earnings
when the asset or liability affects earnings through cost of sales, depreciation,
interest expense, etc.

Under
current accounting rules, the accumulated components of other comprehensive
income are to be reported separately as accumulated other comprehensive income
or loss in the stockholders equity section of the balance sheet. For us, the gains
and losses that are included in Accumulated other comprehensive loss in our
accompanying consolidated balance sheets are primarily related to the
derivative contracts associated with our hedging of anticipated future cash flows
from the sales and purchases of natural gas, natural gas liquids and crude oil
and represent the effective portion of the
gain or loss on these derivative contacts. Accordingly, the total
Accumulated other comprehensive loss included within the Partners Capital section of our accompanying balance
sheets as of
December 31, 2007 and December 31, 2006, included amounts associated
with the commodity price risk management activities of $1,377.2 million and
$838.7 million, respectively.

80

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In future
periods, as the hedged cash flows from our actual purchases and sales of energy
commodities affect our net income, the related gains and losses included in our
accumulated other comprehensive loss as a result of our hedging are transferred
to the income statement as well, effectively offsetting the changes in cash
flows stemming from the hedged risk.

We measure
the risk of price changes in the natural gas, natural gas liquids and crude oil
markets utilizing a value-at-risk model. Value-at-risk is a statistical measure
of how much the mark-to-market value of a portfolio could change during a
period of time, within a certain level of statistical confidence. We utilize a
closed form model to evaluate risk on a daily basis. The value-at-risk computations
utilize a confidence level of 97.7% for the resultant price movement and a
holding period of one day is chosen for the calculation. The confidence level
used means that there is a 97.7% probability that the mark-to-market losses for
a single day will not exceed the value-at-risk number presented. Derivative
contracts evaluated by the model include commodity futures and options
contracts, fixed price swaps, basis swaps and over-the-counter options.

For
each of the years ended December 31, 2007 and 2006, our value-at-risk reached a
high of $1.6 million and $2.6 million, respectively, and a low of $0.7 million
and $0.5 million, respectively. Value-at-risk as of December 31, 2007, was $1.6
million and averaged $1.2 million for 2007. Value-at-risk as of December 31,
2006, was $0.6 million and averaged $1.1 million for 2006.

Our
calculated value-at-risk exposure represents an estimate of the reasonably
possible net losses that would be recognized on our portfolio of derivative
contracts assuming hypothetical movements in future market rates, and is not
necessarily indicative of actual results that may occur. It does not represent
the maximum possible loss or any expected loss that may occur, since actual
future gains and losses will differ from those estimated. Actual gains and
losses may differ from estimates due to actual fluctuations in market rates,
operating exposures and the timing thereof, as well as changes in our portfolio
of derivatives during the year. In addition, as discussed above, we enter into
these derivative contracts solely for the purpose of mitigating the risks that
accompany certain of our business activities and, therefore, the change in the
market value of our portfolio of derivative contracts, with the exception of a
minor amount of hedging inefficiency, is offset by changes in the value of the
underlying physical transactions. For more information on our risk management
activities, see Note 14 to our consolidated financial statements included
elsewhere in this report.

Interest Rate Risk

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. The market risk inherent in our debt instruments
and positions is the potential change arising from increases or decreases in
interest rates as discussed below.

For fixed
rate debt, changes in interest rates generally affect the fair value of the
debt instrument, but not our earnings or cash flows. Conversely, for variable
rate debt, changes in interest rates generally do not impact the fair value of
the debt instrument, but may affect our future earnings and cash flows. We do
not have an obligation to prepay fixed rate debt prior to maturity and, as a
result, interest rate risk and changes in fair value should not have a
significant impact on our fixed rate debt until we would be required to
refinance such debt.

As of
December 31, 2007 and 2006, the carrying values of our fixed rate debt were
approximately $6,382.9 million and $4,551.2 million, respectively. These
amounts compare to, as of December 31, 2007 and 2006, fair values of $6,518.7
million and $4,672.7 million, respectively. Fair values were determined using
quoted market prices, where applicable, or future cash flow discounted at
market rates for similar types of borrowing arrangements. A hypothetical 10%
change (approximately 64 basis points) in the average interest rates applicable
to such debt for 2007 and 2006, would result in changes of approximately $259.9
million and $183.4 million, respectively, in the fair values of these
instruments.

The
carrying value and fair value of our variable rate debt, including associated
accrued interest and excluding the value of interest rate swap agreements
(discussed below), was $684.5 million as of December 31, 2007 and $1,195.6
million as of December 31, 2006. A hypothetical 10% change in the weighted
average interest rate on all of our borrowings, when applied to our outstanding
balance of variable rate debt as of December 31, 2007 and 2006,

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including adjustments for notional swap amounts, would result in
changes of approximately $19.1 million and $20.3 million, respectively, in our
2007 and 2006 annual pre-tax earnings.

As of
December 31, 2007 and 2006, we were a party to interest rate swap agreements
with notional principal amounts of $2.3 billion and $2.1 billion, respectively.
An interest rate swap agreement is a contractual agreement entered into between
two counterparties under which each agrees to make periodic interest payments
to the other for an agreed period of time based upon a predetermined amount of
principal, which is called the notional principal amount. Normally at each
payment or settlement date, the party who owes more pays the net amount; so at
any given settlement date only one party actually makes a payment. The
principal amount is notional because there is no need to exchange actual
amounts of principal.

We entered
into our interest rate swap agreements for the purposes of (i) hedging the
interest rate risk associated with our fixed rate debt obligations and (ii)
transforming a portion of the underlying cash flows related to our long-term
fixed rate debt securities into variable rate debt in order to achieve our
desired mix of fixed and variable rate debt. Since the fair value of our fixed
rate debt varies with changes in the market rate of interest, we enter into
swap agreements to receive a fixed and pay a variable rate of interest. Such
swap agreements result in future cash flows that vary with the market rate of
interest, and therefore hedge against changes in the fair value of our fixed
rate debt due to market rate changes.

As of both
December 31, 2007 and 2006, all of our interest rate swap agreements
represented fixed-for-variable rate swaps, where we agreed to pay our
counterparties a variable rate of interest on a notional principal amount,
comprised of principal amounts from various series of our long-term fixed rate
senior notes. In exchange, our counterparties agreed to pay us a fixed rate of
interest, thereby allowing us to transform our fixed rate liabilities into
variable rate obligations without the incurrence of additional loan origination
or conversion costs.

We monitor our
mix of fixed rate and variable rate debt obligations in light of changing
market conditions and from time to time may alter that mix by, for example,
refinancing balances outstanding under our variable rate debt with fixed rate
debt (or vice versa) or by entering into interest rate swap agreements or other
interest rate hedging agreements. In general, we attempt to
maintain an overall target mix of approximately 50% fixed rate debt and 50%
variable rate debt.

As of
December 31, 2007, our cash and investment portfolio did not include
fixed-income securities. Due to the short-term nature of our investment
portfolio, a hypothetical 10% increase in interest rates would not have a
material effect on the fair market value of our portfolio. Since we have the
ability to liquidate this portfolio, we do not expect our operating results or
cash flows to be materially affected to any significant degree by the effect of
a sudden change in market interest rates on our investment portfolio.

See Note 9
to our consolidated financial statements included elsewhere in this report for
additional information related to our debt instruments; for more information on
our interest rate swap agreements, see Note 14.

Item 8.Financial
Statements and Supplementary Data.

The
information required in this Item 8 is included in this report as set forth in
the Index to Financial Statements on page 114.

Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure.

None.

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Item 9A. Controls and Procedures.

Conclusion
Regarding the Effectiveness of Disclosure Controls and Procedures

As of
December 31, 2007, our management,
including our Chief Executive Officer and Chief Financial Officer, has
evaluated the effectiveness of the design and operation of our disclosure
controls and procedures pursuant to Rule 13a-15(b) under the Securities
Exchange Act of 1934. There are inherent limitations to the effectiveness of
any system of disclosure controls and procedures, including the possibility of
human error and the circumvention or overriding of the controls and procedures.
Accordingly, even effective disclosure controls and procedures can only provide
reasonable assurance of achieving their control objectives. Based upon and as
of the date of the evaluation, our Chief Executive Officer and our Chief
Financial Officer concluded that the design and operation of our disclosure
controls and procedures were effective to provide reasonable assurance that information
required to be disclosed in the reports we file and submit under the Securities
Exchange Act of 1934 is recorded, processed, summarized and reported as and
when required, and is accumulated and communicated to our management, including
our Chief Executive Officer and Chief Financial Officer, as appropriate, to
allow timely decisions regarding required disclosure.

Managements
Report on Internal Control Over Financial Reporting

Our
management is responsible for establishing and maintaining adequate internal
control over financial reporting, as such term is defined in Exchange Act Rule
13a-15(f). Because of its inherent limitations, internal control over financial
reporting may not prevent or detect misstatements. Projections of any
evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the
degree of compliance with the policies or procedures may deteriorate. Under the
supervision and with the participation of our management, including our Chief
Executive Officer and Chief Financial Officer, we conducted an evaluation of
the effectiveness of our internal control over financial reporting based on the
framework in Internal Control  Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission. Based on our
evaluation under the framework in Internal Control  Integrated Framework,
our management concluded that our internal control over financial reporting was
effective as of December 31, 2007.

The
effectiveness of our internal control over financial reporting as of December
31, 2007, has been audited by PricewaterhouseCoopers LLP, an independent
registered public accounting firm, as stated in their report which appears
herein.

Certain
businesses we acquired during 2007 were excluded from the scope of our
managements assessment of the effectiveness of our internal control over
financial reporting as of December 31, 2007. The excluded businesses consisted
of the following:

| |   |                                                                                                        
| | - | -------------------------------------------------------------------------------------------------------
| |  | the
 Vancouver Wharves bulk marine terminal, acquired May 30, 2007; and                                
| |   |                                                                                                        
| |  | the terminal
 assets and operations acquired from Marine Terminals, Inc., effective
 September 1, 2007.

These
businesses, in the aggregate, constituted 0.6% of our total operating revenues
for 2007 and 1.2% of our total assets as of December 31, 2007.

Changes
in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting
during the fourth quarter of 2007 that has materially affected, or is
reasonably likely to materially affect, our internal control over financial
reporting.

Item 9B. Other Information.

None.

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PART III

Item 10. Directors, Executive Officers and Corporate
Governance

Directors and Executive Officers of our General Partner and its
Delegate

Set forth
below is certain information concerning the directors and executive officers of
our general partner and KMR, the delegate of our general partner. All directors
of our general partner are elected annually by, and may be removed by, Kinder
Morgan (Delaware), Inc. as its sole shareholder, and all directors of KMR are
elected annually by, and may be removed by, our general partner as the sole
holder of KMRs voting shares. Kinder Morgan (Delaware), Inc. is a wholly owned
subsidiary of Knight. All officers of our general partner and all officers of
KMR serve at the discretion of the board of directors of our general partner.

|                     |  |     |  |                                                               
|-------------------- |  | --- |  | --------------------------------------------------------------
|Name                 |  | Age |  | Position with our
 General Partner and KMR                    
|                     |  |     |  |                                                               
|Richard D. Kinder    |  | 63  |  | Director, Chairman and Chief Executive Officer                
|C. Park Shaper       |  | 39  |  | Director and President                                        
|Steven J. Kean       |  | 46  |  | Executive Vice President and Chief Operating Officer          
|Edward O. Gaylord    |  | 76  |  | Director                                                      
|Gary L. Hultquist    |  | 64  |  | Director                                                      
|Perry M. Waughtal    |  | 72  |  | Director                                                      
|Kimberly A. Dang     |  | 38  |  | Vice President, Investor Relations and Chief Financial Officer
|Jeffrey R. Armstrong |  | 39  |  | Vice President (President, Terminals)                         
|Thomas A. Bannigan   |  | 54  |  | Vice President (President, Products Pipelines)                
|Richard T. Bradley   |  | 52  |  | Vice President (President, CO2)                               
|David D. Kinder      |  | 33  |  | Vice President, Corporate Development and Treasurer           
|Joseph Listengart    |  | 39  |  | Vice President, General Counsel and Secretary                 
|Scott E. Parker      |  | 47  |  | Vice President (President, Natural Gas Pipelines)             
|James E. Street      |  | 51  |  | Vice President, Human Resources and Administration            

Richard
D. Kinder is
Director, Chairman and Chief Executive Officer of KMR, Kinder Morgan G.P., Inc.
and Knight. Mr. Kinder has served as Director, Chairman and Chief Executive
Officer of KMR since its formation in February 2001. He was elected Director,
Chairman and Chief Executive Officer of Knight in October 1999. He was elected
Director, Chairman and Chief Executive Officer of Kinder Morgan G.P., Inc. in
February 1997. Mr. Kinder was elected President of KMR, Kinder Morgan G.P.,
Inc. and Knight in July 2004 and served as President until May 2005. He has
also served as Chief Manager, and as a member of the Board of Managers of Knight
Holdco LLC since May 2007. Mr. Kinder is
the uncle of David Kinder, Vice President, Corporate Development and Treasurer
of KMR, Kinder Morgan G.P., Inc. and Knight.

C.
Park Shaper is
Director and President of KMR, Kinder Morgan G.P., Inc. and
Knight. Mr. Shaper was elected President of KMR, Kinder Morgan G.P., Inc. and
Knight in May 2005. He served as Executive Vice President of KMR, Kinder Morgan
G.P., Inc. and Knight from July 2004 until May 2005. Mr. Shaper was elected
Director of KMR and Kinder Morgan G.P., Inc. in January 2003 and of Knight in
May of 2007. He was elected
Vice President, Treasurer and Chief Financial Officer of KMR upon its formation
in February 2001, and served as its Treasurer until January 2004, and its Chief
Financial Officer until May 2005. He was elected Vice President, Treasurer and
Chief Financial Officer of Knight in January 2000, and served as its Treasurer
until January 2004, and its Chief Financial Officer until May 2005. Mr. Shaper
was elected Vice President, Treasurer and Chief Financial Officer of Kinder
Morgan G.P., Inc. in January 2000, and served as its Treasurer until January
2004 and its Chief Financial Officer until May 2005. He has also served as
President, and as a member of the Board of Managers, of Knight Holdco LLC since
May 2007. He received a Masters of
Business Administration degree from the J.L. Kellogg Graduate School of
Management at Northwestern University. Mr. Shaper also has a Bachelor of
Science degree in Industrial Engineering and a Bachelor of Arts degree in
Quantitative Economics from Stanford University. Mr. Shaper is also a trust
manager of Weingarten Realty Investors.

Steven
J. Kean is
Executive Vice President and Chief Operating Officer of KMR, Kinder Morgan
G.P., Inc. and Knight. Mr. Kean was elected Executive Vice President and Chief
Operating Officer of KMR, Kinder Morgan G.P., Inc. and Knight in January 2006.
He served as Executive Vice President, Operations of KMR, Kinder Morgan G.P.,
Inc. and Knight from May 2005 to January 2006. He served as President, Texas
Intrastate Pipeline Group from June

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2002 until May 2005. He served as Vice President of Strategic Planning
for the Kinder Morgan Gas Pipeline Group from January 2002 until June 2002. He
has also served as Chief Operating Officer, and as a member of the Board of
Managers, of Knight Holdco LLC since May 2007.
Mr. Kean received his Juris Doctor from the University of Iowa in May 1985 and
received a Bachelor of Arts degree from Iowa State University in May 1982.

Edward
O. Gaylord is a
Director of KMR and Kinder Morgan G.P., Inc. Mr. Gaylord was elected Director
of KMR upon its formation in February 2001. Mr. Gaylord was elected Director of
Kinder Morgan G.P., Inc. in February 1997. Since 1989, Mr. Gaylord has been the
Chairman of the board of directors of Jacintoport Terminal Company, a liquid
bulk storage terminal on the Houston, Texas ship channel.

Gary
L. Hultquist is a
Director of KMR and Kinder Morgan G.P., Inc. Mr. Hultquist was elected Director
of KMR upon its formation in February 2001. He was elected Director of Kinder
Morgan G.P., Inc. in October 1999. Since 1995, Mr. Hultquist has been the
Managing Director of Hultquist Capital, LLC, a San Francisco-based strategic
and merger advisory firm.

Perry M.
Waughtal is a
Director of KMR and Kinder Morgan G.P., Inc. Mr. Waughtal was elected Director
of KMR upon its formation in February 2001. Mr. Waughtal was elected Director
of Kinder Morgan G.P., Inc. in April 2000. Since 1994, Mr. Waughtal has been
the Chairman of Songy Partners Limited, an Atlanta, Georgia based real estate
investment company. Mr. Waughtal is also a director of HealthTronics, Inc.

Kimberly
A. Dang is Vice
President, Investor Relations and Chief Financial Officer of KMR, Kinder Morgan
G.P., Inc. and Knight. Mrs. Dang was elected Chief Financial Officer of KMR,
Kinder Morgan G.P., Inc. and Knight in May 2005. She served as Treasurer of
KMR, Kinder Morgan G.P., Inc. and Knight from January 2004 to May 2005. She was
elected Vice President, Investor Relations of KMR, Kinder Morgan G.P., Inc. and Knight in July 2002. From
November 2001 to July 2002, she served as Director, Investor Relations of KMR,
Kinder Morgan G.P., and Knight. From May 2001 until November 2001, Mrs. Dang
was an independent financial consultant. From September 2000 until May 2001,
she served as an associate and later a principal at Murphree Venture Partners,
a venture capital firm. She has also served
as Chief Financial Officer of Knight Holdco LLC since May 2007. Mrs. Dang has
received a Masters in Business Administration degree from the J.L. Kellogg
Graduate School of Management at Northwestern University and a Bachelor of
Business Administration degree in accounting from Texas A&M University.

Jeffrey
R. Armstrong is
Vice President (President, Terminals) of KMR and Kinder Morgan G.P., Inc. Mr.
Armstrong became Vice President (President, Terminals) in July 2003. He
served as President, Kinder Morgan Liquids Terminals LLC from March 1, 2001,
when the company was formed via the acquisition of GATX Terminals, through July
2003. From 1994 to 2001, Mr. Armstrong worked for GATX Terminals, where he was
General Manager of their East Coast operations. He received his Bachelors
degree from the United States Merchant Marine Academy and an MBA from the
University of Notre Dame.

Thomas
A. Bannigan is
Vice President (President, Products Pipelines) of KMR and Kinder Morgan G.P.,
Inc. and President and Chief Executive Officer of Plantation Pipe Line Company.
Mr. Bannigan was elected Vice President (President, Products Pipelines) of KMR
upon its formation in February 2001. He was elected Vice President (President,
Products Pipelines) of Kinder Morgan G.P., Inc. in October 1999. Mr. Bannigan
has served as President and Chief Executive Officer of Plantation Pipe Line
Company since May 1998. Mr. Bannigan received his Juris Doctor, cum laude, from
Loyola University in 1980 and received a Bachelors degree from the State University
of New York in Buffalo.

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Richard
T. Bradley is Vice
President (President, CO2) of KMR and of Kinder Morgan G.P., Inc.
and President of Kinder Morgan CO2 Company, L.P. Mr. Bradley was
elected Vice President (President, CO2) of KMR upon its formation in
February 2001 and Vice President (President, CO2) of Kinder Morgan
G.P., Inc. in April 2000. Mr. Bradley has been President of Kinder Morgan CO2
Company, L.P. (formerly known as Shell CO2 Company, Ltd.) since
March 1998. Mr. Bradley received a Bachelor of Science in Petroleum Engineering
from the University of Missouri at Rolla.

David
D. Kinder is Vice
President, Corporate Development and Treasurer of KMR, Kinder Morgan G.P., Inc.
and Knight. Mr. Kinder was elected Treasurer of KMR, Kinder Morgan G.P., Inc.
and Knight in May 2005. He was elected Vice President, Corporate Development of
KMR, Kinder Morgan G.P., Inc. and Knight in October 2002. He served as
manager of corporate development for Knight and Kinder Morgan G.P., Inc. from January
2000 to October 2002. He has also served as
Treasurer of Knight Holdco LLC since May 2007. Mr. Kinder graduated cum laude
with a Bachelors degree in Finance from Texas Christian University in 1996. Mr.
Kinder is the nephew of Richard D. Kinder.

Joseph
Listengart is Vice
President, General Counsel and Secretary of KMR, Kinder Morgan G.P., Inc. and
Knight. Mr. Listengart was elected Vice President, General Counsel and
Secretary of KMR upon its formation in February 2001. He was elected Vice President
and General Counsel of Kinder Morgan G.P., Inc. and Vice President, General
Counsel and Secretary of Knight in October 1999. Mr. Listengart was elected
Secretary of Kinder Morgan G.P., Inc. in November 1998 and has been an employee
of Kinder Morgan G.P., Inc. since March 1998. He has also served as General
Counsel and Secretary of Knight Holdco LLC since May 2007. Mr. Listengart
received his Masters in Business Administration from Boston University in
January 1995, his Juris Doctor, magna cum laude, from Boston University in May
1994, and his Bachelor of Arts degree in Economics from Stanford University in
June 1990.

Scott
E. Parker is Vice
President (President, Natural Gas Pipelines) of KMR, Kinder Morgan G.P., Inc.
and Knight. He was elected Vice President (President, Natural Gas
Pipelines) of KMR, Kinder Morgan G.P., Inc. and Knight in May 2005. Mr. Parker
served as President of NGPL from March 2003 to May 2005. Mr. Parker served as
Vice President, Business Development of NGPL from January 2001 to March 2003.
He held various positions at NGPL from January 1984 to January 2001. Mr. Parker
holds a Bachelors degree in accounting from Governors State University.

James
E. Street is Vice
President, Human Resources and Administration of KMR, Kinder Morgan G.P., Inc.
and Knight. Mr. Street was elected Vice President, Human Resources and
Administration of KMR upon its formation in February 2001. He was elected Vice
President, Human Resources and Administration of Kinder Morgan G.P., Inc. and
Knight in August 1999. Mr. Street received a Masters of Business Administration
degree from the University of Nebraska at Omaha and a Bachelor of Science
degree from the University of Nebraska at Kearney.

Corporate
Governance

We
have a separately designated standing audit committee established in accordance
with Section 3(a)(58)(A) of the Securities Exchange Act of 1934 comprised of
Messrs. Gaylord, Hultquist and Waughtal. Mr. Gaylord is the chairman of the
audit committee and has been determined by the board to be an audit committee
financial expert. The board has determined that all of the members of the
audit committee are independent as described under the relevant standards.

We
have not, nor has our general partner nor KMR, made, within the preceding three
years, contributions to any tax-exempt organization in which any of our or
KMRs independent directors serves as an executive officer that in any single
fiscal year exceeded the greater of $1.0 million or 2% of such tax-exempt
organizations consolidated gross revenues.

On
April 11, 2007, our chief executive officer certified to the New York Stock
Exchange, as required by Section 303A.12(a) of the New York Stock Exchange
Listed Company Manual, that as of April 11, 2007, he was not aware of any
violation by us of the New York Stock Exchanges Corporate Governance listing
standards. We have also filed as an exhibit to this report the Sarbanes-Oxley
Act Section 302 certifications regarding the quality of our public disclosure.

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We
make available free of charge within the Investors information section of our
Internet website, at www.kindermorgan.com, and in print to any unitholder who
requests, the governance guidelines, the charters of the audit committee,
compensation committee and nominating and governance committee, and our code of
business conduct and ethics (which applies to senior financial and accounting
officers and the chief executive officer, among others). Requests for copies
may be directed to Investor Relations, Kinder Morgan Energy Partners, L.P., 500
Dallas Street, Suite 1000, Houston, Texas 77002, or telephone (713) 369-9490.
We intend to disclose any amendments to our code of business conduct and ethics
that would otherwise be disclosed on Form 8-K and any waiver from a provision
of that code granted to our executive officers or directors that would
otherwise be disclosed on Form 8-K on our Internet website within four business
days following such amendment or waiver. The information contained on or connected
to our Internet website is not incorporated by reference into this Form 10-K
and should not be considered part of this or any other report that we file with
or furnish to the SEC.

Interested
parties may contact our lead director, the chairpersons of any of the boards
committees, the independent directors as a group or the full board by mail to
Kinder Morgan Management, LLC, 500 Dallas Street, Suite 1000, Houston, Texas
77002, Attention: General Counsel, or by e-mail within the Contact Us section
of our Internet website, at www.kindermorgan.com. Any communication should
specify the intended recipient.

Section
16(a) Beneficial Ownership Reporting Compliance

Section
16 of the Securities Exchange Act of 1934 requires our directors and officers,
and persons who own more than 10% of a registered class of our equity
securities, to file initial reports of ownership and reports of changes in
ownership with the Securities and Exchange Commission. Such persons are
required by SEC regulation to furnish us with copies of all Section 16(a) forms
they file.

Based solely
on our review of the copies of such forms furnished to us and written
representations from our executive officers and directors, we believe that all
Section 16(a) filing requirements were met during 2007.

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Item 11.Executive Compensation.

As is commonly the case for publicly traded limited partnerships, we have no officers. Under our limited partnership agreement, Kinder Morgan G.P., Inc., as our general partner, is to direct, control and manage all of our activities. Pursuant to a delegation of control agreement, Kinder Morgan G.P., Inc. has delegated to KMR the management and control of our business and affairs to the maximum extent permitted by our partnership agreement and Delaware law, subject to our general partners right to approve certain actions by KMR. The executive officers and directors of Kinder Morgan G.P., Inc. serve in the same capacities for KMR. Certain of those executive officers also serve as executive officers of Knight, formerly KMI,
and of Knight Holdco LLC, Knight's privately owned parent company.  Except as indicated otherwise, all information in this report with respect to compensation of executive officers describes the total compensation received by those persons in all capacities for services rendered to us, our subsidiaries and our affiliates, including Knight and Knight Holdco LLC.  In this Item 11,
we, our or us refers to Kinder Morgan Energy Partners, L.P. and, where appropriate, Kinder Morgan G.P., Inc., KMR and Knight.

Compensation Discussion and Analysis

Program Objectives

We are a publicly traded master limited partnership, and our businesses consist of a diversified portfolio of energy transportation, storage and production assets. We seek to attract and retain executives who will help us achieve our primary business strategy objective of growing the value of our portfolio of businesses for the benefit of our unitholders. To help accomplish this goal, we have designed an executive compensation program that rewards individuals with competitive compensation that consists of a mix of cash, benefit plans and long-term compensation, with a majority of executive compensation tied to the at risk portions of the annual cash bonus.

The key objectives of our executive compensation program are to attract, motivate and retain executives who will advance our overall business strategies and objectives to create and return value to our unitholders. We believe that an effective executive compensation program should link total compensation to financial performance and to the attainment of short- and long-term strategic, operational, and financial objectives. We also believe it should provide competitive total compensation opportunities at a reasonable cost. In designing our executive compensation program, we have recognized that our executives have a much greater portion of their overall compensation at-risk than do our other employees; consequently, we have tried to establish the at-risk portions of our executive total compensation at levels that recognize their much increased level of responsibility and their ability to
influence business results.

Currently, our executive compensation program is principally comprised of the following two elements: (i) base cash salary; and (ii) possible annual cash bonus (reflected in the Summary Compensation Table below as Non-Equity Incentive Plan Compensation). It has been our philosophy to pay our executive officers a base salary not to exceed $200,000, which we believe is below annual base salaries for comparable positions in the marketplace. At its January 2008 meeting, KMRs compensation committee (discussed more fully below) agreed to raise the cap for our executive officers base salaries to an annual amount not to exceed $300,000. No increases above $200,000 have been implemented at this time. If this increase was implemented, we believe the base salaries paid to our executive officers would continue to be below the industry average for similarly positioned executives. While not awarded by us, KMR

compensation committee was aware of the units awarded by Knight Holdco LLC (as discussed more fully below) and took these awards into account as components of the total compensation received by our executive officers.

In addition, we believe that the compensation of our Chief Executive Officer, Chief Financial Officer and the executives named below, collectively referred to in this Item 11 as our named executive officers, should be directly and materially tied to the financial performance of Knight and us, and should be aligned with the interests of our unitholders. Therefore, the majority of our named executive officers compensation is allocated to the at risk portion of our compensation programthe annual cash bonus. Accordingly, for 2007, our executive compensation was weighted toward the cash bonus, payable on the basis of achieving (i) an earnings before interest, taxes, depreciation, depletion and amortization (referred to as EBITDA) less capital spending target by Knight; and (ii) a cash distribution per common unit target by us.



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We periodically compare our executive compensation components with market information. The purpose of this comparison is to ensure that our total compensation package operates effectively, remains both reasonable and competitive with the energy industry, and is generally comparable to the compensation offered by companies of similar size and scope as us. We also keep abreast of current trends, developments, and emerging issues in executive compensation, and if appropriate, will obtain advice and assistance from outside legal, compensation or other advisors.

We have endeavored to design our executive compensation program and practices with appropriate consideration of all tax, accounting, legal and regulatory requirements. Section 162(m) of the Internal Revenue Code limits the deductibility of certain compensation for our executive officers to $1,000,000 of compensation per year; however, if specified conditions are met, certain compensation may be excluded from consideration of the $1,000,000 limit. Since the bonuses paid to our executive officers are paid under Knights Annual Incentive Plan as a result of reaching designated financial targets established by KMRs and Knights compensation committees, we expect that all compensation paid to our executives would qualify for deductibility under federal income tax rules. Though we are advised that we and private companies, such as Knight, are not subject to section 162(m), we and
Knight have chosen to generally operate as if this code section does apply to us and Knight as a measure of appropriate governance.

Prior to 2006, long-term equity awards comprised a third element of our executive compensation program. These awards primarily consisted of grants of restricted KMI stock and grants of non-qualified options to acquire shares of KMI common stock, both pursuant to the provisions of KMIs Amended and Restated 1999 Stock Plan, referred to in this report as the KMI stock plan. Prior to 2003, we used both KMI stock options and restricted KMI stock as the principal components of long-term executive compensation, and beginning in 2003, we used grants of restricted stock exclusively as the principal component of long-term executive compensation. For each of the years ended December 31, 2006 and 2007, no restricted stock or options to purchase shares of KMI, KMP or KMR were granted to any of our named executive officers.

Additionally, in connection with KMIs going-private transaction, Knight Holdco LLC awarded members of Knights management Class A-1 and Class B units of Knight Holdco LLC. In accordance with SFAS No. 123R, Knight Holdco LLC is required to recognize compensation expense in connection with the Class A-1 and Class B units over the expected life of such units. As a subsidiary of Knight Holdco LLC, we are, under accounting rules, allocated a portion of this compensation expense, although none of us or any of our subsidiaries have any obligation, nor do we expect, to pay any amounts in respect of such units. For more information concerning the Knight Holdco LLC units, see Item 13. Certain Relationships and Related Transactions, and Director IndependenceRelated TransactionsKMI Going-Private Transaction.

Behaviors Designed to Reward

Our executive compensation program is designed to reward individuals for advancing our business strategies and the interests of our stakeholders, and we prohibit engaging in any detrimental activities, such as performing services for a competitor, disclosing confidential information or violating appropriate business conduct standards. Each executive is held accountable to uphold and comply with company guidelines, which require the individual to maintain a discrimination-free workplace, to comply with orders of regulatory bodies, and to maintain high standards of operating safety and environmental protection.

Unlike many companies, we have no executive perquisites and, with respect to our United States-based executives, we have no supplemental executive retirement, non-qualified supplemental defined benefit/contribution, deferred compensation or split dollar life insurance programs. Additionally, we do not have employment agreements (other than with our Chairman and Chief Executive Officer, Richard D. Kinder), special severance agreements or change of control agreements for our U.S. executives. Our executives are eligible for the same severance policy as our workforce, which caps severance payments to an amount equal to six months of salary. We have no executive company cars or executive car allowances nor do we offer or pay for financial planning services. Additionally, we do not own any corporate aircraft and we do not pay for executives to fly first class. We believe that we are currently
below competitive levels for comparable companies in this area of our overall compensation package; however, we have no current plans to change our policy of not offering such executive benefits, perquisite programs or special executive severance arrangements.



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At his request, Mr. Richard D. Kinder, our Chairman and Chief Executive Officer, receives $1 of base salary per year. Additionally, Mr. Kinder has requested that he receive no annual bonus, unit grants, or other compensation from us. Mr. Kinder does not have any deferred compensation, supplemental retirement or any other special benefit, compensation or perquisite arrangement with us. Each year Mr. Kinder reimburses us for his portion of health care premiums and parking expenses. Mr. Kinder was awarded Class B units by and in Knight Holdco LLC in connection with KMIs going-private transaction, and while we are, under accounting rules, allocated compensation expense attributable to such Class B units, we have no obligation, nor do we expect, to pay any amounts in connection with the Class B units.

Elements of Compensation

As outlined above, our executive compensation program currently is principally comprised of the following two elements: (i) a base cash salary; and (ii) a possible annual cash bonus. With regard to our named executive officers other than our Chief Executive Officer, KMRs compensation committee reviews and approves annually the financial goals and objectives of both Knight and us that are relevant to the compensation of our named executive officers. Generally following the regularly scheduled fourth quarter board meeting in each year, the committee solicits information from other directors, the Chief Executive Officer and other relevant members of senior management regarding the performance of our named executive officers other than our Chief Executive Officer during that year. Our Chief Executive Officer makes compensation recommendations to the committee with respect to our named
executive officers, other than himself. The committee obtains the information and the recommendations prior to the regularly scheduled first quarter board meeting.

Annually, at KMRs regularly scheduled first quarter board meeting, the committee evaluates the performance of our named executive officers other than our Chief Executive Officer and makes determinations regarding the terms of their continued employment and compensation for that year. If the committee deems it advisable, it may, rather than determine the terms of continued employment and compensation for the named executive officers (other than the Chief Executive Officer), make a recommendation with respect thereto to the independent members of the board, who make the determination at the first quarter board meeting. The committee also determines bonuses for the prior year based on the performance targets set therefor, and sets performance targets for the present year for bonus and other relevant purposes.

If any of KMRs or our general partners executive officers is also an executive officer of Knight, the committees compensation determination or recommendation (i) may be with respect to the aggregate compensation to be received by such officer from Knight, KMR, and our general partner that is to be allocated among them in accordance with procedures approved by the committee, if such aggregate compensation set by the committee and that set by the committee or the board of KMR are the same, or alternatively (ii) may be with respect to the compensation to be received by such executive officers from Knight, KMR or our general partner, as the case may be, in which case such compensation will not be allocated among Knight, on the one hand, and KMR, our general partner and us, on the other. Thereafter, the committee or the Chief Executive Officer will discuss the committees
evaluation and the determination as to compensation with the named executive officers.

In addition, the compensation committee has the sole authority to retain (and terminate as necessary) and compensate any compensation consultants, counsel and other firms of experts to advise it as it determines necessary or appropriate. The committee has the sole authority to approve any such firms fees and other retention terms, and we and Knight, as applicable, will make adequate provision for the payment of all fees and other compensation, approved by the committee, to any such firm employed by the committee. The committee also has sole authority to determine if any compensation consultant is to be used to assist in the evaluation of director, Chief Executive Officer or senior executive compensation and will have sole authority to retain and terminate any such compensation consultant and to approve the consultants fees and other retention terms.

Base Salary

Base salary is paid in cash. For each of the years 2007 and 2006, all of our named executive officers, with the exception of our Chairman and Chief Executive Officer who receives $1 of base salary per year as described above, were paid a base salary of $200,000 per year. At KMRs first quarter 2008 board meeting, the compensation committee agreed to raise the base salary cap for our executive officers, beginning in 2008, to an annual amount not



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to exceed $300,000. No increases above $200,000 have been implemented at this time. Generally, we believe that our executive officers base salaries are (and will continue to be following any implementation of the previously described increase) below base salaries for executives in similar positions and with similar responsibilities at companies of comparable size and scope.

Possible Annual Cash Bonus (Non-Equity Cash Incentive)

Our possible annual cash bonuses are provided for under Knights Annual Incentive Plan, which became effective January 18, 2005. The overall purpose of the Knight Annual Incentive Plan is to increase our executive officers and our employees personal stake in the continued success of Knight and us by providing them additional incentives through the possible payment of annual cash bonuses. Under the plan, annual cash bonuses may be paid to our executive officers and other employees depending on a variety of factors, including their individual performance, Knights financial performance, the financial performance of Knights subsidiaries (including us), safety and environmental goals and regulatory compliance.

The plan is administered by the compensation committee of Knights board of directors. The compensation committee is authorized to grant awards under the plan, interpret the plan, adopt rules and regulations for carrying out the plan, and make all determinations necessary or advisable for the administration of the plan.

All of the employees of Knight and its subsidiaries, including KMGP Services Company, Inc., are eligible to participate in the plan, except employees who are included in a unit of employees covered by a collective bargaining agreement unless such agreement expressly provides for eligibility under the plan. However, only eligible employees who are selected by the KMR and Knight compensation committees will actually participate in the plan and receive bonuses.

The plan consists of two components:  the executive plan component and the non-executive plan component. Our Chairman and Chief Executive Officer and all employees who report directly to the Chairman are eligible for the executive plan component; however, as stated elsewhere in this report, Mr. Richard D. Kinder, our Chairman and Chief Executive Officer, has elected to not participate under the plan. As of January 31, 2008, excluding Mr. Richard D. Kinder, eleven of our current executive officers were eligible to participate in the executive plan component. All other U.S. eligible employees were eligible for the non-executive plan component.

The KMR compensation committee determines which of our eligible employees will be eligible to participate under the executive plan component of the plan. At or before the start of each calendar year (or later, to the extent allowed under Internal Revenue Code regulations), performance objectives for that year are identified. The performance objectives are based on one or more of the criteria set forth in the plan. The KMR compensation committee establishes a bonus opportunity for each executive officer, which is our portion of the amount of the bonus the executive officer will earn if the performance objectives are fully satisfied. The compensation committee may specify a minimum acceptable level of achievement of each performance objective below which no bonus is payable with respect to that objective. The compensation committee may set additional levels above the minimum (which may also
be above the targeted performance objective), with a formula to determine the percentage of the bonus opportunity to be earned at each level of achievement above the minimum. Performance at a level above the targeted performance objective may entitle the executive officer to earn a bonus in excess of 100% of the bonus opportunity. However, the maximum payout to any individual under the plan for any year is $2.0 million, and the KMR compensation committee has the discretion to reduce the bonus amount payable by us in any performance period.

Performance objectives may be based on one or more of the following criteria:


        Knights EBITDA less capital spending, or the EBITDA less capital spending of one of its subsidiaries or business units;



        Knights net income or the net income of one of its subsidiaries or business units;



        Knights revenues or the revenues of one of its subsidiaries or business units;




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
        Knights unit revenues minus unit variable costs or the unit revenues minus unit variable costs of one of its subsidiaries or business units;



        Knights return on capital, return on equity, return on assets, or return on invested capital, or the return on capital, return on equity, return on assets, or return on invested capital of one of its subsidiaries or business units;



        Knights cash flow return on assets or cash flows from operating activities, or the cash flow return on assets or cash flows from operating activities of one of its subsidiaries or business units;



        Knights capital expenditures or the capital expenditures of one of its subsidiaries or business units;



        Knights operations and maintenance expense or general and administrative expense, or the operations and maintenance expense or general and administrative expense of one of its subsidiaries or business units; or



        Knights debt-equity ratios and key profitability ratios, or the debt-equity ratios and key profitability ratios of one of its subsidiaries or business units.


The KMR compensation committee set two performance objectives for 2007 under both the executive plan component and the non-executive plan component. The 2007 performance objectives were $3.44 in cash distributions per common unit at KMP, and $1,089.5 million of EBITDA less capital spending at Knight. These targets were the same as our and Knights previously disclosed 2007 budget expectations. At the end of 2007, the KMR compensation committee determined and certified in writing the extent to which the performance objectives had been attained and the extent to which the bonus opportunity had been earned under the formula previously established by the KMR compensation committee. In 2007, both we and Knight exceeded our established targets.

The table below sets forth the bonus opportunities that could have been payable by us and Knight to our executive officers if the performance objectives established by the KMR compensation committee for 2007 had been 100% achieved. The KMR compensation committee may, at its sole discretion, reduce the amount of the portion of the bonus actually paid by us to any executive officer under the plan from the amount of any bonus opportunity open to such executive officer; and, because payments under the plan for our executive officers are determined by comparing actual performance to the performance objectives established by the compensation committee each year for eligible executive officers chosen to participate for that year, it is not possible to accurately predict any amounts that will actually be paid under the executive plan portion of the plan over the life of the plan. The compensation
committee set bonus opportunities under the plan for 2007 for the executive officers at dollar amounts in excess of that which were expected to actually be paid under the plan. The actual payout amounts under the Non-Equity Incentive Plan Awards made in 2007 are set forth in the Summary Compensation Table in this report in the column entitled Non-Equity Incentive Plan Compensation.



Knight Annual Incentive PlanBonus Opportunities for 2007




Name and Principal Position
        
        Dollar ValueRichard D. Kinder, Chairman and Chief Executive Officer..................
        
        $
        
        (1)Kimberly A. Dang, Vice President and Chief Financial Officer.............
        
        
        1,000,000
        (2)Steven J. Kean, Executive Vice President and Chief Operating Officer....
        
        
        1,500,000
        (3)Scott E. Parker, Vice President (President, Natural Gas Pipelines)..........
        
        
        1,500,000
        (3)C. Park Shaper, Director and President..........................................
        
        
        1,500,000
        (3)






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_______________

(1)
        Declined to participate.


(2)
        Under the plan, for 2007, if neither of the targets was met, no bonus opportunities would have been provided; if one of the targets was met, $500,000 in bonus opportunities would have been available; if both of the targets had been exceeded by 10%, $1,500,000 in bonus opportunities would have been available. The KMR compensation committee may, in its sole discretion, reduce the award payable by us to any participant for any reason.


(3)
        Under the plan, for 2007, if neither of the targets was met, no bonus opportunities would have been provided; if one of the targets was met, $750,000 in bonus opportunities would have been available; if both of the targets had been exceeded by 10%, $2,000,000 in bonus opportunities would have been available. The KMR compensation committee may, in its sole discretion, reduce the award payable by us to any participant for any reason.


Knight may amend the plan from time to time without shareholder approval except as required to satisfy the Internal Revenue Code or any applicable securities exchange rules. Awards may be granted under the plan for calendar years 2008 through 2009, unless the plan is terminated earlier by Knight. However, the plan will remain in effect until payment has been completed with respect to all awards granted under the plan prior to its termination.

Other Compensation

Knight Inc. Savings Plan.The Knight Inc. Savings Plan is a defined contribution 401(k) plan. The plan permits all full-time employees of Knight and KMGP Services Company, Inc., including the named executive officers, to contribute between 1% and 50% of base compensation, on a pre-tax basis, into participant accounts. In addition to a mandatory contribution equal to 4% of base compensation per year for most plan participants, our general partner may make special discretionary contributions. Certain employees contributions are based on collective bargaining agreements. The mandatory contributions are made each pay period on behalf of each eligible employee. Participants may direct the investment of both their contributions and employer contributions into a variety of investments at the employees discretion. Plan assets are held and distributed pursuant
to a trust agreement.

Employer contributions for employees vest on the second anniversary of the date of hire. Effective October 1, 2005, for new employees of our Terminals business segment, a tiered employer contribution schedule was implemented. This tiered schedule provides for employer contributions of 1% for service less than one year, 2% for service between one and two years, 3% for service between two and five years, and 4% for service of five years or more. All employer contributions for employees of our Terminals business segment hired after October 1, 2005 vest on the fifth anniversary of the date of hire (effective January 1, 2008, this five year anniversary date for Terminals employees was changed to three years to comply with changes in federal regulations).

At its July 2007 meeting, the compensation committee of the KMR and Knight boards of directors approved a special contribution of an additional 1% of base pay into the Savings Plan for each eligible employee. Each eligible employee will receive an additional 1% company contribution based on eligible base pay each pay period beginning with the first pay period of August 2007 and continuing through the last pay period of July 2008. The additional 1% contribution does not change or otherwise impact, the annual 4% contribution that eligible employees currently receive. It may be converted to any other Savings Plan investment fund at any time and it will vest according to the same vesting schedule described in the preceding paragraph. Since this additional 1% company contribution is discretionary, KMR and Knight compensation committee approvals will be required annually for each additional
contribution. During the first quarter of 2008, excluding our portion of the 1% additional contribution described above, we will not make any additional discretionary contributions to individual accounts for 2007.

Additionally, in 2006, an option to make after-tax Roth contributions (Roth 401(k) option) to a separate participant account was added to the Savings Plan as an additional benefit to all participants. Unlike traditional 401(k) plans, where participant contributions are made with pre-tax dollars, earnings grow tax-deferred, and the withdrawals are treated as taxable income, Roth 401(k) contributions are made with after-tax dollars, earnings are tax-free, and the withdrawals are tax-free if they occur after both (i) the fifth year of participation in the Roth 401(k) option, and (ii) attainment of age 59 1⁄2, death or disability. The employer contribution will still be considered taxable income at the time of withdrawal.



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Knight Inc. Cash Balance Retirement Plan.Employees of KMGP Services Company, Inc. and Knight, including our named executive officers, are also eligible to participate in a Cash Balance Retirement Plan. Certain employees continue to accrue benefits through a career-pay formula, grandfathered according to age and years of service on December 31, 2000, or collective bargaining arrangements. All other employees accrue benefits through a personal retirement account in the Cash Balance Retirement Plan. Under the plan, we make contributions on behalf of participating employees equal to 3% of eligible compensation every pay period. Interest is credited to the personal retirement accounts at the 30-year U.S. Treasury bond rate, or an approved substitute, in effect each year. Employees become fully vested in the plan after five years, and they may take a lump
sum distribution upon termination of employment or retirement.

The following table sets forth the estimated actuarial present value of each named executive officers accumulated pension benefit as of December 31, 2007, under the provisions of the Cash Balance Retirement Plan. With respect to our named executive officers, the benefits were computed using the same assumptions used for financial statement purposes, assuming current remuneration levels without any salary projection, and assuming participation until normal retirement at age sixty-five. These benefits are subject to federal and state income taxes, where applicable, but are not subject to deduction for social security or other offset amounts.



Pension BenefitsCurrent
        
        Present Value ofCredited Yrs
        
        Accumulated
        
        ContributionsName
        
        
        Plan Name
        
        of Service
        
        Benefit(1)
        
        During 2007Richard D. Kinder
        
        
        Cash Balance
        
        7
        $
        
        
        $
        Kimberly A. Dang
        
        
        Cash Balance
        
        6
        
        31,408
        
        
        7,294Steven J. Kean
        
        
        Cash Balance
        
        6
        
        41,724
        
        
        7,767Scott E. Parker
        
        
        Cash Balance
        
        9
        
        71,515
        
        
        9,130C. Park Shaper
        
        
        Cash Balance
        
        7
        
        51,079
        
        
        8,194




__________



(1)
        The present values in the Pension Benefits table are based on certain assumptions-including a 5.75% discount rate, RP 2000 mortality (post-retirement only), 5% cash balance interest crediting rate, and lump sums calculated using a 5% interest rate and IRS mortality. We assumed benefits would commence at normal retirement date or unreduced retirement date, if earlier. No death or turnover was assumed prior to retirement date.


Other Potential Post-Employment Benefits.On October 7, 1999, Mr. Richard D. Kinder entered into an employment agreement with Knight pursuant to which he agreed to serve as its Chairman and Chief Executive Officer. His employment agreement provides for a term of three years and one year extensions on each anniversary of October 7th. Mr. Kinder, at his initiative, accepted an annual salary of $1 to demonstrate his belief in our and Knights long term viability. Mr. Kinder continues to accept an annual salary of $1, and he receives no other compensation from us. Mr. Kinder was awarded Class B units by and in Knight Holdco LLC in connection with Knights going-private transaction, and while we, as a subsidiary of Knight Holdco LLC, are allocated compensation expense attributable
to such Class B units, we have no obligation, nor do we expect, to pay any amounts in connection with the Class B units.

Knight believes that Mr. Kinders employment agreement contains provisions that are beneficial to Knight and its subsidiaries and accordingly, Mr. Kinders employment agreement is extended annually at the request of Knight and KMRs Board of Directors. For example, with limited exceptions, Mr. Kinder is prevented from competing in any manner with Knight or any of its subsidiaries, while he is employed by Knight and for 12 months following the termination of his employment with Knight. The agreement contains provisions that address termination with and without cause, termination as a result of change in duties or disability, and death. At his current compensation level, the maximum amount that would be paid to Mr. Kinder or his estate in the event of his termination is three times $750,000, or $2.25 million. This payment would be made if
Mr. Kinder were terminated by Knight without cause or if Mr. Kinder terminated his employment with Knight as a result of a change in duties



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(as defined in the employment agreement). There are no employment agreements or change-in-control arrangements with any of our other executive officers.

Mr. Scott E. Parker elected to not participate in the going-private transaction. As a result, we offered Mr. Parker a retention agreement. The agreement was effective May 30, 2007, and lasts for three years. Mr. Parker is eligible for quarterly cash payments of $65,000, a one-time relocation payment of $100,000, and the right to participate in both the annual incentive plan and employee benefit plans. Under the terms of the agreement, Mr. Parker will also receive payments of $500,000 on May 30, 2008, $500,000 on May 30, 2009, and $2,000,000 on May 30, 2010, respectively, provided he is an active employee on each respective date. The agreement also contains confidential information, non-solicitation of employees and non-compete provisions.

Common Unit Option Plan.Pursuant to our Common Unit Option Plan, key personnel are eligible to receive grants of options to acquire common units. The total number of common units authorized under the option plan is 500,000. None of the options granted under the option plan may be incentive stock options under Section 422 of the Internal Revenue Code. If an option expires without being exercised, the number of common units covered by such option will be available for a future award. The exercise price for an option may not be less than the fair market value of a common unit on the date of grant. KMRs compensation committee determines the duration and vesting of the options to employees at the time of grant, and no individual employee may be granted options for more than 20,000 common units in any year. As of December 31, 2007, no options to
purchase common units were outstanding under the plan. KMRs compensation committee administers the option plan, and the plan has a termination date of March 5, 2008.

For the year ended December 31, 2007, no options to purchase common units were granted to or exercised by any of our executive officers, and as of December 31, 2007, none of our executive officers owned unexercised common unit options. The plan may also grant, to each of our non-employee directors, options to purchase common units at an exercise price equal to the fair market value of the common units at the end of the trading day on such date. For the year ended December 31, 2007, no options to purchase common units were granted to our non-employee directors.

Summary Compensation Table

The following table shows compensation paid or otherwise awarded to (i) our principal executive officer; (ii) our principal financial officer; and (iii) our three most highly compensated executive officers (other than our principal executive officer and principal financial officer) serving at fiscal year end 2007 (collectively referred to as the named executive officers) for services rendered to us, our subsidiaries or our affiliates, including Knight and Knight Holdco LLC (collectively referred to as the Knight affiliated entities), during fiscal years 2007 and 2006. The amounts in the columns below, except the column entitled Unit Awards by Knight Holdco LLC, represent the total compensation paid or awarded to the named executive officers by all the Knight affiliated entities, and as a result the amounts are in excess of the compensation expense
allocated to and recognized by us for services rendered to us. The amounts in the column entitled Unit Awards by Knight Holdco LLC consist of accounting expense calculated in accordance with SFAS No. 123R and allocated to us for the Knight Holdco LLC Class A-1 and Class B units awarded by Knight Holdco LLC to the named executive officers. As a subsidiary of Knight Holdco LLC, we are allocated a portion of the compensation expense recognized by Knight Holdco LLC with respect to such units, although none of us or any of our subsidiaries have any obligation, nor do we expect, to pay any amounts in respect of such units and none of the named executive officers has received any payments in respect of such units.



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(1)
        
        (2)
        
        (3)
        
        (4)
        
        (5)
        
        (6)Non-Equity
        
        
        
        
        
        Unit AwardsStock
        
        Option
        
        Incentive
        
        Change
        
        
        
        by KnightName and
        
        
        
        
        
        
        
        Awards
        
        Awards
        
        Plan
        
        in Pension
        
        All Other
        
        HoldcoPrincipal Position
        
        Year
        
        Salary
        
        Bonus
        
        by KMI
        
        by KMI
        
        Compensation
        
        Value
        
        Compensation
        
        LLC
        
        TotalRichard D. Kinder
        
        2007
        $
        1
        $
        
        $
        
        $
        
        $
        
        $
        
        $
        
        $
        1,016,000
        $
        1,016,001Director, Chairman and
        
        2006
        
        1
        
        
        
        
        
        
        
        
        
        
        
        
        
        
        
        1Chief Executive OfficerKimberly A. Dang
        
        2007
        
        200,000
        
        
        
        338,095
        
        
        
        400,000
        
        7,294
        
        32,253
        
        73,800
        
        1,051,442Vice President and
        
        2006
        
        200,000
        
        
        
        139,296
        
        37,023
        
        270,000
        
        6,968
        
        46,253
        
        
        
        699,540Chief Financial OfficerSteven J. Kean
        
        2007
        
        200,000
        
        
        
        4,397,080
        
        
        
        1,100,000
        
        7,767
        
        147,130
        
        295,010
        
        6,146,987Executive Vice President
        
        2006
        
        200,000
        
        
        
        1,591,192
        
        147,943
        
        
        
        7,422
        
        284,919
        
        
        
        2,231,476AndChief Operating OfficerScott E. Parker
        
        2007
        
        200,000
        
        
        
        2,340,080
        
        
        
        1,100,000
        
        9,130
        
        307,688
        
        
        
        3,956,898Vice President (President,
        
        2006
        
        200,000
        
        350,000
        
        881,317
        
        29,490
        
        500,000
        
        8,735
        
        164,630
        
        
        
        2,134,172Natural Gas Pipelines)C. Park Shaper
        
        2007
        
        200,000
        
        
        
        1,950,300
        
        
        
        1,200,000
        
        8,194
        
        155,953
        
        466,110
        
        3,980,557Director and President
        
        2006
        
        200,000
        
        
        
        1,134,283
        
        24,952
        
        
        
        7,835
        
        348,542
        
        
        
        1,715,612




_______________



(1)
        Consists of expense calculated in accordance with SFAS No. 123R attributable to restricted KMI stock awarded in 2003, 2004 and 2005 according to the provisions of the KMI Stock Plan. No restricted stock was awarded in 2007 or 2006. For grants of restricted stock, we take the value of the award at time of grant and accrue the expense over the vesting period according to SFAS No. 123R. For grants made July 16, 2003KMI closing price was $53.80, twenty-five percent of the shares in each grant vest on the third anniversary after the date of grant and the remaining seventy-five percent of the shares in each grant vest on the fifth anniversary after the date of grant. For grants made July 20, 2004KMI closing price was $60.79, fifty percent of the shares vest on the third anniversary after the date of grant and the remaining
fifty percent of the shares vest on the fifth anniversary after the date of grant. For grants made July 20, 2005KMI closing price was $89.48, twenty-five percent of the shares in each grant vest on the third anniversary after the date of grant and the remaining seventy-five percent of the shares in each grant vest on the fifth anniversary after the date of grant. As a result of the KMI going-private transaction, all outstanding restricted shares vested in 2007 and therefore all remaining compensation expense with respect to restricted stock was recognized in 2007 in accordance with SFAS No. 123R. However, Knight bore all of the costs associated with this acceleration.


(2)
        Consists of expense calculated in accordance with SFAS No. 123R attributable to options to purchase KMI shares awarded in 2002 and 2003 according to the provisions of the KMI Stock Plan. No options were granted in 2007 or 2006. For options granted in 2002volatility of 0.3912 using a 6 year term, 4.01% five year risk free interest rate return, and a 0.71% expected annual dividend rate. For options granted in 2003volatility of 0.3853 using a 6.25 year term, 3.37% treasury strip quote at time of grant, and a 2.973% expected annual dividend rate. As a result of the KMI going-private transaction, all outstanding options vested in 2007 and therefore all remaining compensation expense with respect to options was recognized in 2007 in accordance with SFAS No. 123R. As a condition to their being permitted to participate in the
KMI going-private transaction, Messrs. Kean and Shaper agreed to the cancellation of 10,467 and 22,031 options, respectively. These cancelled options had weighted average exercise prices of $39.12 and $24.75 per share, respectively. However, Knight bore all of the costs associated with this acceleration.


(3)
        Represents amounts paid according to the provisions of the Knight Annual Incentive Plan. In the case of Mr. Parker, for the year 2006, an additional $350,000 was paid outside of the plan, as reflected in the Bonus column. Amounts were earned in




96



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the fiscal year indicated but were paid in the next fiscal year. Messrs. Kean and Shaper refused to accept a bonus for 2006. The committee agreed that this was not a reflection of performance on either person.

(4)
        Represents the 2007 and 2006, as applicable, change in the actuarial present value of accumulated defined pension benefit (including unvested benefits) according to the provisions of Knights Cash Balance Retirement Plan.


(5)
        Amounts represent value of contributions to the Knight Savings Plan (a 401(k) plan), value of group-term life insurance exceeding $50,000, taxable parking subsidy and dividends paid on unvested restricted stock awards. Amounts each year include $10,000 representing the value of contributions to the Knight Savings Plan. Amounts representing the value of dividends paid on unvested restricted stock awards are as follows: for 2007Mrs. Dang $21,875; Mr. Kean $136,500; Mr. Parker $77,000; and Mr. Shaper $144,375; for 2006Mrs. Dang $35,875; Mr. Kean $273,000; Mr. Parker $154,000; and Mr. Shaper $336,875. Mr. Parkers 2007 amount also includes amounts for imputed income for company provided cellphone, a $100,000 relocation allowance, and a $130,000 payment to compensate for loss
of dividends associated with the KMI going-private transaction.


(6)
        Such amounts represent the amount of the non-cash compensation expense calculated in accordance with SFAS No. 123R attributable to the Class A-1 and Class B units of Knight Holdco LLC and allocated to us for financial reporting purposes but does not include any such expense allocated to Knight or any of its other subsidiaries. None of the named executive officers has received any payments in connection with such units, and none of us or our subsidiaries are obligated, nor do we expect, to pay any amounts in respect of such units. See Item 13. Certain Relationships and Related Transactions, and Director IndependenceRelated TransactionsKMI Going-Private Transaction for further discussion of these units.


KMI Stock Options and Restricted Stock

Effective with the completion of the KMI going-private transaction on May 30, 2007, all of KMIs equity compensation awards (including awards held by our named executive officers) were subject to the following treatment:


        each option or other award to purchase shares of KMI common stock granted under any Kinder Morgan employee or director equity plan, whether vested or unvested, that was outstanding immediately prior to the effective time of the buyout, vested as of the effective time of the buyout, and was cancelled and converted into the right to receive a cash payment equal to the number of shares of KMI common stock underlying such options multiplied by the amount (if any) by which the $107.50 per share merger consideration issued in the going-private transaction exceeded the option exercise price, without interest and less any applicable withholding tax; and



        each share of restricted stock or restricted stock unit under any Kinder Morgan stock plan or benefit plan vested as of the effective time of the buyout and was cancelled and converted into the right to receive a cash payment equal to the number of outstanding shares of restricted stock or restricted stock units, multiplied by the $107.50 per share merger consideration, without interest and less any applicable withholding tax.


The following table sets forth, for each of our named executive officers (i) the number of KMI stock options (all of which were vested) held by such persons; (ii) the cash value realized with respect to such stock options upon consummation of the going-private transaction; (iii) the number of shares of restricted KMI stock held by such persons; and (iv) the aggregate cash value realized with respect to such shares of restricted stock upon consummation of the going-private transaction. A portion of the consideration received by the named executive officers with respect to their options to acquire shares of KMI common stock and their restricted shares of KMI common stock was reinvested in exchange for ownership interests in Knight Holdco LLC, and certain executive officers, as a condition to their being permitted to participate as investors in Knight Holdco LLC, agreed to the cancellation of
certain of their options prior to the going-private transaction.



97



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Option Awards
        
        
        Stock AwardsStock
        
        
        Value
        
        
        Shares of
        
        
        ValueName
        
        Options
        
        
        Realized (1)
        
        
        Restricted Stock
        
        
        Realized (2)Richard D. Kinder
        
        
        
        $
        
        
        
        
        
        $
        Kimberly A. Dang
        
        24,750
        
        
        1,443,178
        
        
        8,000
        
        
        860,000Steven J. Kean(3)
        
        25,533
        
        
        1,375,772
        
        
        78,000
        
        
        8,385,000Scott E. Parker
        
        10,000
        
        
        537,000
        
        
        44,000
        
        
        4,730,000C. Park Shaper(4)
        
        197,969
        
        
        12,529,810
        
        
        82,500
        
        
        8,868,750




_______



(1)
        Calculated based on the actual exercise prices underlying the related options, as opposed to the weighted average exercise price per share of options.


(2)
        Calculated as $107.50 multiplied by the number of shares of restricted stock.


(3)
        Mr. Kean, as a condition to his being permitted to participate as an investor in Knight, agreed to the cancellation of 10,467 of his options shown above, with a weighted average exercise price of $39.12 per share, prior to the going-private transaction.


(4)
        Mr. Shaper, as a condition to his being permitted to participate as an investor in Knight, agreed to the cancellation of 22,031 of his options shown above, with a weighted average exercise price of $24.75 per share, prior to the going-private transaction.


Grants of Plan-Based Awards

The following supplemental compensation table shows compensation details on the value of all non-guaranteed and non-discretionary incentive awards granted during 2007 to our named executive officers, as well as awards of Knight Holdco LLC units received in 2007 by each named executive officer. The table includes the Knight Holdco LLC Class A-1 and Class B units awarded by Knight Holdco LLC to the named executive officers. As a subsidiary of Knight Holdco LLC, we are allocated a portion of the compensation expense recognized by Knight Holdco LLC with respect to such units, although none of us or any of our subsidiaries have any obligation to pay any amounts in respect of such units. The table includes awards made during or for 2007. The information in the table under the caption Estimated Possible Payments Under Non-Equity Incentive Plan Awards represents the threshold, target
and maximum amounts payable under the Knight Annual Incentive Plan for performance in 2007. Amounts actually paid under that plan for 2007 are set forth in the Summary Compensation Table under the caption Non-Equity Incentive Plan Compensation.  There will not be any additional payouts under the Annual Incentive Plan for 2007.



Estimated Possible Payouts Under
        
        All other stockNon-Equity Incentive Plan Awards1
        
        awards2
        
        Grant dateNumber
        
        fair valueName
        
        Grant date
        
        Threshold
        
        Target
        
        Maximum
        
        of units
        
        of stock awards3Richard D. Kinder
        
        May 30, 2007
        
        
        
        
        
        
        
        791,405,452
        
        $    9,200,000Kimberly A. Dang
        
        January 17, 2007
        
        $     500,000
        
        $  1,000,000
        
        $    1,500,000May 30, 2007
        
        
        
        
        
        
        
        49,893,032
        
        674,887Steven J. Kean
        
        January 17, 2007
        
        750,000
        
        1,500,000
        
        2,000,000May 30, 2007
        
        
        
        
        
        
        
        162,114,878
        
        2,720,252Scott E. Parker
        
        January 17, 2007
        
        500,000
        
        1,500,000
        
        2,000,000C. Park Shaper
        
        January 17, 2007
        
        750,000
        
        1,500,000
        
        2,000,000May 30, 2007
        
        
        
        
        
        
        
        225,436,274
        
        4,315,475




__________

1
        Represents grants under the Knight Annual Incentive Plan for performance in 2007. See Elements of Compensation




98



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Possible Annual Cash Bonus (Non-Equity Cash Incentive) for a discussion of these awards.

2
        Represents the sum of the number of Class A-1 units and the number of Class B units of Knight Holdco LLC awarded to the named executive officers in connection with the going-private transaction. See Item 13. Certain Relationships and Related Transactions, and Director IndependenceRelated TransactionsKMI Going-Private Transaction for detail regarding these awards.


3
        Amounts represent the fair value calculated in accordance with SFAS No. 123R attributable to Class A-1 and Class B units of Knight Holdco LLC awarded by Knight Holdco LLC to the named executive officers in connection with the going-private transaction. None of the named executive officers has received any payments in connection with such units, and none of us or our subsidiaries are obligated to pay any amounts in respect of such units. See Item 13. Certain Relationships and Related Transactions, and Director IndependenceRelated TransactionsKMI Going-Private Transaction for further discussion of these units.


Outstanding Equity Awards at Fiscal Year-End

The only unvested equity awards outstanding at the end of fiscal 2007 were the Class B units of Knight Holdco LLC awarded by Knight Holdco LLC to the named executive officers. As a subsidiary of Knight Holdco LLC, we are allocated a portion of the compensation expense recognized by Knight Holdco LLC with respect to such units, although none of us or any of our subsidiaries have any obligation, nor do we expect, to pay any amounts in respect of such units.





Stock awards:Market value ofNumber of units that
        
        units of stock thatName
        Type of units:
        
        have not vested
        
        have not vested1Richard D. Kinder
        Class B units
        
        791,405,452
        
        N/AKimberly A. Dang
        Class B units
        
        49,462,841
        
        N/ASteven J. Kean
        Class B units
        
        158,281,090
        
        N/AC. Park Shaper
        Class B units
        
        217,636,499
        
        N/A




__________



1
        Because the Class B units are equity interests of Knight Holdco LLC, a private limited liability company, the market value of such interests is not readily determinable. None of the named executive officers has received any payments in connection with such units, and none of us or our subsidiaries are obligated, nor do we expect, to pay any amounts in respect of such units. See Item 13. Certain Relationships and Related Transactions, and Director IndependenceRelated TransactionsKMI Going-Private Transaction for further discussion of these units.


Director Compensation

Compensation Committee Interlocks and Insider Participation.The compensation committee of KMR functions as our compensation committee. KMRs compensation committee, comprised of Mr. Edward O. Gaylord, Mr. Gary L. Hultquist and Mr. Perry M. Waughtal, makes compensation decisions regarding the executive officers of our general partner and its delegate, KMR. Mr. Richard D. Kinder, Mr. James E. Street, and Messrs. Shaper and Kean, who are executive officers of KMR, participate in the deliberations of the KMR compensation committee concerning executive officer compensation. None of the members of KMRs compensation committee is or has been one of our officers or employees, and none of our executive officers served during 2007 on a board of directors of another entity which has employed any of the members of KMRs
compensation committee.

Directors Fees.Beginning in 2005, awards under our Common Unit Compensation Plan for Non-Employee Directors served as compensation for each of KMRs three non-employee directors. In addition, directors are reimbursed for reasonable expenses in connection with board meetings. Directors of KMR who are also employees of Knight (Messrs. Richard D. Kinder and C. Park Shaper) do not receive compensation in their capacity as directors.

Kinder Morgan Energy Partners, L.P. Common Unit Compensation Planfor Non-Employee Directors.On January 18, 2005, KMRs compensation committee established the Kinder Morgan Energy Partners, L.P. Common



99



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Unit Compensation Plan for Non-Employee Directors. The plan is administered by KMRs compensation committee and KMRs board has sole discretion to terminate the plan at any time. The primary purpose of this plan was to promote our interests and the interests of our unitholders by aligning the compensation of the non-employee members of the board of directors of KMR with unitholders interests. Further, since KMRs success is dependent on its operation and management of our business and our resulting performance, the plan is expected to align the compensation of the non-employee members of the board with the interests of KMRs shareholders.

The plan recognizes that the compensation to be paid to each non-employee director is fixed by the KMR board, generally annually, and that the compensation is payable in cash. Pursuant to the plan, in lieu of receiving cash compensation, each non-employee director may elect to receive common units. Each election will be generally at or around the first board meeting in January of each calendar year and will be effective for the entire calendar year. The election for 2006 was made effective January 17, 2006; the election for 2007 was made effective January 17, 2007; and the election for 2008 was made effective January 16, 2008. A non-employee director may make a new election each calendar year. The total number of common units authorized under this compensation plan is 100,000.

Each annual election will be evidenced by an agreement, the Common Unit Compensation Agreement, between us and each non-employee director, and this agreement will contain the terms and conditions of each award. Pursuant to this agreement, all common units issued under this plan are subject to forfeiture restrictions that expire six months from the date of issuance. Until the forfeiture restrictions lapse, common units issued under the plan may not be sold, assigned, transferred, exchanged, or pledged by a non-employee director. In the event the directors service as a director of KMR is terminated prior to the lapse of the forfeiture restriction either for cause, or voluntary resignation, each director will, for no consideration, forfeit to us all common units to the extent then subject to the forfeiture restrictions. Common units with respect to which forfeiture restrictions have
lapsed will cease to be subject to any forfeiture restrictions, and we will provide each director a certificate representing the units as to which the forfeiture restrictions have lapsed. In addition, each non-employee director will have the right to receive distributions with respect to the common units awarded to him under the plan, to vote such common units and to enjoy all other unitholder rights, including during the period prior to the lapse of the forfeiture restrictions.

The number of common units to be issued to a non-employee director electing to receive the cash compensation in the form of common units will equal the amount of such cash compensation awarded, divided by the closing price of the common units on the New York Stock Exchange on the day the cash compensation is awarded (such price, the fair market value), rounded down to the nearest 50 common units. The common units will be issuable as specified in the Common Unit Compensation Agreement. A non-employee director electing to receive the cash compensation in the form of common units will receive cash equal to the difference between (i) the cash compensation awarded to such non-employee director and (ii) the number of common units to be issued to such non-employee director multiplied by the fair market value of a common unit. This cash payment will be payable in four equal installments generally
around March 31, June 30, September 30 and December 31 of the calendar year in which such cash compensation is awarded.

On January 17, 2007, each of KMRs three non-employee directors was awarded cash compensation of $160,000 for board service during 2007. Effective January 17, 2007, each non-employee director elected to receive certain amounts of that compensation in the form of our common units and each was issued common units pursuant to the plan and its agreements (based on the $48.44 closing market price of our common units on January 17, 2007, as reported on the New York Stock Exchange). Mr. Gaylord elected to receive compensation of $95,911.20 in the form of our common units and was issued 1,980 common units; Mr. Waughtal elected to receive compensation of $159,852.00 in the form of our common units and was issued 3,300 common units; and Mr. Hultquist elected to receive cash compensation of $96,880.00 in the form of our common units and was issued 2,000 common units. All remaining
compensation ($64,088.80 to Mr. Gaylord; $148.00 to Mr. Waughtal; and $63,120.00 to Mr. Hultquist) will be paid in cash to each of the non-employee directors as described above, and no other compensation will be paid to the non-employee directors during 2007.

On January 16, 2008, each of KMRs three non-employee directors was awarded cash compensation of $160,000 for board service during 2008; however, during a plan audit it was determined that each director was inadvertently paid an additional dividend in 2007. As a result, each directors cash compensation for service during 2008 was adjusted downward to reflect this error. The correction results in cash compensation awarded for 2008 in the amounts of $158,380.00 for Mr. Hultquist; $158,396.20 for Mr. Gaylord; and $157,327.00 for Mr. Waughtal.



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Effective January 16, 2008, two of the three non-employee directors elected to receive certain amounts of that compensation in the form of our common units and each was issued common units pursuant to the plan and its agreements (based on the $55.81 closing market price of our common units on January 16, 2008, as reported on the New York Stock Exchange). Mr. Gaylord elected to receive compensation of $84,831.20 in the form of our common units and was issued 1,520 common units; and Mr. Waughtal elected to receive compensation of $157,272.58 in the form of our common units and was issued 2,818 common units. All remaining compensation ($73,565.00 to Mr. Gaylord; $54.42 to Mr. Waughtal; and $158,380.00 to Mr. Hultquist) will be paid in cash to each of the non-employee directors as described above, and no other compensation will be paid to the non-employee directors during 2008.

Directors Unit Appreciation Rights Plan.On April 1, 2003, KMRs compensation committee established our Directors Unit Appreciation Rights Plan. Pursuant to this plan, each of KMRs three non-employee directors was eligible to receive common unit appreciation rights. Upon the exercise of unit appreciation rights, we will pay, within thirty days of the exercise date, the participant an amount of cash equal to the excess, if any, of the aggregate fair market value of the unit appreciation rights exercised as of the exercise date over the aggregate award price of the rights exercised. The fair market value of one unit appreciation right as of the exercise date will be equal to the closing price of one common unit on the New York Stock Exchange on that date. The award price of one unit appreciation right will be equal to the closing price of one
common unit on the New York Stock Exchange on the date of grant. Proceeds, if any, from the exercise of a unit appreciation right granted under the plan will be payable only in cash (that is, no exercise will result in the issuance of additional common units) and will be evidenced by a unit appreciation rights agreement.

All unit appreciation rights granted vest on the six-month anniversary of the date of grant. If a unit appreciation right is not exercised in the ten year period following the date of grant, the unit appreciation right will expire and not be exercisable after the end of such period. In addition, if a participant ceases to serve on the board for any reason prior to the vesting date of a unit appreciation right, such unit appreciation right will immediately expire on the date of cessation of service and may not be exercised.

On April 1, 2003, the date of adoption of the plan, each of KMRs three non-employee directors was granted 7,500 unit appreciation rights. In addition, 10,000 unit appreciation rights were granted to each of KMRs three non-employee directors on January 21, 2004, at the first meeting of the board in 2004. During the first board meeting of 2005, the plan was terminated and replaced by the Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for Non-Employee Directors; however, all unexercised awards made under the plan remain outstanding. No unit appreciation rights were exercised during 2006. In 2007, Mr. Hultquist exercised 7,500 unit appreciation rights and received a cash amount of $116,250. As of December 31, 2007, 45,000 unit appreciation rights had been granted, vested and remained outstanding.

The following table discloses the compensation earned by each of KMRs three non-employee directors for board service during fiscal year 2007. In addition, directors are reimbursed for reasonable expenses in connection with board meetings. Directors of KMR who are also employees of Knight do not receive compensation in their capacity as directors.



Fees Earned or
        
        Common Unit
        
        All OtherName
        
        Paid in Cash
        
        Awards(1)
        
        Compensation(2)
        
        TotalEdward O. Gaylord
        
        $
        64,089
        
        $
        95,911
        
        $
        111,466
        
        $
        271,466Gary L. Hultquist
        
        
        63,120
        
        
        96,880
        
        
        65,840
        
        
        225,840Perry M. Waughtal
        
        
        148
        
        
        159,852
        
        
        114,726
        
        
        274,726




__________



(1)
        Represents the value of cash compensation received in the form of our common units according to the provisions of our Common Unit Compensation Plan for Non-Employee Directors. Value computed as the number of common units elected to be received in lieu of cash times the closing price on date of election. For Mr. Gaylord, 1,980 units elected on January 17, 2007 times the closing price of $48.44; for Mr. Hultquist, 2,000 units elected times the closing price of $48.44; and for Mr. Waughtal, 3,300 units elected times the closing price of $48.44.




101



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(2)
        For each, represents (i) the value of common unit appreciation rights earned according to the provisions of our Directors Unit Appreciation Rights Plan for Non-Employee Directors, determined according to the provisions of SFAS No. 123Rfor each common unit appreciation right, equal to the increase in value of a corresponding common unit from December 31, 2006 to December 31, 2007; and (ii) distributions paid on unvested common units awarded according to the provisions of our Common Unit Compensation Plan for Non-Employee Directors.


For 2007, for Mr. Gaylord, includes (i) value of $106,575 computed as the number of common unit appreciation rights held during 2007 (17,500) times the increase in common unit closing price from December 31, 2006 to December 31, 2007 ($6.09; equal to $53.99 at December 31, 2007 less $47.90 at December 31, 2006); and (ii) $4,891 for distributions paid on unvested common units awarded according to the provisions of our Common Unit Compensation Plan for Non-Employee Directors; for Mr. Hultquist, includes (i) value of $60,900 computed as the number of common unit appreciation rights held during 2007 (10,000) times the increase in common unit closing price from December 31, 2006 to December 31, 2007 ($6.09; equal to $53.99 at December 31, 2007 less $47.90 at December 31, 2006); and (ii) $4,940 for distributions paid on unvested common units awarded according to the provisions of our
Common Unit Compensation Plan for Non-Employee Directors; for Mr. Waughtal, includes (i) value of $106,575 computed as the number of common unit appreciation rights held during 2007 (17,500) times the increase in common unit closing price from December 31, 2006 to December 31, 2007 ($6.09; equal to $53.99 at December 31, 2007 less $47.90 at December 31, 2006); and (ii) $8,151 for distributions paid on unvested common units awarded according to the provisions of our Common Unit Compensation Plan for Non-Employee Directors.

Compensation Committee Report

Throughout fiscal 2007, the compensation committee of KMRs board of directors was comprised of three directors, each of which the KMR board of directors has determined meets the criteria for independence under KMRs governance guidelines and the New York Stock Exchange rules.

The KMR compensation committee has discussed and reviewed the above Compensation Discussion and Analysis for fiscal year 2007 with management. Based on this review and discussion, the KMR compensation committee recommended to its board of directors, that this Compensation Discussion and Analysis be included in this annual report on Form 10-K for the fiscal year 2007.

KMR Compensation Committee:

Edward O. Gaylord

Gary L. Hultquist

Perry M. Waughtal





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Item 12. Security Ownership of Certain Beneficial Owners
and Management and Related Stockholder Matters.

The
following table sets forth information as of January 31, 2008, regarding (i)
the beneficial ownership of (a) our common and Class B units and (b) KMR shares
by all directors of our general partner and KMR, its delegate, by each of the
named executive officers identified in Item 11 Executive Compensation and by
all directors and executive officers as a group; and (ii) the beneficial ownership
of our common and Class B units or shares of KMR by all persons known by our
general partner to own beneficially at least 5% of our common and Class B units
and KMR shares. For information regarding the beneficial ownership of Knight Holdco
LLCs units by our named executive officers (and our executive officers who
are also officers of Knight) and directors, see Item 13. Certain
Relationships and Related Transactions, and Director IndependenceRelated
TransactionsKMI Going-Private Transaction. Unless otherwise noted,
the address of each person below is c/o Kinder Morgan Energy Partners, L.P., 500 Dallas
Street, Suite 1000, Houston, Texas 77002.

Amount and Nature of Beneficial
Ownership(1)

|                                                               |  |                     |            |                   |  |                                  |   |                   |           |                      |  |                   |   |  |            |  |  |       |  
|-------------------------------------------------------------- |  | ------------------- | ---------- | ----------------- |  | -------------------------------- | - | ----------------- | --------- | -------------------- |  | ----------------- | - |  | ---------- |  |  | ----- | -
|                                                               |  | Common Units        |            | Class B Units     |  | Kinder Morgan
 Management Shares |  
|                                                               |  |                     |            |                   |  |                                  |  
|                                                               |  | Number
 of Units(2) |            | Percent
 of Class |  | Number
 of Units(3)              |   | Percent
 of Class |           | Number of
 Shares(4) |  | Percent
 of Class |  
|                                                               |  |                     |            |                   |  |                                  |   |                   |           |                      |  |                   |  
|Richard D. Kinder(5)                                           |  |                     | 315,979    |                   |  | *                                |   |                   |          |                      |  |                  |   |  | 84,663     |  |  | *     |  
|C. Park Shaper                                                 |  |                     | 4,000      |                   |  | *                                |   |                   |          |                      |  |                  |   |  | 23,793     |  |  | *     |  
|Edward O. Gaylord(6)                                           |  |                     | 40,000     |                   |  | *                                |   |                   |          |                      |  |                  |   |  |           |  |  |      |  
|Gary L. Hultquist                                              |  |                     | 11,500     |                   |  | *                                |   |                   |          |                      |  |                  |   |  |           |  |  |      |  
|Perry M. Waughtal(7)                                           |  |                     | 46,918     |                   |  | *                                |   |                   |          |                      |  |                  |   |  | 46,180     |  |  | *     |  
|Steven J. Kean                                                 |  |                     |           |                   |  |                                 |   |                   |          |                      |  |                  |   |  |           |  |  |      |  
|Scott E. Parker                                                |  |                     |           |                   |  |                                 |   |                   |          |                      |  |                  |   |  |           |  |  |      |  
|Kimberly A. Dang                                               |  |                     | 121        |                   |  | *                                |   |                   |          |                      |  |                  |   |  | 440        |  |  | *     |  
|Directors and Executive Officers
as a group (14
 persons)(8)   |  |                     | 435,995    |                   |  | *                                |   |                   |          |                      |  |                  |   |  | 175,027    |  |  | *     |  
|Knight Inc.(9)                                                 |  |                     | 14,355,735 |                   |  | 8.43                             | % |                   | 5,313,400 |                      |  | 100.00            | % |  | 10,334,746 |  |  | 14.27 | %
|Kayne Anderson Capital
Advisors,L.P. and Richard
 A. Kayne(10) |  |                     |           |                   |  |                                 |   |                   |          |                      |  |                  |   |  | 7,869,016  |  |  | 10.86 | %
|Tortoise Capital Advisors,
L.L.C.(11)                          |  |                     |           |                   |  |                                 |   |                   |          |                      |  |                  |   |  | 4,314,123  |  |  | 5.96  | %
|Janus Capital Management
LLC(12)                               |  |                     |           |                   |  |                                 |   |                   |          |                      |  |                  |   |  | 3,647,958  |  |  | 5.04  | %

* Less than 1%.

|     |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   
|---- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(1)  | Except
 as noted otherwise, all units and KMR shares involve sole voting power and
 sole investment power. For KMR, see note (4). On January 18, 2005, KMRs board of
 directors initiated a rule requiring each director to own a minimum of 10,000
 common units, KMR shares, or a combination thereof.                                                                                                                                                                                                                                                                                                         
|     |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   
|(2)  | As of
 January 31, 2008, we had 170,224,734 common units issued and outstanding.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  
|     |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   
|(3)  | As of
 January 31, 2008, we had 5,313,400 Class B units issued and outstanding.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   
|     |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   
|(4)  | Represent
 the limited liability company shares of KMR. As of January 31, 2008, there
 were 72,432,482 issued and outstanding KMR shares, including two voting
 shares owned by our general partner. In all cases, our i-units will be voted
 in proportion to the affirmative and negative votes, abstentions and
 non-votes of owners of KMR shares. Through the provisions in our partnership
 agreement and KMRs limited liability company agreement, the number of
 outstanding KMR shares, including voting shares owned by our general partner,
 and the number of our i-units will at all times be equal.
|     |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   
|(5)  | Includes
 7,879 common units owned by Mr. Kinders spouse. Mr. Kinder disclaims any and
 all beneficial or pecuniary interest in these units.                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
|     |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   
|(6)  | Includes
 1,520 restricted common units.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          
|     |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   
|(7)  | Includes
 2,818 restricted common units.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          
|     |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   
|(8)  | Includes
 4,338 restricted common units. Also includes 671 KMR shares purchased by one
 of our executives for his children. The executive disclaims any beneficial
 ownership in such KMR shares.                                                                                                                                                                                                                                                                                                                                                                                                                 
|     |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   
|(9)  | Includes
 common units owned by Knight Inc. and its consolidated subsidiaries,
 including 1,724,000 common units owned by Kinder Morgan G.P., Inc.                                                                                                                                                                                                                                                                                                                                                                                                                                                                
|     |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   
|(10) | As
 reported on the Schedule 13G/A filed February 13, 2008 by Kayne Anderson
 Capital Advisors, L.P. and Richard A. Kayne. Kayne Anderson Capital Advisors,
 L.P. reported that in regard to KMR shares, it had sole voting power over 0                                                                                                                                                                                                                                                                                                                                                                          

103

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|     |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        
|---- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|     | shares,
 shared voting power over 7,867,883 shares, sole disposition power over 0
 shares and shared disposition power over 7,867,883 shares. Mr. Kayne reports
 that in regard to KMR shares, he had sole voting power over 1,133 shares,
 shared voting power over 7,867,883 shares, sole disposition power over 1,133
 shares and shared disposition power over 7,867,883 shares. Kayne Anderson
 Capital Advisors, L.P.s and Richard A. Kaynes address is 1800 Avenue of the
 Stars, Second Floor, Los Angeles, California 90067.
|     |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        
|(11) | As
 reported on the Schedule 13G/A filed February 12, 2008 by Tortoise Capital
 Advisors, L.L.C. Tortoise Capital Advisors, L.L.C. reported that in regard to
 KMR shares, it had sole voting power over 0 shares, shared voting power over
 4,202,836 shares, sole disposition power over 0 shares and shared disposition
 power over 4,314,123 shares. Tortoise Capital Advisors, L.L.C.s address is
 10801 Mastin Blvd., Suite 222, Overland Park, Kansas 66210.                                                                   
|     |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        
|(12) | As
 reported on the Schedule 13G filed February 14, 2008 by Janus Capital
 Management LLC. Janus Capital Management LLC reported that in regard to KMR
 shares, it had sole voting power over 3,647,958 shares, shared voting power
 over 0 shares, sole disposition power over 3,647,958 shares and shared
 disposition power over 0 shares. Janus Capital Management LLCs address is
 151 Detroit Street, Denver, Colorado 80206.                                                                                                   

Equity Compensation Plan Information

The
following table sets forth information regarding our equity compensation plans
as of December 31, 2007. Specifically, the table provides information regarding
our Common Unit Option Plan and our Common Unit Compensation Plan for Non-Employee
Directors, both described in Item 11, Executive Compensation.Compensation
Discussion and AnalysisElements of CompensationOther CompensationCommon Unit
Option Plan, Item 11 Executive CompensationDirector CompensationKinder
Morgan Energy Partners, L.P. Common Unit Compensation Plan for Non-Employee
Directors, and Note 13 of the notes to our consolidated financial statements
included elsewhere in this report.

|                                                            |  |                                                                                                  |  | 
|----------------------------------------------------------- |  | ------------------------------------------------------------------------------------------------ |  | 
|Plan category                                               |  | Number of
 securities
 remaining available for
 future issuance under equity
 compensation plans | 
|                                                            |  |                                                                                                  | 
|Equity compensation plans
 approved by security holders     |  |                                                                                                 |  | 
|                                                            |  |                                                                                                  |  | 
|Equity compensation plans not
 approved by security holders |  | 141,820                                                                                          |  | 
|                                                            |  |                                                                                                  |  | 
|                                                            |  |                                                                                                  |  | 
|Total                                                       |  | 141,820                                                                                          |  | 
|                                                            |  |                                                                                                  |  | 

104

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Item 13.Certain Relationships and Related Transactions, and Director Independence.



Related Transactions

KMI Going-Private Transaction

On May 30, 2007, KMI completed the going-private transaction, whereby pursuant to a merger agreement, generally each share of KMI common stock was converted into the right to receive $107.50 in cash without interest.  See Item 11. Executive CompensationKMI Stock Options and Restricted Stock for a discussion of the disposition of options to purchase KMI common stock and shares of restricted KMI stock in the going-private transaction.  For further information regarding this transaction, see (a) General Development of Business within Items 1 and 2 of this report.

In connection with the going-private transaction, some of our executive officers became investors in Knight Holdco LLC, Knight's parent company.  None of our independent directors, Messrs. Gaylord, Hultquist and Waughtal, are investors in Knight Holdco LLC.  Each of the investors in Knight Holdco LLC entered into an amended and restated limited liability company agreement of Knight Holdco LLC which governs the rights and obligations of the investors with respect to Knight Holdco LLC and Knight.  Pursuant to the limited liability company agreement, Knight Holdco LLC is a manager managed limited liability company governed by an 11 member board of managers and initially by a chief manager. Mr. Richard D. Kinder, our Chairman and Chief Executive Officer, is Knight Holdco LLC's initial chief manager.  Mr. Kinder is also a member of the board of managers and has the right to appoint an
additional four members of the board of managers.  The chief manager has control over most of the operations of Knight Holdco LLC, subject to rights of the board of managers (and in some cases, the members of Knight Holdco LLC, acting in their capacity as such) to approve significant actions proposed to be taken by Knight Holdco LLC or its subsidiaries (generally other than us, KMR and our respective subsidiaries), including, among other things, liquidations, issuances of equity securities, distributions (other than identified tax related distributions), transactions with affiliates, settlement of litigation or entry into agreements with a value in excess of $50 million, entry into new lines of business and approval of the annual budget. Additionally, the members of Knight Holdco LLC (and in some cases, just certain members) have the ability to compel restructuring and liquidity events, including an initial public offering of Knight Holdco LLC or any of its subsidiaries or
businesses, a sale or disposition of Knight Holdco LLC or any of its material subsidiaries or its businesses, or distributions of excess cash to the members of Knight Holdco LLC, although in some cases such actions may only be so compelled after specified time periods.

Generally, Knight Holdco LLC has three classes of unitsClass A units, Class A-1 units, and Class B units. The Class A units were issued to investors, including members of senior management who directly or indirectly reinvested all or a portion of their KMI equity and/or cash, in respect of their capital contributions to Knight Holdco LLC. Generally, the holders of Class A units will share ratably in all distributions, subject to amounts allocated to the Class A-1 units and the Class B units as set forth below.

The Class B units were awarded by Knight Holdco LLC to members of Knight's management in consideration of their services to or for the benefit of Knight Holdco LLC. The Class B units represent interests in the profits of Knight Holdco LLC following the return of capital for the holders of Class A units and the achievement of predetermined performance targets over time. The Class B units will performance vest in increments of 5% of profits distributions up to a maximum of 20% of all profits distributions that would otherwise be payable with respect to the Class A units and Class A-1 units, based on the achievement of predetermined performance targets. The Class B units are subject to time based vesting, and with respect to any holder thereof, will vest 33 1/3% on each of the 3rd, 4th and 5th year anniversary of the
issuance of such Class B units to such holder. The amended and restated limited liability company agreement also includes provisions with respect to forfeiture of Class B units upon termination for cause, Knight Holdco LLC's call rights upon termination and other related provisions relating to an employee's tenure. The allocation of the Class B units among Knight's management was determined prior to closing by Mr. Kinder, and approved by other, non-management investors.

The Class A-1 units were awarded by Knight Holdco LLC to members of Knight's management (other than Mr. Richard D. Kinder) who reinvested their equity interests in Knight Holdco LLC in connection with the going-private transaction in consideration of their services to or for the benefit of Knight Holdco LLC. Class A-1 units



105



---



entitle a holder thereof to receive distributions from Knight Holdco LLC in an amount equal to distributions paid on Class A units (other than distributions on the Class A units that represent a return of the capital contributed in respect of such Class A units), but only after the Class A units have received aggregate distributions in an amount equal to the amount of capital contributed in respect of the Class A units.

The table below sets forth the beneficial ownership (as defined in Rule 13(d)(3) of the Exchange Act) of Knight Holdco LLC's units by each of our directors and named executive officers
(and executive officers of ours who are also executive officers of Knight), detailing the contributions made by each in respect of their Class A units and the grant date fair value, as calculated in accordance with SFAS No. 123R, of the Class A-1 and Class B units received by each. In accordance with SFAS No. 123R, Knight Holdco LLC is required to recognize compensation expense in connection with the Class A-1 and Class B units over the expected life of such units.  As a subsidiary of Knight Holdco LLC, we are allocated a portion of this compensation expense, although none of us or any of our subsidiaries have any obligation, nor do we expect, to pay any amounts in respect of such units.  Please see Item 11. Executive Compensation for disclosure regarding the Class A-1 and Class B units
received by each of the named executive officers and the expense as calculated in accordance with SFAS No. 123R allocated to us for 2007 in respect of each officer's units. Except as noted otherwise, each individual has sole voting power and sole disposition power over the units listed.



% of Class% of Class
        Class A-1
        A-1
        
        % of ClassClass A Units
        A Units(1)
        Units
        Units(2)
        Class B Units
        B Units(3)Richard D. Kinder(4)
        2,424,000,000
        30.6
        
        
        791,405,452
        40.0Edward O. Gaylord
        
        
        
        
        
        Gary L. Hultquist
        
        
        
        
        
        Perry M. Waughtal
        
        
        
        
        
        C. Park Shaper(5)
        13,598,785
        *
        7,799,775
        28.3
        217,636,499
        11.0Steven J. Kean(6)
        6,684,149
        *
        3,833,788
        13.9
        158,281,090
        8.0Kimberly A. Dang(7)
        750,032
        *
        430,191
        1.6
        49,462,841
        2.5David D. Kinder(8)
        1,075,981
        *
        617,144
        2.3
        55,398,382
        2.8Joseph Listengart(9)
        6,059,449
        *
        3,475,483
        12.6
        79,140,545
        4.0Scott E. Parker
        
        
        
        
        
        James E. Street(10)
        3,813,005
        *
        2,187,003
        7.9
        49,462,841
        2.5Executive officers and directors as a group (14 persons)
        2,460,763,539
        31.1
        21,086,247
        76.5
        1,626,338,205
        82.2




____________________________________

*
        Less than 1%.


(1)
        As of January 31, 2008, Knight Holdco LLC had 7,914,367,913 Class A Units issued and outstanding.


(2)
        As of January 31, 2008, Knight Holdco LLC had 27,225,694 Class A-1 Units issued and outstanding and 345,042 phantom Class A-1 Units issued and outstanding.  The phantom Class A-1 Units were issued to Canadian management employees.


(3)
        As of January 31, 2008, Knight Holdco LLC had 1,922,620,621 Class B Units issued and outstanding and 55,893,008 phantom Class B Units issued and outstanding.  The phantom Class B Units were issued to Canadian management employees.


(4)
        Includes 522,372 Class A units owned by Mr. Kinder's wife.  Mr. Kinder disclaims any and all beneficial or pecuniary interest in the Class A units held by his wife.  Also includes 263,801,817 Class B Units that Mr. Kinder transferred to a limited partnership.  Mr. Kinder may be deemed to be the beneficial owner of these transferred Class B Units, because Mr. Kinder controls the voting and disposition power of these Class B Units, but he disclaims ninety-nine percent of any beneficial and pecuniary interest in them. Mr. Kinder contributed 23,994,827 shares of KMI common stock and his wife contributed 5,173 shares of KMI common stock to Knight Holdco LLC that were valued for purposes of Knight Holdco LLC's limited liability agreement at $2,423,477,628 and $522,372, respectively, in exchange for their respective Class A units.  The
Class B units received by Mr. Kinder had a grant date fair value as calculated in accordance with SFAS No. 123R of $9,200,000.


(5)
        Includes 217,636,499 Class B Units that Mr. Shaper transferred to a limited partnership.  Mr. Shaper may be deemed to be the beneficial owner of these transferred Class B Units, because Mr. Shaper controls the voting and disposition power of these Class B Units, but he disclaims approximately twenty-two percent of any beneficial and pecuniary interest in them. Mr. Shaper made a cash investment of $13,598,785 of his after-tax proceeds from the conversion in the going-private transaction of 82,500 shares of KMI restricted stock and options to acquire 197,969 shares of KMI common stock in exchange for his Class A units.  The Class A-1 units and Class B units received by Mr. Shaper had an aggregate grant date fair value as calculated in accordance with SFAS No. 123R of $4,315,475.


(6)
        Mr. Kean made a cash investment of $6,684,149 of his after-tax proceeds from the conversion in the going-private transaction of 78,000 shares of KMI restricted stock and options to acquire 25,533 shares of KMI common stock in exchange for his Class A units.  The Class A-1 units and Class B units received by Mr. Kean had an aggregate grant date fair value as calculated in accordance with SFAS No. 123R of $2,720,252.




106

---



(7)
        Includes 49,462,841 Class B Units that Ms. Dang transferred to a limited partnership.  Ms. Dang may be deemed to be the beneficial owner of these transferred Class B Units, because Ms. Dang has voting and disposition power of these Class B Units, but she disclaims ten percent of any beneficial and pecuniary interest in them. Ms. Dang made a cash investment of $750,032 of her after-tax proceeds from the conversion in the going-private transaction of 8,000 shares of KMI restricted stock and options to acquire 24,750 shares of KMI common stock in exchange for her Class A units.  The Class A-1 units and Class B units received by Ms. Dang had an aggregate grant date fair value as calculated in accordance with SFAS No. 123R of $674,887.


(8)
        Includes 55,398,382 Class B Units that Mr. Kinder transferred to a limited partnership.  Mr. Kinder may be deemed to be the benficial owner of these transferred Class B Units, because Mr. Kinder controls the voting and disposition power of these Class B Units, but he disclaims eight percent of any benficial and pecuniary interest in them.  Mr. Kinder made a cash investment of $1,075,981 of his after-tax proceeds from the conversion in the going-private transaction of 15,750 shares of KMI restricted stock in exchange for his Class A units.  The Class A-1 units and Class B units received by Mr. Kinder had an aggregate grant date fair value as calculated in accordance with SFAS No. 123R of $787,587.


(9)
        Mr. Listengart made a cash investment of $6,059,449 of his after-tax proceeds from the conversion in the going-private transaction of 52,500 shares of KMI restricted stock and options to acquire 48,459 shares of KMI common stock in exchange for his Class A units.  The Class A-1 units and Class B units received by Mr. Listengart had an aggregate grant date fair value as calculated in accordance with SFAS No. 123R of $1,712,851.


(10)
        Mr. Street made a cash investment of $3,813,005 of his after-tax proceeds from the conversion in the going-private transaction of 30,000 shares of KMI restricted stock and options to acquire 34,588 shares of KMI common stock in exchange for his Class A units.  The Class A-1 units and Class B units received by Mr. Street had an aggregate grant date fair value as calculated in accordance with SFAS No. 123R of $1,074,434.




Other



Our policy is that (i) employees must obtain authorization from the appropriate business unit president of the relevant company or head of corporate function, and (ii) directors, business unit presidents, executive officers and heads of corporate functions must obtain authorization from the non-interested members of the audit committee of the applicable board of directors, for any business relationship or proposed business transaction in which they or an immediate family member has a direct or indirect interest, or from which they or an immediate family member may derive a personal benefit (a related party transaction).  The maximum dollar amount of related party transactions that may be approved as described above in this paragraph in any calendar year is $1.0 million.  Any related party transactions that would bring the total value of such transactions to greater than $1.0
million must be referred to the audit committee of the appropriate board of directors for approval or to determine the procedure for approval.



For information regarding other related transactions, see Note 12 of the notes to our consolidated financial statements included elsewhere in this report.



Director Independence



Our limited partnership agreement provides for us to have a general partner rather than a board of directors.  Pursuant to a delegation of control agreement, our general partner 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.  Through the operation of that agreement and our partnership agreement, KMR manages and controls our business and affairs, and the board of directors of KMR performs the functions of and acts as our board of directors.  Similarly, the standing committees of KMRs board of directors function as standing committees of our board.  KMRs board of directors is comprised of the same persons who comprise our general partners board of
directors.  References in this report to the board mean KMRs board, acting as our board of directors, and references to committees mean KMRs committees, acting as committees of our board of directors.



107

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The board has adopted governance guidelines for the board and charters for the audit committee, nominating and governance committee and compensation committee.  The governance guidelines and the rules of the New York Stock Exchange require that a majority of the directors be independent, as described in those guidelines, the committee charters and rules, respectively.  Copies of the guidelines and committee charters are available on our internet website at www.kindermorgan.com.  To assist in making determinations of independence, the board has determined that the following categories of relationships are not material relationships that would cause the affected director not to be independent:



 if the director was an employee, or had an immediate family member who was an executive officer, of KMR or us or any of its or our affiliates, but the employment relationship ended more than three years prior to the date of determination (or, in the case of employment of a director as an interim chairman, interim chief executive officer or interim executive officer, such employment relationship ended by the date of determination);



 if during any twelve month period within the three years prior to the determination the director received no more than, and has no immediate family member that received more than, $100,000 in direct compensation from us or our affiliates, other than (i) director and committee fees and pension or other forms of deferred compensation for prior service (provided such compensation is not contingent in any way on continued service), (ii) compensation received by a director for former service as an interim chairman, interim chief executive officer or interim executive officer, and (iii) compensation received by an immediate family member for service as an employee (other than an executive officer);



 if the director is at the date of determination a current employee, or has an immediate family member that is at the date of determination a current executive officer, of another company that has made payments to, or received payments from, us and our affiliates for property or services in an amount which, in each of the three fiscal years prior to the date of determination, was less than the greater of $1.0 million or 2% of such other companys annual consolidated gross revenues.  Contributions to tax-exempt organizations are not considered payments for purposes of this determination;



 if the director is also a director, but is not an employee or executive officer, of our general partner or another affiliate or affiliates of KMR or us, so long as such director is otherwise independent; and



 if the director beneficially owns less than 10% of each class of voting securities of us, our general partner, or KMR.



The board has affirmatively determined that Messrs. Gaylord, Hultquist and Waughtal, who constitute a majority of the directors, are independent as described in our governance guidelines and the New York Stock Exchange rules.  Each of them meets the standards above and has no other relationship with us.  In conjunction with all regular quarterly and certain special board meetings, these three non-management directors also meet in executive session without members of management.  In January 2008, Mr. Waughtal was elected for a one year term to serve as lead director to develop the agendas for and preside at these executive sessions of independent directors.



The governance guidelines and our audit committee charter, as well as the rules of the New York Stock Exchange and the Securities and Exchange Commission, require that members of the audit committee satisfy independence requirements in addition to those above.  The board has determined that all of the members of the audit committee are independent as described under the relevant standards.



108

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Item 14. Principal Accounting Fees and Services

The
following sets forth fees billed for the audit and other services provided by
PricewaterhouseCoopers LLP for the fiscal years ended December 31, 2007 and
2006 (in dollars):

|              |  |                          |           |      |   |          
|------------- |  | ------------------------ | --------- | ---- | - | ---------
|              |  | Year Ended December
 31,
|              |  |                         
|              |  | 2007                     |           | 2006
|              |  |                          |           |     
|Audit fees(1) |  | $                        | 2,070,205 |      | $ | 2,038,215
|Tax fees(2)   |  |                          | 2,563,793 |      |   | 1,470,466
|              |  |                          |           |     
|Total         |  | $                        | 4,633,998 |      | $ | 3,508,681
|              |  |                          |           |     

|    |                                                                                                                                                                                                                                                                                                                                                                                                                                    
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|   
|(1) | Includes
 fees for integrated audit of annual financial statements and internal control
 over financial reporting, reviews of the related quarterly financial
 statements, and reviews of documents filed with the Securities and Exchange
 Commission.                                                                                                                                                                            
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                    
|(2) | For 2007 and 2006, amounts include fees of $2,352,533
 and $1,356,399, respectively, billed for professional services rendered for
 tax processing and preparation of Forms K-1 for our unitholders. Amounts also
 include fees of $211,260 and $114,067, respectively, billed for professional
 services rendered for tax return review services and for general state, local
 and foreign tax compliance and consulting services.

All
services rendered by PricewaterhouseCoopers LLP are permissible under
applicable laws and regulations, and were pre-approved by the audit committee of KMR and our general partner.
Pursuant to the charter of the audit
committee of KMR, the delegate of our general partner, the committees primary
purposes include the following: (i) to select, appoint, engage, oversee,
retain, evaluate and terminate our external auditors; (ii) to pre-approve all
audit and non-audit services, including tax services, to be provided,
consistent with all applicable laws, to us by our external auditors; and (iii)
to establish the fees and other compensation to be paid to our external
auditors. The audit committee has reviewed the external auditors fees
for audit and non audit services for fiscal year 2007. The audit committee has
also considered whether such non audit services are compatible with maintaining
the external auditors independence and has concluded that they are compatible
at this time.

Furthermore,
the audit committee will review the external auditors proposed audit scope and
approach as well as the performance of the external auditors. It also has
direct responsibility for and sole authority to resolve any disagreements
between our management and our external auditors regarding financial reporting,
will regularly review with the external auditors any problems or difficulties
the auditors encountered in the course of their audit work, and will, at least
annually, use its reasonable efforts to obtain and review a report from the
external auditors addressing the following (among other items): (i) the
auditors internal quality-control procedures; (ii) any material issues raised
by the most recent internal quality-control review, or peer review, of the
external auditors; (iii) the independence of the external auditors; and (iv)
the aggregate fees billed by our external auditors for each of the previous two
fiscal years.

109

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PART IV

Item 15. Exhibits and Financial Statement Schedules

| |                                                                      
| | ---------------------------------------------------------------------
| | (a)(1) and (2) Financial Statements and Financial Statement Schedules
| |                                                                      
| | See Index to Financial Statements set forth on page
114.           
| |                                                                      
| | (a)(3) Exhibits                                                      

|        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                       
|------- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|*3.1   |  | Third
 Amended and Restated Agreement of Limited Partnership of Kinder Morgan Energy
 Partners, L.P. (filed as Exhibit 3.1 to Kinder Morgan Energy Partners, L.P.
 Form 10-Q (File No. 1-11234) for the quarter ended June 30, 2001, filed on
 August 9, 2001).                                                                                                                                                                       
|        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                       
|*3.2   |  | Amendment
 No. 1 dated November 19, 2004 to Third Amended and Restated Agreement of
 Limited Partnership of Kinder Morgan Energy Partners, L.P. (filed as Exhibit
 99.1 to Kinder Morgan Energy Partners, L.P. Form 8-K, filed November 22,
 2004).                                                                                                                                                                                   
|        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                       
|*3.3   |  | Amendment
 No. 2 to Third Amended and Restated Agreement of Limited Partnership of
 Kinder Morgan Energy Partners, L.P. (filed as Exhibit 99.1 to Kinder Morgan
 Energy Partners, L.P. Form 8-K, filed May 5, 2005).                                                                                                                                                                                                                  
|        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                       
|*4.1   |  | Specimen
 Certificate evidencing Common Units representing Limited Partner Interests
 (filed as Exhibit 4.1 to Amendment No. 1 to Kinder Morgan Energy Partners,
 L.P. Registration Statement on Form S-4, File No. 333-44519, filed on
 February 4, 1998).                                                                                                                                                                           
|        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                       
|*4.2   |  | Indenture
 dated as of January 29, 1999 among Kinder Morgan Energy Partners, L.P., the
 guarantors listed on the signature page thereto and U.S. Trust Company of
 Texas, N.A., as trustee, relating to Senior Debt Securities (filed as Exhibit
 4.1 to the Partnerships Current Report on Form 8-K filed February 16, 1999,
 File No. 1-11234 (the February 16, 1999 Form 8-K)).                                                 
|        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                       
|*4.3   |  | First
 Supplemental Indenture dated as of January 29, 1999 among Kinder Morgan
 Energy Partners, L.P., the subsidiary guarantors listed on the signature page
 thereto and U.S. Trust Company of Texas, N.A., as trustee, relating to
 $250,000,000 of 6.30% Senior Notes due February 1, 2009 (filed as Exhibit 4.2
 to the February 16, 1999 Form 8-K (File No. 1-11234)).                                                          
|        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                       
|*4.4   |  | Second
 Supplemental Indenture dated as of September 30, 1999 among Kinder Morgan
 Energy Partners, L.P. and U.S. Trust Company of Texas, N.A., as trustee, relating
 to release of subsidiary guarantors under the $250,000,000 of 6.30% Senior
 Notes due February 1, 2009 (filed as Exhibit 4.4 to the Partnerships Form
 10-Q (File No. 1-11234) for the quarter ended September 30, 1999 (the 1999
 Third Quarter Form 10-Q)).
|        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                       
|*4.5   |  | Indenture
 dated November 8, 2000 between Kinder Morgan Energy Partners, L.P. and First
 Union National Bank, as Trustee (filed as Exhibit 4.8 to Kinder Morgan Energy
 Partners, L.P. Form 10-K for 2001 (File No. 1-11234)).                                                                                                                                                                                                        
|        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                       
|*4.6   |  | Form of
 7.50% Notes due November 1, 2010 (contained in the Indenture filed as Exhibit
 4.8 to the Kinder Morgan Energy Partners, L.P. Form 10-K (File No. 1-11234)
 for 2001).                                                                                                                                                                                                                                                       
|        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                       
|*4.7   |  | Indenture
 dated January 2, 2001 between Kinder Morgan Energy Partners and First Union
 National Bank, as trustee, relating to Senior Debt Securities (including form
 of Senior Debt Securities) (filed as Exhibit 4.11 to Kinder Morgan Energy
 Partners, L.P. Form 10-K (File No. 1-11234) for 2000).                                                                                                                              
|        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                       
|*4.8   |  | Indenture
 dated January 2, 2001 between Kinder Morgan Energy Partners and First Union
 National Bank, as trustee, relating to Subordinated Debt Securities
 (including form of Subordinated Debt Securities) (filed as Exhibit 4.12 to
 Kinder Morgan Energy Partners, L.P. Form 10-K (File No. 1-11234) for 2000).                                                                                                                  
|        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                       
|*4.9   |  | Certificate
 of Vice President and Chief Financial Officer of Kinder Morgan Energy
 Partners, L.P. establishing the terms of the 6.75% Notes due March 15, 2011
 and the 7.40% Notes due March 15, 2031 (filed as Exhibit 4.1 to Kinder Morgan
 Energy Partners, L.P. Form 8-K (File No. 1-11234), filed on March 14, 2001).                                                                                                          
|        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                       
|*4.10  |  | Specimen of
 6.75% Notes due March 15, 2011 in book-entry form (filed as Exhibit 4.2 to
 Kinder Morgan Energy Partners, L.P. Form 8-K (File No. 1-11234), filed on
 March 14, 2001).                                                                                                                                                                                                                                                  
|        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                       
|*4.11  |  | Specimen of
 7.40% Notes due March 15, 2031 in book-entry form (filed as Exhibit 4.3 to
 Kinder Morgan Energy Partners, L.P. Form 8-K (File No. 1-11234), filed on
 March 14, 2001).                                                                                                                                                                                                                                                  

110

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|        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                              
|------- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|*4.12  |  | Certificate
 of Vice President and Chief Financial Officer of Kinder Morgan Energy
 Partners, L.P. establishing the terms of the 7.125% Notes due March 15, 2012
 and the 7.750% Notes due March 15, 2032 (filed as Exhibit 4.1 to Kinder
 Morgan Energy Partners, L.P. Form 10-Q (File No. 1-11234) for the quarter
 ended March 31, 2002, filed on May 10, 2002).                                                                          
|        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                              
|*4.13  |  | Specimen of
 7.125% Notes due March 15, 2012 in book-entry form (filed as Exhibit 4.2 to
 Kinder Morgan Energy Partners, L.P. Form 10-Q (File No. 1-11234) for the
 quarter ended March 31, 2002, filed on May 10, 2002).                                                                                                                                                                                                                    
|        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                              
|*4.14  |  | Specimen of
 7.750% Notes due March 15, 2032 in book-entry form (filed as Exhibit 4.3 to
 Kinder Morgan Energy Partners, L.P. Form 10-Q (File No. 1-11234) for the
 quarter ended March 31, 2002, filed on May 10, 2002).                                                                                                                                                                                                                    
|        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                              
|*4.15  |  | Indenture
 dated August 19, 2002 between Kinder Morgan Energy Partners, L.P. and
 Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.1 to the
 Kinder Morgan Energy Partners, L.P. Registration Statement on Form S-4 (File
 No. 333-100346) filed on October 4, 2002 (the October 4, 2002 Form S-4)).                                                                                                                    
|        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                              
|*4.16  |  | First
 Supplemental Indenture to Indenture dated August 19, 2002, dated August 23,
 2002 between Kinder Morgan Energy Partners, L.P. and Wachovia Bank, National
 Association, as Trustee (filed as Exhibit 4.2 to the October 4, 2002 Form
 S-4).                                                                                                                                                                                           
|        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                              
|*4.17  |  | Form of
 7.30% Note (contained in the Indenture filed as Exhibit 4.1 to the October 4,
 2002 Form S-4).                                                                                                                                                                                                                                                                                                                                      
|        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                              
|*4.18  |  | Senior
 Indenture dated January 31, 2003 between Kinder Morgan Energy Partners, L.P.
 and Wachovia Bank, National Association (filed as Exhibit 4.2 to the Kinder
 Morgan Energy Partners, L.P. Registration Statement on Form S-3 (File No.
 333-102961) filed on February 4, 2003 (the February 4, 2003 Form S-3)).                                                                                                                      
|        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                              
|*4.19  |  | Form of
 Senior Note of Kinder Morgan Energy Partners, L.P. (included in the Form of
 Senior Indenture filed as Exhibit 4.2 to the February 4, 2003 Form S-3).                                                                                                                                                                                                                                                                               
|        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                              
|*4.20  |  | Subordinated
 Indenture dated January 31, 2003 between Kinder Morgan Energy Partners, L.P.
 and Wachovia Bank, National Association (filed as Exhibit 4.4 to the February
 4, 2003 Form S-3).                                                                                                                                                                                                                                                
|        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                              
|*4.21  |  | Form of
 Subordinated Note of Kinder Morgan Energy Partners, L.P. (included in the
 Form of Subordinated Indenture filed as Exhibit 4.4 to the February 4, 2003
 Form S-3).                                                                                                                                                                                                                                                                  
|        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                              
|*4.22  |  | Certificate
 of Vice President, Treasurer and Chief Financial Officer and Vice President,
 General Counsel and Secretary of Kinder Morgan Management, LLC and Kinder
 Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P.
 establishing the terms of the 5.00% Notes due December 15, 2013 (filed as
 Exhibit 4.25 to Kinder Morgan Energy Partners, L.P. Form 10-K for 2003 filed
 March 5, 2004).                          
|        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                              
|*4.23  |  | Certificate
 of Executive Vice President and Chief Financial Officer and Vice President,
 General Counsel and Secretary of Kinder Morgan Management, LLC and Kinder
 Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P.
 establishing the terms of the 5.125% Notes due November 15, 2014 (filed as
 Exhibit 4.27 to Kinder Morgan Energy Partners, L.P. Form 10-K for 2004 filed
 March 4, 2005).                          
|        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                              
|*4.24  |  | Certificate
 of Vice President, Treasurer and Chief Financial Officer and Vice President,
 General Counsel and Secretary of Kinder Morgan Management, LLC and Kinder
 Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P.
 establishing the terms of the 5.80% Notes due March 15, 2035 (filed as
 Exhibit 4.1 to Kinder Morgan Energy Partners, L.P. Form 10-Q for the quarter
 ended March 31, 2005, filed on May 6, 2005).
|        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                              
|*4.25  |  | Certificate
 of Vice President and Chief Financial Officer of Kinder Morgan Management,
 LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners,
 L.P. establishing the terms of the 6.00% Senior Notes due 2017 and 6.50%
 Senior Notes due 2037 (filed as Exhibit 4.28 to Kinder Morgan Energy
 Partners, L.P. Form 10-K for 2006 filed March 1, 2007).                                                              
|        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                              
|*4.26  |  | Certificate of the Vice President and
 Treasurer and the Vice President and Chief Financial Officer of Kinder Morgan
 Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners,
 L.P., establishing the terms of the 6.95% Senior Notes due 2038 (filed
 as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P. Form 10-Q for the
 quarter ended June 30, 2007 filed August 8, 2007).                         
|        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                              
|*4.27  |  | Certificate of the Vice President and
 Treasurer and the Vice President and Chief Financial Officer of Kinder Morgan
 Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan
 Energy Partners, L.P., establishing the terms of the 5.85% Senior Notes due
 2012 (filed as Exhibit 4.2 to Kinder Morgan Energy Partners,
 L.P. Form 10-Q for the quarter ended September 30, 2007 filed November 9,
 2007).                 

111

---



|         |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|-------- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|4.28    |  | Certificate of the Vice President and
 Treasurer and the Vice President and Chief Financial Officer of Kinder Morgan
 Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan
 Energy Partners, L.P., establishing the terms of the 5.95% Senior Notes due
 2018.                                                                                                                                                                                                                                                          
|         |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|4.29    |  | Certain
 instruments with respect to long-term debt of Kinder Morgan Energy Partners,
 L.P. and its consolidated subsidiaries which relate to debt that does not
 exceed 10% of the total assets of Kinder Morgan Energy Partners, L.P. and its
 consolidated subsidiaries are omitted pursuant to Item 601(b) (4) (iii) (A)
 of Regulation S-K, 17 C.F.R. sec.229.601. Kinder Morgan Energy Partners, L.P.
 hereby agrees to furnish supplementally to the Securities and Exchange Commission
 a copy of each such instrument upon request.
|         |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|*10.1   |  | Kinder
 Morgan Energy Partners, L.P. Common Unit Option Plan (filed as Exhibit 10.6
 to the Kinder Morgan Energy Partners, L.P. 1997 Form 10-K, File No. 1-11234).                                                                                                                                                                                                                                                                                                                                                                          
|         |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|*10.2   |  | Delegation
 of Control Agreement among Kinder Morgan Management, LLC, Kinder Morgan G.P.,
 Inc. and Kinder Morgan Energy Partners, L.P. and its operating partnerships
 (filed as Exhibit 10.1 to the Kinder Morgan Energy Partners, L.P. Form 10-Q
 for the quarter ended June 30, 2001).                                                                                                                                                                                                                                                  
|         |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|*10.3   |  | Amendment No. 1 to Delegation of Control
 Agreement, dated as of July 20, 2007, among Kinder Morgan G.P., Inc., Kinder
 Morgan Management, LLC, Kinder Morgan Energy Partners, L.P. and its operating
 partnerships (filed as Exhibit 10.1 to Kinder Morgan Energy Partners, L.P.s
 Current Report on Form 8-K on July 20, 2007).                                                                                                                                                                                                          
|         |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|*10.4   |  | Kinder
 Morgan Energy Partners, L.P. Directors Unit Appreciation Rights Plan (filed
 as Exhibit 10.6 to the Kinder Morgan Energy Partners, L.P. Form 10-K for 2003
 filed March 5, 2004).                                                                                                                                                                                                                                                                                                                                                  
|         |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|*10.5   |  | Amendment
 No. 1 to Kinder Morgan Energy Partners, L.P. Directors Unit Appreciation
 Rights Plan (filed as Exhibit 10.7 to the Kinder Morgan Energy Partners, L.P.
 Form 10-K for 2003 filed March 5, 2004).                                                                                                                                                                                                                                                                                                                               
|         |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|*10.6   |  | Resignation
 and Non-Compete agreement dated July 21, 2004 between KMGP Services, Inc. and
 Michael C. Morgan, President of Kinder Morgan, Inc., Kinder Morgan G.P., Inc.
 and Kinder Morgan Management, LLC (filed as Exhibit 10.1 to the Kinder Morgan
 Energy Partners, L.P. Form 10-Q for the quarter ended June 30, 2004, filed on
 August 5, 2004).                                                                                                                                                                                   
|         |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|*10.7   |  | Kinder
 Morgan Energy Partners, L.P. Common Unit Compensation Plan for Non-Employee
 Directors (filed as Exhibit 10.2 to Kinder Morgan Energy Partners, L.P. Form
 8-K filed January 21, 2005).                                                                                                                                                                                                                                                                                                                                             
|         |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|*10.8   |  | Form of
 Common Unit Compensation Agreement entered into with Non-Employee Directors
 (filed as Exhibit 10.1 to Kinder Morgan Energy Partners, L.P. Form 8-K filed
 January 21, 2005).                                                                                                                                                                                                                                                                                                                                                      
|         |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|*10.9   |  | Five-Year Credit
 Agreement dated as of August 5, 2005 among Kinder Morgan Energy Partners,
 L.P., the lenders party thereto and Wachovia Bank, National Association as
 Administrative Agent (filed as Exhibit 10.1 to Kinder Morgan Energy Partners,
 L.P.s Current Report on Form 8-K, filed on August 11, 2005).                                                                                                                                                                                                                       
|         |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|*10.10  |  | First
 Amendment, dated October 28, 2005, to Five-Year Credit Agreement dated as of
 August 5, 2005 among Kinder Morgan Energy Partners, L.P., the lenders party
 thereto and Wachovia Bank, National Association as Administrative Agent
 (filed as Exhibit 10.1 to Kinder Morgan Energy Partners, L.P.s Form 10-Q for
 the quarter ended September 30, 2006).                                                                                                                                                                            
|         |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|*10.11  |  | Second
 Amendment, dated April 13, 2006, to Five-Year Credit Agreement dated as of
 August 5, 2005 among Kinder Morgan Energy Partners, L.P., the lenders party
 thereto and Wachovia Bank, National Association as Administrative Agent
 (filed as Exhibit 10.2 to Kinder Morgan Energy Partners, L.P.s Form 10-Q for
 the quarter ended September 30, 2006).                                                                                                                                                                             
|         |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|*10.12  |  | Third
 Amendment, dated October 6, 2006, to Five-Year Credit Agreement dated as of
 August 5, 2005 among Kinder Morgan Energy Partners, L.P., the lenders party
 thereto and Wachovia Bank, National Association as Administrative Agent
 (filed as Exhibit 10.3 to Kinder Morgan Energy Partners, L.P.s Form 10-Q for
 the quarter ended September 30, 2006).                                                                                                                                                                             
|         |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|11.1    |  | Statement
 re: computation of per share earnings.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
|         |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|12.1    |  | Statement
 re: computation of ratio of earnings to fixed charges.                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
|         |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|21.1    |  | List of
 Subsidiaries.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      
|         |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|23.1    |  | Consent of
 PricewaterhouseCoopers LLP.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
|         |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|23.2    |  | Consent of
 Netherland, Sewell and Associates, Inc.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         
|         |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|31.1    |  | Certification
 by CEO pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act
 of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of
 2002.                                                                                                                                                                                                                                                                                                                                                               
|         |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|31.2    |  | Certification
 by CFO pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act
 of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of
 2002.                                                                                                                                                                                                                                                                                                                                                               

112

---



|       |  |                                                                                                                                 
|------ |  | --------------------------------------------------------------------------------------------------------------------------------
|32.1  |  | Certification
 by CEO pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906
 of the Sarbanes-Oxley Act of 2002.
|       |  |                                                                                                                                 
|32.2  |  | Certification
 by CFO pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906
 of the Sarbanes-Oxley Act of 2002.

|  |                                                                                                                                       
|- | --------------------------------------------------------------------------------------------------------------------------------------
| 
| 
|* | Asterisk indicates exhibits incorporated by reference as indicated;
 all other exhibits are filed herewith, except as noted otherwise.

113

---



INDEX TO
FINANCIAL STATEMENTS

|                                                                                                        |  |              
|------------------------------------------------------------------------------------------------------- |  | -------------
|                                                                                                        |  | Page 
 Number
|                                                                                                        |  |              
|KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES                                                    |  |              
|                                                                                                        |  |              
|Report
 of Independent Registered Public Accounting Firm                                                |  | 115          
|                                                                                                        |  |              
|Consolidated
 Statements of Income for the years ended December 31, 2007, 2006, and 2005                |  | 117          
|                                                                                                        |  |              
|Consolidated
 Statements of Comprehensive Income for the years ended December 31, 2007,
 2006, and 2005 |  | 118          
|                                                                                                        |  |              
|Consolidated
 Balance Sheets as of December 31, 2007 and 2006                                           |  | 119          
|                                                                                                        |  |              
|Consolidated
 Statements of Cash Flows for the years ended December 31, 2007, 2006, and
 2005           |  | 120          
|                                                                                                        |  |              
|Consolidated
 Statements of Partners Capital for the years ended December 31, 2007, 2006,
 and 2005    |  | 122          
|                                                                                                        |  |              
|Notes
 to Consolidated Financial Statements                                                             |  | 123          

114

---



Report of Independent
Registered Public Accounting Firm

To the
Partners of 
Kinder Morgan Energy Partners, L.P.:

In our opinion,
the accompanying consolidated balance sheets and the related statements of
income and comprehensive income, of partners capital and of cash flows present
fairly, in all material respects, the financial position of Kinder Morgan
Energy Partners, L.P. (the Partnership) and its subsidiaries at December 31,
2007 and 2006, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 2007 in conformity
with accounting principles generally accepted in the United States of America.
Also in our opinion, the Partnership maintained, in all material respects,
effective internal control over financial reporting as of December 31, 2007,
based on criteria established in Internal Control - Integrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
The Partnerships management is responsible for these financial statements, for
maintaining effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial reporting,
included in Managements Report on Internal Control Over Financial Reporting
appearing in item 9A. Our responsibility is to express opinions on these
financial statements and on the Partnerships internal control over financial
reporting based on our integrated audits. We conducted our audits in accordance
with the standards of the Public Company Accounting Oversight Board (United
States). Those standards require that we plan and perform the audits to obtain
reasonable assurance about whether the financial statements are free of
material misstatement and whether effective internal control over financial
reporting was maintained in all material respects. Our audits of the financial
statements included examining, on a test basis, evidence supporting the amounts
and disclosures in the financial statements, assessing the accounting
principles used and significant estimates made by management, and evaluating
the overall financial statement presentation. Our audit of internal control
over financial reporting included obtaining an understanding of internal
control over financial reporting, assessing the risk that a material weakness
exists, and testing and evaluating the design and operating effectiveness of
internal control based on the assessed risk. Our audits also included
performing such other procedures as we considered necessary in the
circumstances. We believe that our audits provide a reasonable basis for our
opinions.

A companys
internal control over financial reporting is a process designed to provide
reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with
generally accepted accounting principles. A companys internal control over
financial reporting includes those policies and procedures that (i) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (ii)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally
accepted accounting principles, and that receipts and expenditures of the
company are being made only in accordance with authorizations of management and
directors of the company; and (iii) provide reasonable assurance regarding
prevention or timely detection of unauthorized acquisition, use, or disposition
of the companys assets that could have a material effect on the financial
statements.

Because of its
inherent limitations, internal control over financial reporting may not prevent
or detect misstatements. Also, projections of any evaluation of effectiveness
to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the
policies or procedures may deteriorate.

As described
in Managements Report on Internal Control Over Financial Reporting, management
has excluded:

| |   |                                                                                                         
| | - | --------------------------------------------------------------------------------------------------------
| |  | The
 Vancouver Wharves bulk marine terminal, acquired May 30, 2007; and                                 
| |   |                                                                                                         
| |  | The terminal
 assets and operations acquired from Marine Terminals, Inc., effective
 September 30, 2007,

(the Acquired
Businesses) from its assessment of internal control over financial reporting
as of December 31, 2007 because these businesses were each acquired by the
Partnership in a purchase business combination during 2007. We have also
excluded the Acquired Businesses from our audit of internal control over
financial reporting. These Acquired Businesses are wholly-owned subsidiaries
whose total assets and total revenues, in the aggregate,

115

---



represent 0.6%
and 1.2%, respectively, of the related consolidated financial statement amounts
as of and for the year ended December 31, 2007.

/s/ PricewaterhouseCoopers
LLP 
PricewaterhouseCoopers LLP 
Houston, Texas 
February 25, 2008

116

---



KINDER MORGAN ENERGY PARTNERS, L.P. AND
SUBSIDIARIES

CONSOLIDATED
STATEMENTS OF INCOME

|                                                                |  |                                       |         |      |   |         |   |   |         |  
|--------------------------------------------------------------- |  | ------------------------------------- | ------- | ---- | - | ------- | - | - | ------- | -
|                                                                |  | Year Ended December 31,               |        
|                                                                |  |                                       |        
|                                                                |  | 2007                                  |         | 2006 |   | 2005    |  
|                                                                |  |                                       |         |      |   |         |  
|                                                                |  | (In millions except per unit amounts) |        
|Revenues                                                        |  |                                       |         |      |   |         |   |   |         |  
|Natural gas
sales                                               |  | $                                     | 5,834.7 |      | $ | 6,039.9 |   | $ | 7,198.5 |  
|Services                                                        |  |                                       | 2,449.2 |      |   | 2,177.6 |   |   | 1,810.5 |  
|Product sales
and other                                         |  |                                       | 933.8   |      |   | 831.2   |   |   | 736.9   |  
|                                                                |  |                                       |         |      |   |         |   |   |         |  
|                                                                |  |                                       | 9,217.7 |      |   | 9,048.7 |   |   | 9,745.9 |  
|                                                                |  |                                       |         |      |   |         |   |   |         |  
|Costs, Expenses and
Other                                       |  |                                       |         |      |   |         |   |   |         |  
|Gas purchases
and other costs of sales                          |  |                                       | 5,809.8 |      |   | 5,990.9 |   |   | 7,167.3 |  
|Operations and
maintenance                                      |  |                                       | 1,024.6 |      |   | 777.0   |   |   | 719.5   |  
|Fuel and
power                                                  |  |                                       | 237.5   |      |   | 223.7   |   |   | 178.5   |  
|Depreciation,
depletion and amortization                        |  |                                       | 540.0   |      |   | 423.9   |   |   | 341.6   |  
|General and
administrative                                      |  |                                       | 278.7   |      |   | 238.4   |   |   | 216.7   |  
|Taxes, other
than income taxes                                  |  |                                       | 153.8   |      |   | 134.4   |   |   | 106.5   |  
|Goodwill
impairment expense                                     |  |                                       | 377.1   |      |   |        |   |   |        |  
|Other expense
(income)                                          |  |                                       | (11.5   | )    |   | (31.2   | ) |   |        |  
|                                                                |  |                                       |         |      |   |         |   |   |         |  
|                                                                |  |                                       | 8,410.0 |      |   | 7,757.1 |   |   | 8,730.1 |  
|                                                                |  |                                       |         |      |   |         |   |   |         |  
|                                                                |  |                                       |         |      |   |         |   |   |         |  
|Operating Income                                                |  |                                       | 807.7   |      |   | 1,291.6 |   |   | 1,015.8 |  
|                                                                |  |                                       |         |      |   |         |   |   |         |  
|Other Income (Expense)                                          |  |                                       |         |      |   |         |   |   |         |  
|Earnings from
equity investments                                |  |                                       | 69.7    |      |   | 74.0    |   |   | 89.6    |  
|Amortization of
excess cost of equity investments               |  |                                       | (5.8    | )    |   | (5.6    | ) |   | (5.5    | )
|Interest,
net                                                   |  |                                       | (391.4  | )    |   | (337.8  | ) |   | (259.0  | )
|Other,
net                                                      |  |                                       | 14.2    |      |   | 12.0    |   |   | 3.3     |  
|Minority
Interest                                               |  |                                       | (7.0    | )    |   | (15.4   | ) |   | (7.3    | )
|                                                                |  |                                       |         |      |   |         |   |   |         |  
|                                                                |  |                                       |         |      |   |         |   |   |         |  
|Income from Continuing
Operations Before Income Taxes           |  |                                       | 487.4   |      |   | 1,018.8 |   |   | 836.9   |  
|                                                                |  |                                       |         |      |   |         |   |   |         |  
|Income Taxes                                                    |  |                                       | (71.0   | )    |   | (29.0   | ) |   | (24.5   | )
|                                                                |  |                                       |         |      |   |         |   |   |         |  
|                                                                |  |                                       |         |      |   |         |   |   |         |  
|Income from Continuing
Operations                               |  |                                       | 416.4   |      |   | 989.8   |   |   | 812.4   |  
|                                                                |  |                                       |         |      |   |         |   |   |         |  
|Discontinued
Operations:                                        |  |                                       |         |      |   |         |   |   |         |  
|Income (loss)
from operations of North System                   |  |                                       | 21.1    |      |   | 14.3    |   |   | (0.2    | )
|Gain on
disposal of North System                                |  |                                       | 152.8   |      |   |        |   |   |        |  
|                                                                |  |                                       |         |      |   |         |   |   |         |  
|Income (loss) from Discontinued
Operations                      |  |                                       | 173.9   |      |   | 14.3    |   |   | (0.2    | )
|                                                                |  |                                       |         |      |   |         |   |   |         |  
|Net Income                                                      |  | $                                     | 590.3   |      | $ | 1,004.1 |   | $ | 812.2   |  
|                                                                |  |                                       |         |      |   |         |   |   |         |  
|                                                                |  |                                       |         |      |   |         |   |   |         |  
|Calculation of Limited
Partners interest in Net Income (loss): |  |                                       |         |      |   |         |   |   |         |  
|Income from
Continuing Operations                               |  | $                                     | 416.4   |      | $ | 989.8   |   | $ | 812.4   |  
|Less: General
Partners interest                                |  |                                       | (609.9  | )    |   | (513.2  | ) |   | (477.3  | )
|                                                                |  |                                       |         |      |   |         |   |   |         |  
|Limited
Partners interest                                      |  |                                       | (193.5  | )    |   | 476.6   |   |   | 335.1   |  
|Add: Limited
Partners interest in Discontinued Operations      |  |                                       | 172.2   |      |   | 14.2    |   |   | (0.2    | )
|                                                                |  |                                       |         |      |   |         |   |   |         |  
|Limited Partners interest
in Net Income (loss)                 |  | $                                     | (21.3   | )    | $ | 490.8   |   | $ | 334.9   |  
|                                                                |  |                                       |         |      |   |         |   |   |         |  
|                                                                |  |                                       |         |      |   |         |   |   |         |  
|Basic Limited Partners Net
Income (loss) per Unit:             |  |                                       |         |      |   |         |   |   |         |  
|Income (loss)
from Continuing Operations                        |  | $                                     | (0.82   | )    | $ | 2.12    |   | $ | 1.58    |  
|Income from
Discontinued Operations                             |  |                                       | 0.73    |      |   | 0.07    |   |   |        |  
|                                                                |  |                                       |         |      |   |         |   |   |         |  
|Net Income (loss)                                               |  | $                                     | (0.09   | )    | $ | 2.19    |   | $ | 1.58    |  
|                                                                |  |                                       |         |      |   |         |   |   |         |  
|Weighted average number of units
outstanding                    |  |                                       | 236.9   |      |   | 224.6   |   |   | 212.2   |  
|                                                                |  |                                       |         |      |   |         |   |   |         |  
|                                                                |  |                                       |         |      |   |         |   |   |         |  
|Diluted Limited Partners
Net Income (loss) per Unit:           |  |                                       |         |      |   |         |   |   |         |  
|Income (loss)
from Continuing Operations                        |  | $                                     | (0.82   | )    | $ | 2.12    |   | $ | 1.58    |  
|Income from
Discontinued Operations                             |  |                                       | 0.73    |      |   | 0.06    |   |   |        |  
|                                                                |  |                                       |         |      |   |         |   |   |         |  
|Net Income (loss)                                               |  | $                                     | (0.09   | )    | $ | 2.18    |   | $ | 1.58    |  
|                                                                |  |                                       |         |      |   |         |   |   |         |  
|Weighted average number of units
outstanding                    |  |                                       | 236.9   |      |   | 224.9   |   |   | 212.4   |  
|                                                                |  |                                       |         |      |   |         |   |   |         |  
|                                                                |  |                                       |         |      |   |         |   |   |         |  
|Per unit cash distribution
declared                             |  | $                                     | 3.48    |      | $ | 3.26    |   | $ | 3.13    |  
|                                                                |  |                                       |         |      |   |         |   |   |         |  

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

117

---



KINDER MORGAN ENERGY PARTNERS, L.P. AND
SUBSIDIARIES

CONSOLIDATED
STATEMENTS OF COMPREHENSIVE INCOME

|                                                                                                                                                                                                                                                             |  |                         |        |      |   |         |   |   |          |  
|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------ |  | ----------------------- | ------ | ---- | - | ------- | - | - | -------- | -
|                                                                                                                                                                                                                                                             |  | Year Ended December 31, |       
|                                                                                                                                                                                                                                                             |  |                         |       
|                                                                                                                                                                                                                                                             |  | 2007                    |        | 2006 |   | 2005    |  
|                                                                                                                                                                                                                                                             |  |                         |        |      |   |         |  
|                                                                                                                                                                                                                                                             |  | (In millions)           |       
|                                                                                                                                                                                                                                                             |  |                         |       
|Net Income                                                                                                                                                                                                                                                   |  | $                       | 590.3  |      | $ | 1,004.1 |   | $ | 812.2    |  
|                                                                                                                                                                                                                                                             |  |                         |        |      |   |         |   |   |          |  
|Change in fair value of
derivatives used for hedging purposes                                                                                                                                                                                                |  |                         | (974.2 | )    |   | (187.5  | ) |   | (1,045.6 | )
|Reclassification of change in
fair value of derivatives to net income                                                                                                                                                                                        |  |                         | 433.2  |      |   | 428.1   |   |   | 424.0    |  
|Foreign currency translation
adjustments                                                                                                                                                                                                                     |  |                         | 132.5  |      |   | (19.6   | ) |   | (0.7     | )
|Minimum pension liability
adjustments, pension and other
 post-retirement benefit plan actuarial gains/losses, and reclassification of pension
 and other post-retirement benefit plan actuarial gains/losses and prior
 service costs/credits to net income |  |                         | (3.5   | )    |   | (1.8    | ) |   |         |  
|                                                                                                                                                                                                                                                             |  |                         |        |      |   |         |   |   |          |  
|Total other
comprehensive income                                                                                                                                                                                                                             |  |                         | (412.0 | )    |   | 219.2   |   |   | (622.3   | )
|                                                                                                                                                                                                                                                             |  |                         |        |      |   |         |   |   |          |  
|                                                                                                                                                                                                                                                             |  |                         |        |      |   |         |   |   |          |  
|Comprehensive Income                                                                                                                                                                                                                                         |  | $                       | 178.3  |      | $ | 1,223.3 |   | $ | 189.9    |  
|                                                                                                                                                                                                                                                             |  |                         |        |      |   |         |   |   |          |  

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

118

---



KINDER MORGAN ENERGY PARTNERS, L.P. AND
SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

|                                                                                                                         |  |                       |   |          |   |  |  |   |          |   | 
|------------------------------------------------------------------------------------------------------------------------ |  | --------------------- | - | -------- | - |  |  | - | -------- | - | 
|                                                                                                                         |  | December 31,         
|                                                                                                                         |  |                      
|                                                                                                                         |  | 2007                  |   | 2006    
|                                                                                                                         |  |                       |   |         
|                                                                                                                         |  | (Dollars in millions)
|ASSETS                                                                                                                   |  |                       |   |          |   |  | 
|Current Assets                                                                                                           |  |                       |   |          |   |  | 
|Cash and cash
equivalents                                                                                                |  |                       | $ | 58.9     |   |  |  | $ | 6.7      |   | 
|Restricted
deposits                                                                                                      |  |                       |   | 67.9     |   |  |  |   |         |   | 
|Accounts,
notes and interest receivable, net Trade                                                                       |  |                       |   | 960.2    |   |  |  |   | 854.7    |   | 
|Related
parties                                                                                                          |  |                       |   | 3.6      |   |  |  |   | 7.9      |   | 
|Inventories                                                                                                              |  |                       |   |          |   |  |  |   |          |   | 
|Products                                                                                                                 |  |                       |   | 19.5     |   |  |  |   | 20.4     |   | 
|Materials and
supplies                                                                                                   |  |                       |   | 18.3     |   |  |  |   | 16.6     |   | 
|Gas
imbalances                                                                                                           |  |                       |   |          |   |  |  |   |          |   | 
|Trade                                                                                                                    |  |                       |   | 21.2     |   |  |  |   | 7.8      |   | 
|Related
parties                                                                                                          |  |                       |   | 5.7      |   |  |  |   | 11.6     |   | 
|Other current
assets                                                                                                     |  |                       |   | 54.4     |   |  |  |   | 111.1    |   | 
|                                                                                                                         |  |                       |   |          |   |  |  |   |          |   | 
|                                                                                                                         |  |                       |   | 1,209.7  |   |  |  |   | 1,036.8  |   | 
|                                                                                                                         |  |                       |   |          |   |  |  |   |          |   | 
|Property, Plant and
  Equipment, net                                                                                     |  |                       |   | 11,591.3 |   |  |  |   | 10,106.1 |   | 
|Investments                                                                                                              |  |                       |   | 655.4    |   |  |  |   | 426.3    |   | 
|Notes receivable                                                                                                         |  |                       |   |          |   |  |  |   |          |   | 
|Trade                                                                                                                    |  |                       |   | 0.1      |   |  |  |   | 1.2      |   | 
|Related
parties                                                                                                          |  |                       |   | 87.9     |   |  |  |   | 96.2     |   | 
|Goodwill                                                                                                                 |  |                       |   | 1,077.8  |   |  |  |   | 1,421.0  |   | 
|Other intangibles, net                                                                                                   |  |                       |   | 238.6    |   |  |  |   | 213.2    |   | 
|Deferred charges and other
  assets                                                                                      |  |                       |   | 317.0    |   |  |  |   | 241.4    |   | 
|                                                                                                                         |  |                       |   |          |   |  |  |   |          |   | 
|Total Assets                                                                                                             |  |                       | $ | 15,177.8 |   |  |  | $ | 13,542.2 |   | 
|                                                                                                                         |  |                       |   |          |   |  |  |   |          |   | 
|LIABILITIES AND PARTNERS CAPITAL                                                                                        |  |                       |   |          |   |  |  |   |          |   | 
|Current Liabilities                                                                                                      |  |                       |   |          |   |  |  |   |          |   | 
|Accounts
payable                                                                                                         |  |                       |   |          |   |  |  |   |          |   | 
|Cash book
overdrafts                                                                                                     |  |                       | $ | 19.0     |   |  |  | $ | 46.2     |   | 
|Trade                                                                                                                    |  |                       |   | 926.7    |   |  |  |   | 784.1    |   | 
|Related
parties                                                                                                          |  |                       |   | 22.6     |   |  |  |   | 203.3    |   | 
|Current
portion of long-term debt                                                                                        |  |                       |   | 610.2    |   |  |  |   | 1,359.1  |   | 
|Accrued
interest                                                                                                         |  |                       |   | 131.2    |   |  |  |   | 83.7     |   | 
|Accrued
taxes                                                                                                            |  |                       |   | 73.8     |   |  |  |   | 35.4     |   | 
|Deferred
revenues                                                                                                        |  |                       |   | 22.8     |   |  |  |   | 20.0     |   | 
|Gas
imbalances                                                                                                           |  |                       |   |          |   |  |  |   |          |   | 
|Trade                                                                                                                    |  |                       |   | 23.7     |   |  |  |   | 15.9     |   | 
|Related
parties                                                                                                          |  |                       |   |         |   |  |  |   |         |   | 
|Accrued other
current liabilities                                                                                        |  |                       |   | 728.3    |   |  |  |   | 589.6    |   | 
|                                                                                                                         |  |                       |   |          |   |  |  |   |          |   | 
|                                                                                                                         |  |                       |   | 2,558.3  |   |  |  |   | 3,137.3  |   | 
|                                                                                                                         |  |                       |   |          |   |  |  |   |          |   | 
|Long-Term Liabilities and
  Deferred Credits                                                                             |  |                       |   |          |   |  |  |   |          |   | 
|Long-term
debt                                                                                                           |  |                       |   |          |   |  |  |   |          |   | 
|Outstanding                                                                                                              |  |                       |   | 6,455.9  |   |  |  |   | 4,384.3  |   | 
|Value
of interest rate swaps                                                                                             |  |                       |   | 152.2    |   |  |  |   | 42.6     |   | 
|                                                                                                                         |  |                       |   |          |   |  |  |   |          |   | 
|                                                                                                                         |  |                       |   | 6,608.1  |   |  |  |   | 4,426.9  |   | 
|Deferred
revenues                                                                                                        |  |                       |   | 14.2     |   |  |  |   | 18.8     |   | 
|Deferred
income taxes                                                                                                    |  |                       |   | 202.4    |   |  |  |   | 185.2    |   | 
|Asset
retirement obligations                                                                                             |  |                       |   | 50.8     |   |  |  |   | 48.9     |   | 
|Other
long-term liabilities and deferred credits                                                                         |  |                       |   | 1,254.1  |   |  |  |   | 716.6    |   | 
|                                                                                                                         |  |                       |   |          |   |  |  |   |          |   | 
|                                                                                                                         |  |                       |   | 8,129.6  |   |  |  |   | 5,396.4  |   | 
|                                                                                                                         |  |                       |   |          |   |  |  |   |          |   | 
|Commitments and
  Contingencies (Notes 13 and 16)                                                                        |  |                       |   |          |   |  |  |   |          |   | 
|Minority Interest                                                                                                        |  |                       |   | 54.2     |   |  |  |   | 60.2     |   | 
|                                                                                                                         |  |                       |   |          |   |  |  |   |          |   | 
|Partners Capital                                                                                                        |  |                       |   |          |   |  |  |   |          |   | 
|Common Units
(170,220,396 and 162,816,303 units issued and outstanding
  as of December 31, 2007 and 2006, respectively) |  |                       |   | 3,048.4  |   |  |  |   | 3,414.9  |   | 
|Class B Units
(5,313,400 and 5,313,400 units issued and outstanding as
  of December 31, 2007 and 2006, respectively)    |  |                       |   | 102.0    |   |  |  |   | 126.1    |   | 
|i-Units
(72,432,482 and 62,301,676 units issued and outstanding as of
  December 31, 2007 and 2006, respectively)        |  |                       |   | 2,400.8  |   |  |  |   | 2,154.2  |   | 
|General
Partner                                                                                                          |  |                       |   | 161.1    |   |  |  |   | 119.2    |   | 
|Accumulated
other comprehensive loss                                                                                     |  |                       |   | (1,276.6 | ) |  |  |   | (866.1   | ) | 
|                                                                                                                         |  |                       |   |          |   |  |  |   |          |   | 
|                                                                                                                         |  |                       |   | 4,435.7  |   |  |  |   | 4,948.3  |   | 
|                                                                                                                         |  |                       |   |          |   |  |  |   |          |   | 
|Total Liabilities and
  Partners Capital                                                                                |  |                       | $ | 15,177.8 |   |  |  | $ | 13,542.2 |   | 
|                                                                                                                         |  |                       |   |          |   |  |  |   |          |   | 

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

119

---



KINDER MORGAN ENERGY PARTNERS, L.P. AND
SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

|                                                                                    |  |                         |   |          |   |      |  |   |          |   |  |  |   |          |   | 
|----------------------------------------------------------------------------------- |  | ----------------------- | - | -------- | - | ---- |  | - | -------- | - |  |  | - | -------- | - | 
|                                                                                    |  | Year Ended December 31,
|                                                                                    |  |                        
|                                                                                    |  | 2007                    |   | 2006     |   | 2005
|                                                                                    |  |                         |   |          |   |     
|                                                                                    |  | (In millions)          
|Cash Flows From Operating
Activities                                                |  |                         |   |          |   |      |  |   |          |  
|Net
income                                                                          |  |                         | $ | 590.3    |   |      |  | $ | 1,004.1  |   |  |  | $ | 812.2    |   | 
|Adjustments to
reconcile net income to net cash provided by operating
  activities: |  |                         |   |          |   |      |  |   |          |   |  |  |   |          |   | 
|Depreciation,
depletion and amortization                                            |  |                         |   | 547.0    |   |      |  |   | 432.8    |   |  |  |   | 349.8    |   | 
|Amortization
of excess cost of equity investments                                   |  |                         |   | 5.8      |   |      |  |   | 5.7      |   |  |  |   | 5.6      |   | 
|Impairment of
goodwill                                                              |  |                         |   | 377.1    |   |      |  |   |         |   |  |  |   |         |   | 
|Gains and
other non-cash income from the sale of property, plant and
  equipment    |  |                         |   | (162.5   | ) |      |  |   | (15.2    | ) |  |  |   | (0.5     | ) | 
|Gains from
property casualty indemnifications                                       |  |                         |   | (1.8     | ) |      |  |   | (15.2    | ) |  |  |   |         |   | 
|Earnings from
equity investments                                                    |  |                         |   | (71.5    | ) |      |  |   | (76.2    | ) |  |  |   | (91.7    | ) | 
|Distributions
from equity investments                                               |  |                         |   | 104.1    |   |      |  |   | 67.9     |   |  |  |   | 63.1     |   | 
|Changes in
components of working capital:                                           |  |                         |   |          |   |      |  |   |          |   |  |  |   |          |   | 
|Accounts
receivable                                                                 |  |                         |   | 92.6     |   |      |  |   | 15.8     |   |  |  |   | (240.7   | ) | 
|Other current
assets                                                                |  |                         |   | 3.9      |   |      |  |   | 13.8     |   |  |  |   | (14.1    | ) | 
|Inventories                                                                         |  |                         |   | (6.9     | ) |      |  |   | 0.9      |   |  |  |   | (13.5    | ) | 
|Accounts
payable                                                                    |  |                         |   | (79.7    | ) |      |  |   | (48.8    | ) |  |  |   | 294.9    |   | 
|Accrued
interest                                                                    |  |                         |   | 47.3     |   |      |  |   | 8.0      |   |  |  |   | 17.9     |   | 
|Accrued
liabilities                                                                 |  |                         |   | (9.5     | ) |      |  |   | (10.6    | ) |  |  |   | 4.5      |   | 
|Accrued
taxes                                                                       |  |                         |   | 40.7     |   |      |  |   | 14.2     |   |  |  |   | (2.3     | ) | 
|Rate
reparations, refunds and other litigation reserve adjustments                  |  |                         |   | 140.0    |   |      |  |   | (19.1    | ) |  |  |   | 105.0    |   | 
|Other,
net                                                                          |  |                         |   | 124.9    |   |      |  |   | (14.2    | ) |  |  |   | (0.8     | ) | 
|                                                                                    |  |                         |   |          |   |      |  |   |          |   |  |  |   |          |   | 
|Net Cash Provided by Operating
Activities                                           |  |                         |   | 1,741.8  |   |      |  |   | 1,363.9  |   |  |  |   | 1,289.4  |   | 
|                                                                                    |  |                         |   |          |   |      |  |   |          |   |  |  |   |          |   | 
|                                                                                    |  |                         |   |          |   |      |  |   |          |   |  |  |   |          |   | 
|Cash Flows From Investing
Activities                                                |  |                         |   |          |   |      |  |   |          |   |  |  |   |          |   | 
|Acquisitions
of assets and equity investments                                       |  |                         |   | (713.3   | ) |      |  |   | (387.2   | ) |  |  |   | (307.8   | ) | 
|Additions to
property, plant and equip. for expansion and maintenance
  projects    |  |                         |   | (1,691.6 | ) |      |  |   | (1,182.1 | ) |  |  |   | (863.1   | ) | 
|Sale of
property, plant and equipment, and other net assets net of
  removal costs  |  |                         |   | 302.6    |   |      |  |   | 70.8     |   |  |  |   | 9.9      |   | 
|Property
casualty indemnifications                                                  |  |                         |   | 8.0      |   |      |  |   | 13.1     |   |  |  |   |         |   | 
|Net proceeds
from (Investments in) margin deposits                                  |  |                         |   | (70.2    | ) |      |  |   | 2.3      |   |  |  |   |         |   | 
|Contributions
to equity investments                                                 |  |                         |   | (276.1   | ) |      |  |   | (2.5     | ) |  |  |   | (1.2     | ) | 
|Natural gas
stored underground and natural gas liquids line-fill                    |  |                         |   | 12.3     |   |      |  |   | (12.9    | ) |  |  |   | (18.7    | ) | 
|Other                                                                               |  |                         |   | (0.2     | ) |      |  |   | (3.4     | ) |  |  |   | (0.2     | ) | 
|                                                                                    |  |                         |   |          |   |      |  |   |          |   |  |  |   |          |   | 
|Net Cash Used in Investing
Activities                                               |  |                         |   | (2,428.5 | ) |      |  |   | (1,501.9 | ) |  |  |   | (1,181.1 | ) | 
|                                                                                    |  |                         |   |          |   |      |  |   |          |   |  |  |   |          |   | 
|                                                                                    |  |                         |   |          |   |      |  |   |          |   |  |  |   |          |   | 
|Cash Flows From Financing
Activities                                                |  |                         |   |          |   |      |  |   |          |   |  |  |   |          |   | 
|Issuance of
debt                                                                    |  |                         |   | 7,686.1  |   |      |  |   | 4,632.5  |   |  |  |   | 4,900.9  |   | 
|Payment of
debt                                                                     |  |                         |   | (6,409.3 | ) |      |  |   | (3,698.7 | ) |  |  |   | (4,463.2 | ) | 
|Repayments
from (Loans to) related party                                            |  |                         |   | 4.4      |   |      |  |   | 1.1      |   |  |  |   | 2.1      |   | 
|Debt issue
costs                                                                    |  |                         |   | (13.8    | ) |      |  |   | (2.0     | ) |  |  |   | (6.0     | ) | 
|Increase
(Decrease) in cash book overdrafts                                         |  |                         |   | (27.2    | ) |      |  |   | 15.8     |   |  |  |   | 0.6      |   | 
|Proceeds from
issuance of common units                                              |  |                         |   | 342.9    |   |      |  |   | 248.4    |   |  |  |   | 415.6    |   | 
|Proceeds from
issuance of i-units                                                   |  |                         |   | 297.9    |   |      |  |   |         |   |  |  |   |         |   | 
|Contributions
from minority interest                                                |  |                         |   | 8.9      |   |      |  |   | 109.8    |   |  |  |   | 7.8      |   | 
|Distributions
to partners:                                                          |  |                         |   |          |   |      |  |   |          |   |  |  |   |          |   | 
|Common
units                                                                        |  |                         |   | (552.6   | ) |      |  |   | (512.1   | ) |  |  |   | (460.6   | ) | 
|Class B
units                                                                       |  |                         |   | (18.0    | ) |      |  |   | (17.2    | ) |  |  |   | (16.3    | ) | 
|General
Partner                                                                     |  |                         |   | (567.7   | ) |      |  |   | (523.2   | ) |  |  |   | (460.9   | ) | 
|Minority
interest                                                                   |  |                         |   | (16.0    | ) |      |  |   | (119.0   | ) |  |  |   | (12.1    | ) | 
|Other,
net                                                                          |  |                         |   | 0.1      |   |      |  |   | (3.0     | ) |  |  |   | (3.9     | ) | 
|                                                                                    |  |                         |   |          |   |      |  |   |          |   |  |  |   |          |   | 
|Net Cash Provided by (Used in)
Financing Activities                                 |  |                         |   | 735.7    |   |      |  |   | 132.4    |   |  |  |   | (96.0    | ) | 
|                                                                                    |  |                         |   |          |   |      |  |   |          |   |  |  |   |          |   | 
|                                                                                    |  |                         |   |          |   |      |  |   |          |   |  |  |   |          |   | 
|Effect of exchange rate changes
on cash and cash equivalents                        |  |                         |   | 3.2      |   |      |  |   | 0.2      |   |  |  |   | (0.2     | ) | 
|                                                                                    |  |                         |   |          |   |      |  |   |          |   |  |  |   |          |   | 
|                                                                                    |  |                         |   |          |   |      |  |   |          |   |  |  |   |          |   | 
|Increase (Decrease) in Cash and
Cash Equivalents                                    |  |                         |   | 52.2     |   |      |  |   | (5.4     | ) |  |  |   | 12.1     |   | 
|Cash and Cash Equivalents,
beginning of year                                        |  |                         |   | 6.7      |   |      |  |   | 12.1     |   |  |  |   |         |   | 
|                                                                                    |  |                         |   |          |   |      |  |   |          |   |  |  |   |          |   | 
|Cash and Cash Equivalents, end
of year                                              |  |                         | $ | 58.9     |   |      |  | $ | 6.7      |   |  |  | $ | 12.1     |   | 
|                                                                                    |  |                         |   |          |   |      |  |   |          |   |  |  |   |          |   | 

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

120

---



KINDER MORGAN ENERGY PARTNERS, L.P. AND
SUBSIDIARIES

CONSOLIDATED
STATEMENTS OF CASH FLOWS
(continued)

|                                                                     |  |                         |   |       |  |      |  |   |         |  |  |  |   |       |  | 
|-------------------------------------------------------------------- |  | ----------------------- | - | ----- |  | ---- |  | - | ------- |  |  |  | - | ----- |  | 
|                                                                     |  | Year Ended December 31,
|                                                                     |  |                        
|                                                                     |  | 2007                    |   | 2006  |  | 2005
|                                                                     |  |                         |   |       |  |     
|                                                                     |  | (In millions)          
|Noncash Investing and
  Financing Activities:                        |  |                         |   |       |  |      |  |   |         | 
|Contribution
of net assets to partnership investments                |  |                         | $ |      |  |      |  | $ | 17.0    |  |  |  | $ |      |  | 
|Assets
acquired by the issuance of units                             |  |                         |   | 15.0  |  |      |  |   | 1.6     |  |  |  |   | 49.6  |  | 
|Assets
acquired by the assumption or incurrence of liabilities       |  |                         |   | 19.7  |  |      |  |   | 6.1     |  |  |  |   | 76.6  |  | 
|Assets
acquired by the transfer of Trans Mountain                    |  |                         |   |      |  |      |  |   | 1,199.5 |  |  |  |   |      |  | 
|Liabilities
assumed by the transfer of Trans Mountain                |  |                         |   |      |  |      |  |   | 282.5   |  |  |  |   |      |  | 
|Related party
asset settlements with Knight                          |  |                         |   | 276.2 |  |      |  |   |        |  |  |  |   |      |  | 
|Related party
liability settlements with Knight                      |  |                         |   | 556.6 |  |      |  |   |        |  |  |  |   |      |  | 
|                                                                     |  |                         |   |       |  |      |  |   |         |  |  |  |   |       |  | 
|Supplemental disclosures of
  cash flow information:                 |  |                         |   |       |  |      |  |   |         |  |  |  |   |       |  | 
|Cash paid
during the year for interest (net of capitalized interest) |  |                         |   | 336.0 |  |      |  |   | 329.2   |  |  |  |   | 245.6 |  | 
|Cash paid
during the year for income taxes                           |  |                         |   | 6.2   |  |      |  |   | 25.6    |  |  |  |   | 7.3   |  | 

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

121

---



KINDER MORGAN ENERGY PARTNERS, L.P. AND
SUBSIDIARIES

CONSOLIDATED
STATEMENTS OF PARTNERS CAPITAL

|                                                                                                    |  |      |             |      |   |          |   |                       |             |  |   |          |   |  |             |  |   |          |  
|--------------------------------------------------------------------------------------------------- |  | ---- | ----------- | ---- | - | -------- | - | --------------------- | ----------- |  | - | -------- | - |  | ----------- |  | - | -------- | -
|                                                                                                    |  | 2007 |             | 2006 |   | 2005     |  
|                                                                                                    |  |      |             |      |   |          |  
|                                                                                                    |  |      | Units       |      |   | Amount   |   |                       | Units       |  |   | Amount   |   |  | Units       |  |   | Amount   |  
|                                                                                                    |  |      |             |      |   |          |   |                       |             |  |   |          |   |  |             |  |   |          |  
|                                                                                                    |  |      |             |      |   |          |   | (Dollars in millions) |             |  |   |          |   |  |            
|Common
Units:                                                                                       |  |      |             |      |   |          |   |                       |             |  |   |          |   |  |             |  |   |          |  
|Beginning
Balance                                                                                   |  |      | 162,816,303 |      | $ | 3,414.9  |   |                       | 157,005,326 |  | $ | 2,680.4  |   |  | 147,537,908 |  | $ | 2,438.0  |  
|Net income
(loss)                                                                                   |  |      |            |      |   | (20.4    | ) |                       |            |  |   | 347.8    |   |  |            |  |   | 237.8    |  
|Units issued as
consideration pursuant to common unit compensation
 plan for non-employee directors |  |      | 7,280       |      |   | 0.4      |   |                       | 5,250       |  |   | 0.3      |   |  | 5,250       |  |   | 0.3      |  
|Units issued as
consideration in the acquisition of assets                                          |  |      | 266,813     |      |   | 15.0     |   |                       | 34,627      |  |   | 1.6      |   |  | 1,022,068   |  |   | 49.6     |  
|Units issued
for cash                                                                               |  |      | 7,130,000   |      |   | 342.5    |   |                       | 5,771,100   |  |   | 248.2    |   |  | 8,440,100   |  |   | 415.3    |  
|Trans Mountain
Acquisition                                                                          |  |      |            |      |   | (166.8   | ) |                       |            |  |   | 648.7    |   |  |            |  |   |         |  
|Knight Inc.
going-private transaction exp.                                                          |  |      |            |      |   | 15.4     |   |                       |            |  |   |         |   |  |            |  |   |         |  
|Distributions                                                                                       |  |      |            |      |   | (552.6   | ) |                       |            |  |   | (512.1   | ) |  |            |  |   | (460.6   | )
|                                                                                                    |  |      |             |      |   |          |   |                       |             |  |   |          |   |  |             |  |   |          |  
|Ending
Balance                                                                                      |  |      | 170,220,396 |      |   | 3,048.4  |   |                       | 162,816,303 |  |   | 3,414.9  |   |  | 157,005,326 |  |   | 2,680.4  |  
|                                                                                                    |  |      |             |      |   |          |   |                       |             |  |   |          |   |  |             |  |   |          |  
|Class B Units:                                                                                      |  |      |             |      |   |          |   |                       |             |  |   |          |   |  |             |  |   |          |  
|Beginning
Balance                                                                                   |  |      | 5,313,400   |      |   | 126.1    |   |                       | 5,313,400   |  |   | 109.6    |   |  | 5,313,400   |  |   | 117.4    |  
|Net income
(loss)                                                                                   |  |      |            |      |   | (0.6     | ) |                       |            |  |   | 11.6     |   |  |            |  |   | 8.5      |  
|Trans Mountain
Acquisition                                                                          |  |      |            |      |   | (6.0     | ) |                       |            |  |   | 22.1     |   |  |            |  |   |         |  
|Knight Inc.
going-private transaction exp.                                                          |  |      |            |      |   | 0.5      |   |                       |            |  |   |         |   |  |            |  |   |         |  
|Distributions                                                                                       |  |      |            |      |   | (18.0    | ) |                       |            |  |   | (17.2    | ) |  |            |  |   | (16.3    | )
|                                                                                                    |  |      |             |      |   |          |   |                       |             |  |   |          |   |  |             |  |   |          |  
|Ending
Balance                                                                                      |  |      | 5,313,400   |      |   | 102.0    |   |                       | 5,313,400   |  |   | 126.1    |   |  | 5,313,400   |  |   | 109.6    |  
|                                                                                                    |  |      |             |      |   |          |   |                       |             |  |   |          |   |  |             |  |   |          |  
|i-Units:                                                                                            |  |      |             |      |   |          |   |                       |             |  |   |          |   |  |             |  |   |          |  
|Beginning
Balance                                                                                   |  |      | 62,301,676  |      |   | 2,154.2  |   |                       | 57,918,373  |  |   | 1,783.6  |   |  | 54,157,641  |  |   | 1,695.0  |  
|Net income
(loss)                                                                                   |  |      |            |      |   | (0.3     | ) |                       |            |  |   | 131.4    |   |  |            |  |   | 88.7     |  
|Units issued
for cash                                                                               |  |      | 5,700,000   |      |   | 297.6    |   |                       |            |  |   |         |   |  |            |  |   | (0.1     | )
|Trans Mountain
Acquisition                                                                          |  |      |            |      |   | (57.4    | ) |                       |            |  |   | 239.2    |   |  |            |  |   |         |  
|Knight Inc.
going-private transaction exp.                                                          |  |      |            |      |   | 6.7      |   |                       |            |  |   |         |   |  |            |  |   |         |  
|Distributions                                                                                       |  |      | 4,430,806   |      |   |         |   |                       | 4,383,303   |  |   |         |   |  | 3,760,732   |  |   |         |  
|                                                                                                    |  |      |             |      |   |          |   |                       |             |  |   |          |   |  |             |  |   |          |  
|Ending
Balance                                                                                      |  |      | 72,432,482  |      |   | 2,400.8  |   |                       | 62,301,676  |  |   | 2,154.2  |   |  | 57,918,373  |  |   | 1,783.6  |  
|                                                                                                    |  |      |             |      |   |          |   |                       |             |  |   |          |   |  |             |  |   |          |  
|General Partner:                                                                                    |  |      |             |      |   |          |   |                       |             |  |   |          |   |  |             |  |   |          |  
|Beginning
Balance                                                                                   |  |      |            |      |   | 119.2    |   |                       |            |  |   | 119.9    |   |  |            |  |   | 103.5    |  
|Net
income                                                                                          |  |      |            |      |   | 611.6    |   |                       |            |  |   | 513.3    |   |  |            |  |   | 477.3    |  
|Trans Mountain
Acquisition                                                                          |  |      |            |      |   | (2.2     | ) |                       |            |  |   | 9.2      |   |  |            |  |   |         |  
|Knight Inc.
going-private transaction exp.                                                          |  |      |            |      |   | 0.2      |   |                       |            |  |   |         |   |  |            |  |   |         |  
|Distributions                                                                                       |  |      |            |      |   | (567.7   | ) |                       |            |  |   | (523.2   | ) |  |            |  |   | (460.9   | )
|                                                                                                    |  |      |             |      |   |          |   |                       |             |  |   |          |   |  |             |  |   |          |  
|Ending
Balance                                                                                      |  |      |            |      |   | 161.1    |   |                       |            |  |   | 119.2    |   |  |            |  |   | 119.9    |  
|                                                                                                    |  |      |             |      |   |          |   |                       |             |  |   |          |   |  |             |  |   |          |  
|Accum. other comprehensive
income (loss):                                                           |  |      |             |      |   |          |   |                       |             |  |   |          |   |  |             |  |   |          |  
|Beginning
Balance                                                                                   |  |      |            |      |   | (866.1   | ) |                       |            |  |   | (1,079.7 | ) |  |            |  |   | (457.4   | )
|Change in fair
value of derivatives used for
hedging purposes                                       |  |      |            |      |   | (974.2   | ) |                       |            |  |   | (187.5   | ) |  |            |  |   | (1,045.6 | )
|Reclassification of change in fair value of derivatives to
net income                               |  |      |            |      |   | 433.2    |   |                       |            |  |   | 428.1    |   |  |            |  |   | 424.0    |  
|Foreign
currency translation adjustments                                                            |  |      |            |      |   | 132.5    |   |                       |            |  |   | (19.6    | ) |  |            |  |   | (0.7     | )
|Pension and
other post-retirement benefit
liability changes                                         |  |      |            |      |   | (3.5     | ) |                       |            |  |   | (1.8     | ) |  |            |  |   |         |  
|Adj. to
initially apply SFAS No. 158-pension and other post-retirement benefit acctg. changes       |  |      |            |      |   | 1.5      |   |                       |            |  |   | (5.6     | ) |  |            |  |   |         |  
|                                                                                                    |  |      |             |      |   |          |   |                       |             |  |   |          |   |  |             |  |   |          |  
|Ending
Balance                                                                                      |  |      |            |      |   | (1,276.6 | ) |                       |            |  |   | (866.1   | ) |  |            |  |   | (1,079.7 | )
|                                                                                                   
|                                                                                                    |  |      |             |      |   |          |   |                       |             |  |   |          |   |  |             |  |   |          |  
|Total Partners
Capital                                                                             |  |      | 247,966,278 |      | $ | 4,435.7  |   |                       | 230,431,379 |  | $ | 4,948.3  |   |  | 220,237,099 |  | $ | 3,613.8  |  
|                                                                                                    |  |      |             |      |   |          |   |                       |             |  |   |          |   |  |             |  |   |          |  

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

122

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KINDER MORGAN ENERGY PARTNERS, L.P. AND
SUBSIDIARIES

NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS

1. Organization

General

Kinder
Morgan Energy Partners, L.P. is a Delaware limited partnership formed in August
1992. Unless the context requires otherwise, references to we, us, our or
the Partnership are intended to mean Kinder Morgan Energy Partners, L.P. and
its consolidated subsidiaries.

We
own and manage a diversified portfolio of energy transportation and storage
assets and presently conduct our business through five reportable business
segments. These segments and the activities performed to provide services to
our customers and create value for our unitholders are as follows:

| |   |                                                                                                                                                                                                        
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | Products
 Pipelines - transporting, storing and processing refined petroleum products;                                                                                                                 
| |   |                                                                                                                                                                                                        
| |  | Natural Gas
 Pipelines - transporting, storing, selling, gathering, treating and
 processing natural gas;                                                                                              
| |   |                                                                                                                                                                                                        
| |  | CO2-producing,
 transporting and selling carbon dioxide, commonly called CO2, for use in, and
 selling crude oil, natural gas and natural gas liquids produced from,
 enhanced oil recovery operations;
| |   |                                                                                                                                                                                                        
| |  | Terminals -
 transloading, storing and delivering a wide variety of bulk, petroleum,
 petrochemical and other liquid products at terminal facilities located across
 North America; and                
| |   |                                                                                                                                                                                                        
| |  | Trans
 Mountain  transporting crude oil and refined petroleum products from
 Edmonton, Alberta, Canada to marketing terminals and refineries in British
 Columbia and the state of Washington.        

We
focus on providing fee-based services to customers, generally avoiding
near-term commodity price risks and taking advantage of the tax benefits of a
limited partnership structure. We trade on the New York Stock Exchange under
the symbol KMP, and we conduct our operations through the following five
limited partnerships:

| |   |                                               
| | - | ----------------------------------------------
| |  | Kinder
 Morgan Operating L.P. A (OLP-A);    
| |   |                                               
| |  | Kinder
 Morgan Operating L.P. B (OLP-B);    
| |   |                                               
| |  | Kinder
 Morgan Operating L.P. C (OLP-C);    
| |   |                                               
| |  | Kinder
 Morgan Operating L.P. D (OLP-D); and
| |   |                                               
| |  | Kinder Morgan CO2 Company (KMCO2).            

Combined,
the five limited partnerships are referred to as our operating partnerships,
and we are the 98.9899% limited partner and our general partner is the 1.0101%
general partner in each. Both we and our operating partnerships are governed by
Amended and Restated Agreements of Limited Partnership, as amended and certain
other agreements that are collectively referred to in this report as the
partnership agreements.

Knight Inc.
and Kinder Morgan G.P., Inc.

On
August 28, 2006, Kinder Morgan, Inc., a Kansas corporation referred to as KMI
in this report, entered into an agreement and plan of merger whereby generally each share of KMI common stock would be converted into the right to receive $107.50 in cash without interest.  KMI in turn would merge with a wholly owned subsidiary of Knight Holdco LLC, a privately owned company in which Richard D. Kinder, Chairman and Chief Executive Officer of KMI, would be a major investor.  On May 30, 2007, the merger closed, with KMI continuing as the surviving legal entity and subsequently renamed Knight Inc., referred to as Knight in this report.  Additional investors in Knight Holdco LLC include the following: other senior members of Knight management, most of whom are also senior officers of Kinder Morgan G.P., Inc. (our general partner) and of Kinder Morgan Management, LLC (our general partners delegate); KMI co-founder William V. Morgan; KMI board members Fayez Sarofim and Michael C. Morgan; and affiliates of (i) Goldman Sachs
Capital Partners; (ii) American International Group, Inc.; (iii) The Carlyle Group; and (iv) Riverstone Holdings LLC.  This transaction is referred to in this report as the going-private transaction.

123

---



Knight
is privately owned, and remains the sole indirect
common stockholder of our general partner. On July 27, 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. At December 31, 2007, Knight
and its consolidated subsidiaries owned, through its general and limited
partner interests, an approximate 13.9% interest in us.

Kinder Morgan
Management, LLC

Kinder
Morgan Management, LLC, a Delaware limited liability company, was formed on
February 14, 2001. Its shares represent limited liability company interests and
are traded on the New York Stock Exchange under the symbol KMR. Kinder Morgan
Management, LLC is referred to as KMR in this report. Our general partner
owns all of KMRs voting securities and, pursuant to a delegation of control
agreement, our general partner 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.

Under
the delegation of control agreement, KMR manages and controls our business and
affairs and the business and affairs of our operating limited partnerships and
their subsidiaries. Furthermore, in accordance with its limited liability
company agreement, KMRs activities are limited to being a limited partner in,
and managing and controlling the business and affairs of us, our operating
limited partnerships and their subsidiaries. As of December 31, 2007, KMR owned
approximately 29.2% of our outstanding limited partner units (which are in the
form of i-units that are issued only to KMR).

2. Summary of Significant Accounting Policies

Basis of
Presentation

Our
consolidated financial statements include our accounts and those of our
operating partnerships and their majority-owned and controlled subsidiaries.
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$. All significant intercompany items have
been eliminated in consolidation. Certain amounts from prior years have been
reclassified to conform to the current presentation.

Our
consolidated financial statements were prepared in accordance with accounting
principles generally accepted in the United States. We believe, however, that
certain accounting policies are of more significance in our financial statement
preparation process than others. Also, certain amounts included in or affecting
our financial statements and related disclosures must be estimated, requiring
us to make certain assumptions with respect to values or conditions which
cannot be known with certainty at the time our financial statements are
prepared.

These
estimates and assumptions affect the amounts we report for assets and
liabilities, our revenues and expenses during the reporting period, and our
disclosure of contingent assets and liabilities at the date of our financial
statements. We evaluate these estimates on an ongoing basis, utilizing
historical experience, consultation with experts and other methods we consider
reasonable in the particular circumstances. Nevertheless, actual results may
differ significantly from our estimates. Any effects on our business, financial
position or results of operations resulting from revisions to these estimates
are recorded in the period in which the facts that give rise to the revision
become known.

124

---



Cash Equivalents

We
define cash equivalents as all highly liquid short-term investments with
original maturities of three months or less.

Accounts
Receivables

Our
policy for determining an appropriate allowance for doubtful accounts varies
according to the type of business being conducted and the customers being
served. An allowance for doubtful accounts is charged to expense monthly,
generally using a percentage of revenue or receivables, based on a historical
analysis of uncollected amounts, adjusted as necessary for changed
circumstances and customer-specific information. When specific receivables are
determined to be uncollectible, the reserve and receivable are relieved. The
following table shows the balance in the allowance for doubtful accounts and
activity for the years ended December 31, 2007, 2006 and 2005 (in millions):

|                                 |  |                                   |     |                                           |  |                                          |     |               |  |                            |     |  |  |   |      |   |  |   |     |  | 
|-------------------------------- |  | --------------------------------- | --- | ----------------------------------------- |  | ---------------------------------------- | --- | ------------- |  | -------------------------- | --- |  |  | - | ---- | - |  | - | --- |  | 
|                                 |  | Valuation and Qualifying Accounts |     |                                           |  |                                          |     |               | 
|Allowance
 for Doubtful Accounts |  | Balance at
 beginning of
 Period  |     | Additions
 charged to costs
 and expenses |  | Additions
 charged to other
 accounts(1) |     | Deductions(2) |  | Balance at
 end of
 period |    
|                                 |  |                                   |     |                                           |  |                                          |     |               |  |                            |    
|Year ended December 31,
 2007    |  | $                                 | 6.8 |                                           |  | $                                        | 0.4 |               |  | $                          |    |  |  | $ | (0.2 | ) |  | $ | 7.0 |  | 
|                                 |  |                                   |     |                                           |  |                                          |     |               |  |                            |     |  |  |   |      |   |  |   |     |  | 
|Year ended December 31,
 2006    |  | $                                 | 6.5 |                                           |  | $                                        | 0.3 |               |  | $                          | 0.3 |  |  | $ | (0.3 | ) |  | $ | 6.8 |  | 
|                                 |  |                                   |     |                                           |  |                                          |     |               |  |                            |     |  |  |   |      |   |  |   |     |  | 
|Year ended December 31,
 2005    |  | $                                 | 8.6 |                                           |  | $                                        | 0.2 |               |  | $                          |    |  |  | $ | (2.3 | ) |  | $ | 6.5 |  | 

|    |                                                                                                                                   
|--- | ----------------------------------------------------------------------------------------------------------------------------------
|(1) | Amount for 2006 represents
 the allowance recognized when we acquired Devco USA L.L.C. ($0.2) and
 Transload Services, LLC ($0.1).
|    |                                                                                                                                   
|(2) | Deductions represent the
 write-off of receivables.                                                                               

In
addition, the balances of Accrued other current liabilities in our
accompanying consolidated balance sheets include amounts related to customer
prepayments of approximately $6.5 million as of December 31, 2007 and $10.8
million as of December 31, 2006.

Inventories

Our
inventories of products consist of natural gas liquids, refined petroleum
products, natural gas, carbon dioxide and coal. We report these assets at the
lower of weighted-average cost or market. We report materials and supplies at
the lower of cost or market. As of December 31, 2007, we owed certain customers
a total of $8.3 million for the value of natural gas inventory stored in our
underground storage facilities, and we reported this amount within Accounts
PayableTrade in our accompanying consolidated balance sheet. As of December
31, 2006, the value of natural gas in our underground storage facilities under
the weighted-average cost method was $8.4 million, and we reported this amount
within Other current assets in our accompanying consolidated balance sheet.
We also maintain gas in our underground storage facilities on behalf of certain
third parties. We receive a fee from our storage service customers but do not
reflect the value of their gas stored in our facilities in our accompanying
consolidated balance sheets.

Property,
Plant and Equipment

Capitalization,
Depreciation and Depletion and Disposals

We
report property, plant and equipment at its acquisition cost. We expense costs
for maintenance and repairs in the period incurred. The cost of property, plant
and equipment sold or retired and the related depreciation are removed from our
balance sheet in the period of sale or disposition. For our pipeline system
assets, we generally charge the original cost of property sold or retired to
accumulated depreciation and amortization, net of salvage and cost of removal.
We do not include retirement gain or loss in income except in the case of
significant retirements or sales. Gains and losses on minor system sales,
excluding land, are recorded to the appropriate accumulated

125

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depreciation
reserve. Gains and losses for operating systems sales and land sales are booked
to income or expense accounts in accordance with regulatory accounting
guidelines.

We
compute depreciation using the straight-line method based on estimated economic
lives. Generally, we apply composite depreciation rates to functional groups of
property having similar economic characteristics. The rates range from 2.0% to
12.5%, excluding certain short-lived assets such as vehicles. Depreciation
estimates are based on various factors, including age (in the case of acquired
assets), manufacturing specifications, technological advances and historical
data concerning useful lives of similar assets. Uncertainties that impact these
estimates included changes in laws and regulations relating to restoration and
abandonment requirements, economic conditions, and supply and demand in the
area. When assets are put into service, we make estimates with respect to
useful lives (and salvage values where appropriate) that we believe are
reasonable. However, subsequent events could cause us to change our estimates,
thus impacting the future calculation of depreciation and amortization expense.
Historically, adjustments to useful lives have not had a material impact on our
aggregate depreciation levels from year to year.

Our
oil and gas producing activities are accounted for under the successful efforts
method of accounting. Under this method costs that are incurred to acquire
leasehold and subsequent development costs are capitalized. Costs that are
associated with the drilling of successful exploration wells are capitalized if
proved reserves are found. Costs associated with the drilling of exploratory
wells that do not find proved reserves, geological and geophysical costs, and
costs of certain non-producing leasehold costs are expensed as incurred. The
capitalized costs of our producing oil and gas properties are depreciated and
depleted by the units-of-production method. Other miscellaneous property, plant
and equipment are depreciated over the estimated useful lives of the asset.

A
gain on the sale of property, plant and equipment used in our oil and gas
producing activities or in our bulk and liquids terminal activities is
calculated as the difference between the cost of the asset disposed of, net of
depreciation, and the sales proceeds received. A gain on an asset disposal is
recognized in income in the period that the sale is closed. A loss on the sale
of property, plant and equipment is calculated as the difference between the
cost of the asset disposed of, net of depreciation, and the sales proceeds
received or the maket value if the asset is being held for sale. A loss is
recognized when the asset is sold or when the net cost of an asset held for
sale is greater than the market value of the asset.

In
addition, we engage in enhanced recovery techniques in which carbon dioxide is
injected into certain producing oil reservoirs. In some cases, the acquisition
cost of the carbon dioxide associated with enhanced recovery is capitalized as
part of our development costs when it is injected. The acquisition cost
associated with pressure maintenance operations for reservoir management is
expensed when it is injected. When carbon dioxide is recovered in conjunction
with oil production, it is extracted and re-injected, and all of the associated
costs are expensed as incurred. Proved developed reserves are used in computing
units of production rates for drilling and development costs, and total proved
reserves are used for depletion of leasehold costs. The units-of-production
rate is determined by field.

As
discussed in Inventories above, we maintain natural gas in underground
storage as part of our inventory. This component of our inventory represents
the portion of gas stored in an underground storage facility generally known as
working gas, and represents an estimate of the portion of gas in these
facilities available for routine injection and withdrawal to meet demand. In
addition to this working gas, underground gas storage reservoirs contain
injected gas which is not routinely cycled but, instead, serves the function of
maintaining the necessary pressure to allow efficient operation of the
facility. This gas, generally known as cushion gas, is divided into the
categories of recoverable cushion gas and unrecoverable cushion gas, based
on an engineering analysis of whether the gas can be economically removed from
the storage facility at any point during its life. The portion of the cushion
gas that is determined to be unrecoverable is considered to be a permanent part
of the facility itself (thus, part of our Property, Plant and Equipment, net
balance in our accompanying consolidated balance sheets), and this
unrecoverable portion is depreciated over the facilitys estimated useful life.
The portion of the cushion gas that is determined to be recoverable is also
considered a component of the facility but is not depreciated because it is
expected to ultimately be recovered and sold.

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Impairments

We
evaluate the impairment of our long-lived assets in accordance with Statement
of Financial Accounting Standards No. 144, Accounting for the Impairment or
Disposal of Long-Lived Assets. SFAS No. 144 requires that long-lived assets
that are to be disposed of by sale be measured at the lower of book value or
fair value less the cost to sell. We review for the impairment of long-lived
assets whenever events or changes in circumstances indicate that our carrying amount
of an asset may not be recoverable. We would recognize an impairment loss when
estimated future cash flows expected to result from our use of the asset and
its eventual disposition is less than its carrying amount.

We
evaluate our oil and gas producing properties for impairment of value on a
field-by-field basis or, in certain instances, by logical grouping of assets if
there is significant shared infrastructure, using undiscounted future cash
flows based on total proved and risk-adjusted probable and possible reserves.
Oil and gas producing properties deemed to be impaired are written down to
their fair value, as determined by discounted future cash flows based on total
proved and risk-adjusted probable and possible reserves or, if available,
comparable market values. Unproved oil and gas properties that are individually
significant are periodically assessed for impairment of value, and a loss is
recognized at the time of impairment.

Equity
Method of Accounting

We
account for investments greater than 20% in affiliates, which we do not
control, by the equity method of accounting. Under this method, an investment
is carried at our acquisition cost, plus our equity in undistributed earnings
or losses since acquisition, and less distributions received.

Excess
of Cost Over Fair Value

We
account for our business acquisitions and intangible assets in accordance with
the provisions of SFAS No. 141, Business Combinations, and SFAS No. 142,
Goodwill and Other Intangible Assets. Accounting standards require that
goodwill not be amortized, but instead should be tested, at least on an annual
basis, for impairment. Pursuant to this SFAS No. 142, goodwill and other
intangible assets with indefinite useful lives cannot be amortized until their
useful life becomes determinable. Instead, such assets must be tested for
impairment annually or on an interim basis if events or circumstances indicate
that the fair value of the asset has decreased below its carrying value. We
have selected an impairment measurement test date of January 1 of each year and
we have determined that our goodwill was not impaired as of January 1, 2008;
however, our consolidated income statement for the year ended December 31, 2007
included a goodwill impairment expense of $377.1 million, due to the inclusion
of Knights first quarter 2007 impairment of goodwill that resulted from a
determination of the fair values of Trans Mountain pipeline assets prior to our
acquisition of these assets on April 30, 2007. For more information on this
acquisition and this impairment expense, see Notes 3 and 8, respectively.

Our
total unamortized excess cost over fair value of net assets in consolidated
affiliates was $1,077.8 million as of December 31, 2007 and $1,421.0 million as
of December 31, 2006. Such amounts are reported as Goodwill on our
accompanying consolidated balance sheets. Our total unamortized excess cost
over underlying fair value of net assets accounted for under the equity method
was$138.2 million as of both
December 31, 2007 and December 31, 2006. Pursuant to SFAS No. 142, this amount,
referred to as equity method goodwill, should continue to be recognized in
accordance with Accounting Principles Board Opinion No. 18, The Equity Method
of Accounting for Investments in Common Stock. Accordingly, we included this
amount within Investments on our accompanying consolidated balance sheets.

In
almost all cases, the price we paid to acquire our share of the net assets of
our equity investees differed from the underlying book value of such net
assets. This differential consists of two pieces. First, an amount related to
the difference between the investees recognized net assets at book value and
at current fair values (representing the appreciated value in plant and other
net assets), and secondly, to any premium in excess of fair value (representing
equity method goodwill as described above) we paid to acquire the investment.
The first differential, representing the excess of the fair market value of our
investees plant and other net assets over its underlying book value at the
date of acquisition totaled $174.7 million and $177.1 million as of December
31, 2007 and 2006, respectively, and similar to our treatment of equity method
goodwill, we included these amounts within Investments on our

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accompanying
consolidated balance sheets. As of December 31, 2007, this excess investment
cost is being amortized over a weighted average life of approximately 30.9
years.

In
addition to our annual impairment test of goodwill, we periodically reevaluate
the amount at which we carry the excess of cost over fair value of net assets
accounted for under the equity method, as well as the amortization period for
such assets, to determine whether current events or circumstances warrant
adjustments to our carrying value and/or revised estimates of useful lives in
accordance with APB Opinion No. 18. The impairment test under APB No. 18
considers whether the fair value of the equity investment as a whole, not the
underlying net assets, has declined and whether that decline is other than
temporary. As of December 31, 2007, we believed no such impairment had occurred
and no reduction in estimated useful lives was warranted. For more information
on our investments, see Note 7.

Revenue
Recognition Policies

We
recognize revenues as services are rendered or goods are delivered and, if
applicable, title has passed. We generally sell natural gas under long-term
agreements, with periodic price adjustments. In some cases, we sell natural gas
under short-term agreements at prevailing market prices. In all cases, we
recognize natural gas sales revenues when the natural gas is sold to a
purchaser at a fixed or determinable price, delivery has occurred and title has
transferred, and collectibility of the revenue is reasonably assured. The
natural gas we market is primarily purchased gas produced by third parties, and
we market this gas to power generators, local distribution companies,
industrial end-users and national marketing companies. We recognize gas
gathering and marketing revenues in the month of delivery based on customer
nominations and generally, our natural gas marketing revenues are recorded
gross, not net of cost of gas sold.

We
provide various types of natural gas storage and transportation services to
customers. The natural gas remains the property of these customers at all
times. In many cases (generally described as firm service), the customer pays
a two-part rate that includes (i) a fixed fee reserving the right to transport
or store natural gas in our facilities and (ii) a per-unit rate for volumes
actually transported or injected into/withdrawn from storage. The fixed-fee
component of the overall rate is recognized as revenue in the period the
service is provided. The per-unit charge is recognized as revenue when the
volumes are delivered to the customers agreed upon delivery point, or when the
volumes are injected into/withdrawn from our storage facilities. In other cases
(generally described as interruptible service), there is no fixed fee
associated with the services because the customer accepts the possibility that
service may be interrupted at our discretion in order to serve customers who have
purchased firm service. In the case of interruptible service, revenue is
recognized in the same manner utilized for the per-unit rate for volumes
actually transported under firm service agreements. In addition to our firm
and interruptible transportation services, we also provide natural gas park
and loan service to assist customers in managing short-term gas surpluses or
deficits. Revenues are recognized based on the terms negotiated under these
contracts.

We
provide crude oil transportation services and refined petroleum products
transportation and storage services to customers. Revenues are recorded when
products are delivered and services have been provided, and adjusted according
to terms prescribed by the toll settlements with shippers and approved by
regulatory authorities.

We
recognize bulk terminal transfer service revenues based on volumes loaded and
unloaded. We recognize liquids terminal tank rental revenue ratably over the
contract period. We recognize liquids terminal throughput revenue based on
volumes received and volumes delivered. Liquids terminal minimum take-or-pay
revenue is recognized at the end of the contract year or contract term
depending on the terms of the contract. We recognize transmix processing revenues
based on volumes processed or sold, and if applicable, when title has passed.
We recognize energy-related product sales revenues based on delivered
quantities of product.

Revenues
from the sale of oil, natural gas liquids and natural gas production are
recorded using the entitlement method. Under the entitlement method, revenue is
recorded when title passes based on our net interest. We record our entitled
share of revenues based on entitled volumes and contracted sales prices. Since
there is a ready market for oil and gas production, we sell the majority of our
products soon after production at various locations, at which time title and
risk of loss pass to the buyer. As a result, we maintain a minimum amount of
product inventory in storage.

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Allowance
For Funds Used During Construction

Included
in the cost of our qualifying property, plant and equipment is an allowance for
funds used during construction or upgrade, often referred to as AFUDC. AFUDC
represents the estimated cost of capital, from borrowed funds, during the
construction period. Total AFUDC resulting from the capitalization of interest
expense in 2007, 2006 and 2005 was $31.4 million, $20.3 million and $9.8
million, respectively. Approximately $6.1 million and $2.2 million of AFUDC on
equity, related to our Trans Mountain pipeline system assets, was also
capitalized in the twelve months ended December 31, 2007 and 2006,
respectively.

Unit-Based
Compensation

We
account for common unit options granted under our common unit option plan
according to the provisions of SFAS No. 123R (revised 2004), Share-Based
Payment, which became effective for us January 1, 2006. However, we have not
granted common unit options or made any other share-based payment awards since
May 2000, and as of December 31, 2005, all outstanding options to purchase our
common units were fully vested. Therefore, the adoption of this Statement did
not have an effect on the accounting for these common unit options in our consolidated
financial statements, as we had reached the end of the requisite service period
for any compensation cost resulting from share-based payments made under our
common unit option plan.

Environmental
Matters

We
expense or capitalize, as appropriate, environmental expenditures that relate
to current operations. We expense expenditures that relate to an existing
condition caused by past operations, which do not contribute to current or
future revenue generation. We do not discount environmental liabilities to a
net present value, and we record environmental liabilities when environmental
assessments and/or remedial efforts are probable and we can reasonably estimate
the costs. Generally, our recording of these accruals coincides with our
completion of a feasibility study or our commitment to a formal plan of action.
We recognize receivables for anticipated associated insurance recoveries when
such recoveries are deemed to be probable.

We
routinely conduct reviews of potential environmental issues and claims that
could impact our assets or operations. These reviews assist us in identifying
environmental issues and estimating the costs and timing of remediation
efforts. We also routinely adjust our environmental liabilities to reflect
changes in previous estimates. In making environmental liability estimations,
we consider the material effect of environmental compliance, pending legal
actions against us, and potential third-party liability claims. Often, as the
remediation evaluation and effort progresses, additional information is
obtained, requiring revisions to estimated costs. These revisions are reflected
in our income in the period in which they are reasonably determinable. For more
information on our environmental disclosures, see Note 16.

Legal

We
are subject to litigation and regulatory proceedings as the result of our
business operations and transactions. We utilize both internal and external
counsel in evaluating our potential exposure to adverse outcomes from orders,
judgments or settlements. When we identify specific litigation that is expected
to continue for a significant period of time and require substantial
expenditures, we identify a range of possible costs expected to be required to litigate
the matter to a conclusion or reach an acceptable settlement, and we accrue for
such amounts. To the extent that actual outcomes differ from our estimates, or
additional facts and circumstances cause us to revise our estimates, our
earnings will be affected. In general, we expense legal costs as incurred and
all recorded legal liabilities are revised as better information becomes
available. For more information on our legal disclosures, see Note 16.

Pensions and Other
Post-retirement Benefits

We
account for pension and other post-retirement benefit plans according to the
provisions of SFAS No. 158, Employers Accounting for Defined Benefit Pension
and Other Postretirement Plans, an amendment of FASB Statement Nos. 87, 88, 106
and 132(R). This Statement requires us to fully recognize the overfunded or
underfunded status of our consolidating subsidiaries pension and
post-retirement benefit plans as either assets or

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liabilities on
our balance sheet. For more information on our pension and post-retirement
benefit disclosures, see Note 10.

Gas
Imbalances

We
value gas imbalances due to or due from interconnecting pipelines at the lower
of cost or market. Gas imbalances represent the difference between customer
nominations and actual gas receipts from, and gas deliveries to, our
interconnecting pipelines and shippers under various operational balancing and
shipper imbalance agreements. Natural gas imbalances are either settled in cash
or made up in-kind subject to the pipelines various tariff provisions.

Minority
Interest

Minority
interest, sometimes referred to as noncontrolling interest, represents the
outstanding ownership interests in our five operating limited partnerships and
their consolidated subsidiaries that are not owned by us. In our consolidated
income statements, the minority interest in the income (or loss) of a
consolidated subsidiary is shown as a deduction from (or an addition to) our
consolidated net income. In our consolidated balance sheets, minority interest
represents the noncontrolling ownership interest in our consolidated net assets
and is presented separately between liabilities and Partners Capital.

As
of December 31, 2007, minority interest consisted of the following:

| |   |                                                                                                                                                                                                           
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | the 1.0101% general partner
interest in
 each of our five operating partnerships;                                                                                                                         
| |   |                                                                                                                                                                                                           
| |  | the 0.5% special limited partner
interest
 in SFPP, L.P.;                                                                                                                                                 
| |   |                                                                                                                                                                                                           
| |  | the 50% interest in Globalplex
Partners, a
 Louisiana joint venture owned 50% and controlled by Kinder Morgan Bulk
 Terminals, Inc.;                                                                      
| |   |                                                                                                                                                                                                           
| |  | the 33 1/3% interest in
International
 Marine Terminals Partnership, a Louisiana partnership owned 66 2/3% and
 controlled by Kinder Morgan Operating L.P. C;                                           
| |   |                                                                                                                                                                                                           
| |  | the approximate 31% interest in
the Pecos
Carbon Dioxide Company, a Texas general partnership owned approximately 69% and controlled by Kinder
Morgan CO2 Company, L.P. and its consolidated subsidiaries;
| |   |                                                                                                                                                                                                           
| |  | the 1% interest in River
Terminals
 Properties, L.P., a Tennessee partnership owned 99% and controlled by Kinder
 Morgan River Terminals LLC; and                                                         
| |   |                                                                                                                                                                                                           
| |  | the 30% interest in Guilford
County
 Terminal Company, LLC, a limited liability company owned 70% and controlled
 by Kinder Morgan Southeast Terminals LLC.                                               
| |   |                                                                                                                                                                                                           

Income
Taxes

We
are not a taxable entity for federal income tax purposes. As such, we do not
directly pay federal income tax. Our taxable income or loss, which may vary
substantially from the net income or net loss we report in our consolidated
statement of income, is includable in the federal income tax returns of each
partner. The aggregate difference in the basis of our net assets for financial
and tax reporting purposes cannot be readily determined as we do not have
access to information about each partners tax attributes in us.

Some
of our corporate subsidiaries and corporations in which we have an equity
investment do pay U.S. federal, state, and foreign income taxes. Deferred
income tax assets and liabilities for certain operations conducted through
corporations are recognized for temporary differences between the assets and
liabilities for financial reporting and tax purposes. Changes in tax
legislation are included in the relevant computations in the period in which
such changes are effective. Deferred tax assets are reduced by a valuation
allowance for the amount of any tax benefit not expected to be realized.

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Foreign
Currency Transactions and Translation

We
account for foreign currency transactions and the foreign currency translation
of our consolidating foreign subsidiaries in accordance with the provisions of
SFAS No. 52, Foreign Currency Translation. Foreign currency transactions are
those transactions whose terms are denominated in a currency other than the
currency of the primary economic environment in which our foreign subsidiary
operates, also referred to as its functional currency. Transaction gains or
losses result from a change in exchange rates between (i) the functional
currency, for example the Canadian dollar for a Canadian subsidiary; and (ii)
the currency in which a foreign currency transaction is denominated, for
example the U.S. dollar for a Canadian subsidiary.

We
translate the assets and liabilities of each of our consolidating foreign
subsidiaries to U.S. dollars at year-end exchange rates. Income and expense
items are translated at weighted-average rates of exchange prevailing during
the year and stockholders equity accounts are translated by using historical
exchange rates. Translation adjustments result from translating all assets and
liabilities at current year-end rates, while stockholders equity is translated
by using historical and weighted-average rates. The cumulative translation
adjustments balance is reported as a component of accumulated other
comprehensive income/(loss) within Partners Capital on our accompanying
consolidated balance sheet.

Comprehensive
Income

Statement
of Financial Accounting Standards No. 130, Accounting for Comprehensive Income,
requires that enterprises report a total for comprehensive income. The
difference between our net income and our comprehensive income resulted from
(i) unrealized gains or losses on derivatives utilized for hedging our exposure
to fluctuating expected future cash flows produced by price or interest rate
risk; (ii) foreign currency translation adjustments; and (iii) unrealized
periodic benefit costs from minimum pension liability adjustments and the
reclassification of post-retirement benefit and pension plan actuarial
gains/losses and prior service costs/credits to net income. For more
information on our risk management activities, see Note 14.

Cumulative
revenues, expenses, gains and losses that under generally accepted accounting
principals are included within our comprehensive income but excluded from our
earnings are reported as accumulated other comprehensive income/(loss) within
Partners Capital in our consolidated balance sheets. The following table
summarizes changes in the amount of our Accumulated other comprehensive loss
in our accompanying consolidated balance sheets for each of the two years ended
December 31, 2006 and 2007 (in millions):

|                  |  |                                                                 |   |                                             |   |                                                      |  |                                                        |       |   |  |  |   |      |   |  |  |   |          |   | 
|----------------- |  | --------------------------------------------------------------- | - | ------------------------------------------- | - | ---------------------------------------------------- |  | ------------------------------------------------------ | ----- | - |  |  | - | ---- | - |  |  | - | -------- | - | 
|                  |  | Net unrealized
 gains/(losses)
 on cash flow
 hedge derivatives |   | Foreign
 currency
 translation
 adjustments |   | Pension and
 Other
 Post-retirement
 liability adjs. |  | Total
 Accumulated other
 comprehensive
 income/(loss) |      
|                  |  |                                                                 |   |                                             |   |                                                      |  |                                                        |      
|December 31, 2005 |  |                                                                 | $ | (1,079.3                                    | ) |                                                      |  | $                                                      | (0.4  | ) |  |  | $ |     |   |  |  | $ | (1,079.7 | ) | 
|Change for period |  |                                                                 |   | 240.6                                       |   |                                                      |  |                                                        | (19.6 | ) |  |  |   | (7.4 | ) |  |  |   | 213.6    |   | 
|                  |  |                                                                 |   |                                             |   |                                                      |  |                                                        |       |   |  |  |   |      |   |  |  |   |          |   | 
|December 31, 2006 |  |                                                                 |   | (838.7                                      | ) |                                                      |  |                                                        | (20.0 | ) |  |  |   | (7.4 | ) |  |  |   | (866.1   | ) | 
|Change for period |  |                                                                 |   | (541.0                                      | ) |                                                      |  |                                                        | 132.5 |   |  |  |   | (2.0 | ) |  |  |   | (410.5   | ) | 
|                  |  |                                                                 |   |                                             |   |                                                      |  |                                                        |       |   |  |  |   |      |   |  |  |   |          |   | 
|December 31, 2007 |  |                                                                 | $ | (1,379.7                                    | ) |                                                      |  | $                                                      | 112.5 |   |  |  | $ | (9.4 | ) |  |  | $ | (1,276.6 | ) | 
|                  |  |                                                                 |   |                                             |   |                                                      |  |                                                        |       |   |  |  |   |      |   |  |  |   |          |   | 

Net
Income Per Unit

We
compute Basic 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. Diluted Limited Partners Net Income per Unit
reflects the maximum potential dilution that could occur if units whose
issuance depends on the market price of the units at a future date were
considered outstanding, or if, by application of the treasury stock method,
options to issue units were exercised, both of which would result in the
issuance of additional units that would then share in our net income.

Emerging
Issues Task Force Issue No. 03-6, or EITF 03-6, Participating Securities and
the Two-Class Method Under FASB Statement No 128 addresses the computation of
earnings per share by entities that have issued

131

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securities
other than common stock that contractually entitle the holder to participate in
dividends and earnings of the entity when, and if, it declares dividends on its
securities. For partnerships, under the two-class method, earnings per unit is
calculated as if all of the earnings for the period were distributed regardless
of whether a general partner has discretion over the amount of distribution to
be made for any particular period. EITF 03-6 does not impact our overall net
income or other financial results because we do not have undistributed earnings
in any period presented in this report.

Asset
Retirement Obligations

We
account for asset retirement obligations pursuant to SFAS No. 143, Accounting
for Asset Retirement Obligations. For more information on our asset retirement
obligations, see Note 4.

Risk
Management Activities

We
utilize energy commodity derivative contracts for the purpose of mitigating our
risk resulting from fluctuations in the market price of natural gas, natural
gas liquids and crude oil. In addition, we enter into interest rate swap
agreements for the purpose of hedging the interest rate risk associated with
our debt obligations.

Our
derivative contracts are accounted for under SFAS No. 133, Accounting for
Derivative Instruments and Hedging Activities, as amended by SFAS No. 137,
Accounting for Derivative Instruments and Hedging Activities  Deferral of the
Effective Date of FASB Statement No.133 and No. 138, Accounting for Certain
Derivative Instruments and Certain Hedging Activities.SFAS No. 133 established accounting and
reporting standards requiring that every derivative contract (including certain
derivative contracts embedded in other contracts) be recorded in the balance
sheet as either an asset or liability measured at its fair value. SFAS No. 133
requires that changes in the derivative contracts fair value be recognized
currently in earnings unless specific hedge accounting criteria are met. If a
derivative contract meets those criteria, SFAS No. 133 allows a derivative
contracts gains and losses to offset related results on the hedged item in the
income statement, and requires that a company formally designate a derivative
contract as a hedge and document and assess the effectiveness of derivative
contracts associated with transactions that receive hedge accounting.

Furthermore,
if the derivative transaction qualifies for and is designated as a normal
purchase and sale, it is exempted from the fair value accounting requirements
of SFAS No. 133 and is accounted for using traditional accrual accounting. Our
derivative contracts that hedge our commodity price risks involve our normal
business activities, which include the sale of natural gas, natural gas liquids
and crude oil, and these derivative contracts have been designated as cash flow
hedges as defined by SFAS No. 133. SFAS No. 133 designates derivative contracts
that hedge exposure to variable cash flows of forecasted transactions as cash
flow hedges and the effective portion of the derivative contracts gain or loss
is initially reported as a component of other comprehensive income (outside
earnings) and subsequently reclassified into earnings when the forecasted
transaction affects earnings. The ineffective portion of the gain or loss is
reported in earnings immediately. See Note 14 for more information on our risk
management activities.

Accounting
for Regulatory Activities

Our
regulated utility operations are accounted for in accordance with the
provisions of SFAS No. 71, Accounting for the Effects of Certain Types of
Regulation, which prescribes the circumstances in which the application of
generally accepted accounting principles is affected by the economic effects of
regulation. Regulatory assets and liabilities represent probable future
revenues or expenses associated with certain charges and credits that will be
recovered from or refunded to customers through the ratemaking process.

The
following regulatory assets and liabilities are reflected within Deferred
charges and other assets and Other long-term liabilities and deferred
credits, respectively, in our accompanying consolidated balance sheets as of
December 31, 2007 and December 31, 2006 (in millions):

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|                             |  |                    |   |      |  |  | 
|---------------------------- |  | ------------------ | - | ---- |  |  | 
|                             |  | As of December 31, |  
|                             |  |                    |  
|                             |  | 2007               |   | 2006 | 
|                             |  |                    |   |      | 
|Regulated Assets:            |  |                    |   |      | 
|Employee
benefit costs       |  |                    | $ | 0.6  |  |  | 
|Fuel
Tracker                 |  |                    |   | 2.4  |  |  | 
|Deferred
regulatory expenses |  |                    |   | 3.4  |  |  | 
|                             |  |                    |   |      |  |  | 
|Total
regulatory assets      |  |                    |   | 6.4  |  |  | 
|                             |  |                    |   |      |  |  | 
|Regulated Liabilities:       |  |                    |   |      |  |  | 
|Deferred income
taxes        |  |                    |   |     |  |  | 
|                             |  |                    |   |      |  |  | 
|Total
regulatory liabilities |  |                    |   |     |  |  | 
|                            
|                             |  |                    |   |      |  |  | 
|Net regulatory
assets        |  |                    | $ | 6.4  |  |  | 
|                             |  |                    |   |      |  |  | 

As
of December 31, 2007, all of our regulatory assets and regulatory liabilities
were being recovered from or refunded to customers through rates over periods
ranging from one to five years.

3.
Acquisitions, Joint Ventures and Divestitures

Acquisitions
and Joint Ventures Involving Unrelated Entities

During
2007, 2006 and 2005, we completed the following acquisitions, and except for
our acquisition of the Trans Mountain pipeline system (discussed below), these
acquisitions were accounted for as business combinations according to the
provisions of Statement of Financial Accounting Standards No. 141, Business
Combinations. SFAS No. 141 requires business combinations involving unrelated
entities to be accounted for using the purchase method of accounting, which
establishes a new basis of accounting for the purchased assets and
liabilitiesthe acquirer records all the acquired assets and assumed
liabilities at their estimated fair market values (not the acquired entitys
book values) as of the acquisition date.

The
preliminary allocation of these assets (and any liabilities assumed) may be
adjusted to reflect the final determined amounts, and although the time that is
required to identify and measure the fair value of the assets acquired and the
liabilities assumed in a business combination will vary with circumstances,
generally our allocation period ends when we no longer are waiting for
information that is known to be available or obtainable. The results of
operations from these acquisitions accounted for as business combinations are
included in our consolidated financial statements from the acquisition date.

|     |  |        |  |                                            |  |                              |   |                 |  |                              |  |                            |     |          |  |                    |   |       |  |  |  |   |       |  |  |  |   |      |  |  |  |   |   |  | 
|---- |  | ------ |  | ------------------------------------------ |  | ---------------------------- | - | --------------- |  | ---------------------------- |  | -------------------------- | --- | -------- |  | ------------------ | - | ----- |  |  |  | - | ----- |  |  |  | - | ---- |  |  |  | - | - |  | 
|     |  |        |  |                                            |  | Allocation of Purchase Price |  
|     |  |        |  |                                            |  |                              |  
|     |  |        |  |                                            |  | (in millions)                |  
|     |  |        |  |                                            |  |                              |  
|Ref. |  | Date   |  | Acquisition                                |  | Purchase
 Price              |   | Current
 Assets |  | Property
 Plant &
 Equipment |  | Deferred
 Charges
 & Other |     | Goodwill |  | Minority
 Interest |  
|     |  |        |  |                                            |  |                              |   |                 |  |                              |  |                            |     |          |  |                    |  
|(1)  |  | 1/05   |  | Claytonville Oil Field Unit                |  |                              | $ | 6.5             |  |                              |  | $                          |    |          |  |                    | $ | 6.5   |  |  |  | $ |      |  |  |  | $ |     |  |  |  | $ |  |  | 
|(2)  |  | 4/05   |  | Texas Petcoke Terminal
 Region             |  |                              |   | 247.2           |  |                              |  |                            |    |          |  |                    |   | 72.5  |  |  |  |   | 161.4 |  |  |  |   | 13.3 |  |  |  |   |  |  | 
|(3)  |  | 7/05   |  | Terminal Assets                            |  |                              |   | 36.2            |  |                              |  |                            | 0.5 |          |  |                    |   | 35.7  |  |  |  |   |      |  |  |  |   |     |  |  |  |   |  |  | 
|(4)  |  | 7/05   |  | General Stevedores, L.P.                   |  |                              |   | 10.4            |  |                              |  |                            | 0.6 |          |  |                    |   | 5.2   |  |  |  |   | 0.2   |  |  |  |   | 4.4  |  |  |  |   |  |  | 
|(5)  |  | 8/05   |  | North Dayton Natural Gas
 Storage Facility |  |                              |   | 109.4           |  |                              |  |                            |    |          |  |                    |   | 71.7  |  |  |  |   | 11.7  |  |  |  |   | 26.0 |  |  |  |   |  |  | 
|(6)  |  | 8-9/05 |  | Terminal Assets                            |  |                              |   | 4.3             |  |                              |  |                            | 0.4 |          |  |                    |   | 3.9   |  |  |  |   |      |  |  |  |   |     |  |  |  |   |  |  | 
|(7)  |  | 11/05  |  | Allied Terminal Assets                     |  |                              |   | 13.3            |  |                              |  |                            | 0.2 |          |  |                    |   | 12.6  |  |  |  |   | 0.5   |  |  |  |   |     |  |  |  |   |  |  | 
|(8)  |  | 2/06   |  | Entrega Gas Pipeline LLC                   |  |                              |   | 244.6           |  |                              |  |                            |    |          |  |                    |   | 244.6 |  |  |  |   |      |  |  |  |   |     |  |  |  |   |  |  | 
|(9)  |  | 4/06   |  | Oil and Gas Properties                     |  |                              |   | 63.6            |  |                              |  |                            | 0.1 |          |  |                    |   | 63.5  |  |  |  |   |      |  |  |  |   |     |  |  |  |   |  |  | 
|(10) |  | 4/06   |  | Terminal Assets                            |  |                              |   | 61.9            |  |                              |  |                            | 0.5 |          |  |                    |   | 43.6  |  |  |  |   |      |  |  |  |   | 17.8 |  |  |  |   |  |  | 
|(11) |  | 11/06  |  | Transload Services, LLC                    |  |                              |   | 16.6            |  |                              |  |                            | 1.6 |          |  |                    |   | 6.6   |  |  |  |   |      |  |  |  |   | 8.4  |  |  |  |   |  |  | 
|(12) |  | 12/06  |  | Devco USA L.L.C.                           |  |                              |   | 7.3             |  |                              |  |                            | 0.8 |          |  |                    |   |      |  |  |  |   | 6.5   |  |  |  |   |     |  |  |  |   |  |  | 
|(13) |  | 12/06  |  | Roanoke, Virginia Products
 Terminal       |  |                              |   | 6.4             |  |                              |  |                            |    |          |  |                    |   | 6.4   |  |  |  |   |      |  |  |  |   |     |  |  |  |   |  |  | 
|(14) |  | 1/07   |  | Interest in Cochin Pipeline                |  |                              |   | 47.8            |  |                              |  |                            |    |          |  |                    |   | 47.8  |  |  |  |   |      |  |  |  |   |     |  |  |  |   |  |  | 
|(15) |  | 5/07   |  | Vancouver Wharves Terminal.                |  |                              |   | 57.2            |  |                              |  |                            | 6.5 |          |  |                    |   | 50.7  |  |  |  |   |      |  |  |  |   |     |  |  |  |   |  |  | 
|(16) |  | 9/07   |  | Marine Terminals, Inc.
 Assets             |  |                              |   | 101.5           |  |                              |  |                            | 0.2 |          |  |                    |   | 60.8  |  |  |  |   | 40.5  |  |  |  |   |     |  |  |  |   |  |  | 
|     |  |        |  |                                            |  |                              |   |                 |  |                              |  |                            |     |          |  |                    |   |       |  |  |  |   |       |  |  |  |   |      |  |  |  |   |   |  | 

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(1)
Claytonville Oil Field Unit

Effective
January 31, 2005, we acquired an approximate 64.5% gross working interest in
the Claytonville oil field unit located in Fisher County, Texas from Aethon I
L.P. The field is located nearly 30 miles east of the SACROC unit in the
Permian Basin of West Texas. Our purchase price was approximately $6.5 million,
consisting of $6.2 million in cash and the assumption of $0.3 million of
liabilities. Following our acquisition, we became the operator of the field,
which at the time of acquisition was producing approximately 200 barrels of oil
per day. The acquisition of this ownership interest complemented our existing
carbon dioxide assets in the Permian Basin and we include the acquired
operations as part of our CO2 business segment.

(2)
Texas Petcoke Terminal Region

Effective
April 29, 2005, we acquired seven bulk terminal operations from Trans-Global
Solutions, Inc. for an aggregate consideration of approximately $247.2 million,
consisting of $186.0 million in cash, $46.2 million in common units, and an
obligation to pay an additional $15 million on April 29, 2007, two years after
the closing. We settled the $15 million liability by issuing additional common
units. All of the acquired assets are located in the state of Texas, and
include facilities at the Port of Houston, the Port of Beaumont and the TGS
Deepwater Terminal located on the Houston Ship Channel. We combined the
acquired operations into a new terminal region called the Texas Petcoke region,
as certain of the terminals have contracts in place to provide petroleum coke
handling services for major Texas oil refineries. The acquisition complemented
our existing Gulf Coast terminal facilities and expanded our pre-existing petroleum
coke handling operations. The acquired operations are included as part of our
Terminals business segment.

Our
allocation of the purchase price to assets acquired and liabilities assumed was
based on an appraisal of fair market values, which was completed in the fourth
quarter of 2005. A total of $13.3 million of goodwill was assigned to our
Terminals business segment and the entire amount is expected to be deductible
for tax purposes. We believe this acquisition resulted in the recognition of goodwill
primarily due to the fact that certain advantageous factors and conditions
existed that contributed to our acquisition price exceeding the fair value of
acquired identifiable net assets and liabilities in the aggregate, these
factors represented goodwill. The $161.4 million of deferred charges and other
assets in the table above represents the fair value of intangible customer
relationships, which encompass both the contractual life of customer contracts
plus any future customer relationship value beyond the contract life. In
connection with the transaction, Trans-Global Solutions, Inc. agreed to
indemnify Kinder Morgan G.P., Inc. for any losses relating to our failure to
repay $50.9 million of indebtedness incurred to fund the acquisition, and we agreed
to indemnify Trans-Global Solutions, Inc. for any taxes of Trans-Global
Solutions, Inc. that may arise from the sale of any acquired assets. We have no
current intention to sell any of the assets acquired in this transaction.

(3)
July 2005 Terminal Assets

In
July 2005, we acquired three terminal facilities in separate transactions for
an aggregate consideration of approximately $36.2 million in cash. The largest
of the transactions was the purchase of a refined petroleum products terminal
in New York Harbor from ExxonMobil Oil Corporation. The second acquisition
involved a dry-bulk river terminal located in the state of Kentucky, and the
third involved a liquids/dry-bulk facility located in Blytheville, Arkansas.
The operations of all three facilities are included in our Terminals business
segment.

The
New York Harbor terminal, located on Staten Island and referred to as the
Kinder Morgan Staten Island terminal, complements our existing Northeast
liquids terminal facilities located in Carteret and Perth Amboy, New Jersey. At
the time of acquisition, the terminal had storage capacity of 2.3 million
barrels for gasoline, diesel and fuel oil, and we expected to bring several
idle tanks back into service that would add another 550,000 barrels of
capacity. As part of the transaction, ExxonMobil entered into a long-term
storage capacity agreement with us and has continued to utilize a portion of
the terminal. Since our acquisition, we have invested approximately $25 million
in terminal improvements, including funds used to rebuild a ship berth with the
ability to accommodate tanker vessels. All expansion projects should be
complete by the end of the first quarter of 2008.

The
dry-bulk terminal, located along the Ohio River in Hawesville, Kentucky,
primarily handles wood chips and finished paper products. The acquisition
complemented our existing terminal assets located in the Ohio River

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Valley and further expanded our wood-chip handling
businesses. As part of the transaction, we assumed a long-term handling
agreement with Weyerhauser Company, an international forest products company.

The
assets acquired at the liquids/dry-bulk facility in Blytheville, Arkansas
consisted of storage and supporting infrastructure for 40,000 tons of anhydrous
ammonia, 9,500 tons of urea ammonium nitrate solutions and 40,000 tons of urea.
As part of the transaction, we have entered into a long-term agreement to
sublease all of the existing anhydrous ammonia and urea ammonium nitrate terminal
assets to Terra Nitrogen Company, L.P. The terminal is one of only two
facilities in the United States that can handle imported fertilizer and provide
shipment west on railcars, and the acquisition of the facility positioned us to
take advantage of the increase in fertilizer imports that has resulted from the
recent decrease in domestic production.

(4)
General Stevedores, L.P.

Effective
July 31, 2005, we acquired all of the partnership interests in General
Stevedores, L.P. for an aggregate consideration of approximately $10.4 million,
consisting of $2.0 million in cash, $3.4 million in common units, and $5.0
million in assumed liabilities, including debt of $3.0 million. In August 2005,
we paid the $3.0 million outstanding debt balance.

General
Stevedores, L.P. owns, operates and leases barge unloading facilities located
along the Houston, Texas ship channel. Its operations primarily consist of
receiving, storing and transferring semi-finished steel products, including coils,
pipe and billets. The acquisition complemented and further expanded our
existing Texas Gulf Coast terminal facilities, and its operations are included
as part of our Terminals business segment. A total of $4.4 million of goodwill
was assigned to our Terminals business segment, and the entire amount is
expected to be deductible for tax purposes. We believe this acquisition
resulted in the recognition of goodwill primarily due to the fact that certain
advantageous factors and conditions existed that contributed to our acquisition
price exceeding the fair value of acquired identifiable net assets and
liabilities in the aggregate, these factors represented goodwill.

(5)
North Dayton Natural Gas Storage Facility

Effective
August 1, 2005, we acquired a natural gas storage facility in Liberty County,
Texas, from Texas Genco LLC for an aggregate consideration of approximately
$109.4 million, consisting of $52.9 million in cash and $56.5 million in
assumed debt. The facility, referred to as our North Dayton storage facility,
has approximately 6.3 billion cubic feet of total capacity, consisting of 4.2
billion cubic feet of working capacity and 2.1 billion cubic feet of pad
(cushion) gas. The acquisition complemented our existing Texas intrastate
natural gas pipeline group assets and positioned us to pursue expansions at the
facility that will provide or offer needed services to utilities, the growing
liquefied natural gas industry along the Texas Gulf Coast, and other natural
gas storage users. Additionally, as part of the transaction, we entered into a
long-term storage capacity and transportation agreement with NRG, one of the
largest wholesale electric power generating companies in the United States,
with over 13,000 megawatts of generation capacity. The agreement covers storage
services for approximately 2.0 billion cubic feet of natural gas capacity and
expires on March 1, 2017. The North Dayton storage facilitys operations are
included in our Natural Gas Pipelines business segment.

Our
allocation of the purchase price to assets acquired and liabilities assumed was
based on an appraisal of fair market values, which was completed in the fourth
quarter of 2005. A total of $26.0 million of goodwill was assigned to our
Natural Gas Pipelines business segment and the entire amount is expected to be
deductible for tax purposes. We believe our acquisition of the North Dayton
natural gas storage facility resulted in the recognition of goodwill primarily
due to the fact that the favorable location and the favorable association with
our pre-existing assets contributed to our acquisition price exceeding the fair
value of acquired identifiable net assets and liabilities in the aggregate,
these factors represented goodwill. The $11.7 million of deferred charges and
other assets in the table above represents the fair value of the intangible
long-term natural gas storage capacity and transportation agreement.

(6)
August and September 2005 Terminal Assets

In
August and September 2005, we acquired certain terminal facilities and assets,
including both real and personal property, in two separate transactions for an
aggregate consideration of approximately $4.3 million in cash.

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In August 2005, we spent $1.9 million to acquire the
Kinder Morgan Blackhawk terminal from White Material Handling, Inc., and in
September 2005, we spent $2.4 million to acquire a repair shop and related
assets from Trans-Global Solutions, Inc.

The
Kinder Morgan Blackhawk terminal consists of approximately 46 acres of land,
storage buildings, and related equipment located in Black Hawk County, Iowa.
The terminal primarily stores and transfers fertilizer and salt and further
expanded our Midwest region bulk terminal operations. The acquisition of the
repair shop, located in Jefferson County, Texas, near Beaumont, consists of
real and personal property, including parts inventory. The acquisition
facilitated and expanded the earlier acquisition of our Texas Petcoke terminals
from Trans-Global Solutions in April 2005. The operations of both acquisitions
are included in our Terminals business segment.

(7)
Allied Terminal Assets

Effective
November 4, 2005, we acquired certain terminal assets from Allied Terminals,
Inc. for an aggregate consideration of approximately $13.3 million, consisting
of $12.1 million in cash and $1.2 million in assumed liabilities. The assets
primarily consisted of storage tanks, loading docks, truck racks, land and
other equipment and personal property located adjacent to our Shipyard River
bulk terminal in Charleston, South Carolina. The acquisition complemented an
ongoing capital expansion project at our Shipyard River terminal that together,
will add infrastructure in order to increase
the terminals ability to handle increasing supplies of imported coal. The
acquired assets are counted as an external addition to our Shipyard River
terminal and are included as part of our Terminals business segment.

(8) Entrega Gas Pipeline LLC

Effective
February 23, 2006, Rockies Express Pipeline LLC acquired Entrega Gas Pipeline
LLC from EnCana Corporation for $244.6 million in cash. West2East Pipeline LLC
is a limited liability company and is the sole owner of Rockies Express
Pipeline LLC. We contributed 66 2/3% of the consideration for this purchase,
which corresponded to our percentage ownership of West2East Pipeline LLC at
that time. At the time of acquisition, Sempra Energy held the remaining 33 1/3%
ownership interest and contributed this same proportional amount of the total
consideration.

On
the acquisition date, Entrega Gas Pipeline LLC owned the Entrega Pipeline, an
interstate natural gas pipeline that, when fully constructed, consisted of two
segments: (i) a 136-mile, 36-inch diameter pipeline that extends from the
Meeker Hub in Rio Blanco County, Colorado to the Wamsutter Hub in Sweetwater
County, Wyoming and (ii) a 191-mile, 42-inch diameter pipeline that extends
from the Wamsutter Hub to the Cheyenne Hub in Weld County, Colorado. In the
first quarter of 2006, EnCana Corporation completed construction of the
pipeline segment that extends from the Meeker Hub to the Wamsutter Hub, and
interim service began on that portion of the pipeline on February 24, 2006.
Under the terms of the purchase and sale agreement, Rockies Express Pipeline
LLC constructed the segment that extends from the Wamsutter Hub to the Cheyenne
Hub. Construction on this pipeline segment began in the second quarter of 2006,
and both pipeline segments were placed into service on February 14, 2007. The
acquired assets are included in our Natural Gas Pipelines business segment.

In
April 2006, Rockies Express Pipeline LLC merged with and into Entrega Gas
Pipeline LLC, and the surviving entity was renamed Rockies Express Pipeline
LLC. Going forward, the entire pipeline system (including lines currently being
developed by Rockies Express Pipeline LLC) will be known as the Rockies Express
Pipeline. The combined 1,679-mile pipeline system will be one of the largest natural
gas pipelines ever constructed in North America. The approximately $4.9 billion
project will have the capability to transport 1.8 billion cubic feet per day of
natural gas, and binding firm commitments have been secured for all of the
pipeline capacity.

On
June 30, 2006, ConocoPhillips exercised its option to acquire a 25% ownership
interest in West2East Pipeline LLC. On that date, a 24% ownership interest was
transferred to ConocoPhillips, and an additional 1% interest will be
transferred once construction of the entire project is completed. Through our
subsidiary Kinder Morgan W2E Pipeline LLC, we will continue to operate the
project but our ownership interest decreased to 51% of the equity in the
project (down from 66 2/3%). Sempras ownership interest in West2East Pipeline
LLC decreased to 25% (down from 33 1/3%). When construction of the entire
project is completed, our ownership interest will be reduced to 50% at which
time the capital accounts of West2East Pipeline LLC will be trued up to reflect
our 50%

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economics in the project. We do not anticipate any
additional changes in the ownership structure of the Rockies Express Pipeline
project.

West2East
Pipeline LLC qualifies as a variable interest entity as defined by Financial Accounting
Standards Board Interpretation No. 46 (Revised December 2003) (FIN 46R), Consolidation
of Variable Interest Entities-an interpretation of ARB No. 51, due to the
fact that the total equity at risk is not sufficient to permit the entity to
finance its activities without additional subordinated financial support
provided by any parties, including equity holders. Furthermore, following
ConocoPhillips acquisition of its ownership interest in West2East Pipeline LLC
on June 30, 2006, we receive 50% of the economics of the Rockies Express
project on an ongoing basis, and thus, effective June 30, 2006, we were no
longer considered the primary beneficiary of this entity as defined by FIN 46R.
Accordingly, on that date, we made the change in accounting for our investment
in West2East Pipeline LLC from full consolidation to the equity method
following the decrease in our ownership percentage.

Under
the equity method, we record the costs of our investment within the Investments
line on our consolidated balance sheet and as changes in the net assets of
West2East Pipeline LLC occur (for example, earnings and dividends), we
recognize our proportional share of that change in the Investment account. We
also record our proportional share of any accumulated other comprehensive
income or loss within the Accumulated other comprehensive loss line on our
consolidated balance sheet.

In
addition, we have guaranteed our proportionate share of West2East Pipeline LLCs
debt borrowings under a $2 billion credit facility entered into by Rockies
Express Pipeline LLC. For more information on our contingent debt, see Note 9.

(9)
April 2006 Oil and Gas Properties

On
April 5, 2006, Kinder Morgan Production Company L.P. purchased various oil and
gas properties from Journey Acquisition  I, L.P. and Journey 2000, L.P. for an
aggregate consideration of approximately $63.6 million, consisting of $60.0
million in cash and $3.6 million in assumed liabilities. The acquisition was
effective March 1, 2006. However, we divested certain acquired properties that
are not considered candidates for carbon dioxide enhanced oil recovery, thus
reducing our total investment. We received proceeds of approximately $27.1
million from the sale of these properties.

The
properties are primarily located in the Permian Basin area of West Texas,
produce approximately 400 barrels of oil equivalent per day, and
include some fields with potential for enhanced oil recovery development near
our current carbon dioxide operations. The acquired operations are included as
part of our CO2 business segment.

(10)
April 2006 Terminal Assets

In
April 2006, we acquired terminal assets and operations from A&L Trucking,
L.P. and U.S. Development Group in three separate transactions for an aggregate
consideration of approximately $61.9 million, consisting of $61.6 million in
cash and $0.3 million in assumed liabilities.

The
first transaction included the acquisition of equipment and infrastructure on
the Houston Ship Channel that loads and stores steel products. The acquired
assets complement our nearby bulk terminal facility purchased from General
Stevedores, L.P. in July 2005. The second acquisition included the purchase of
a rail terminal at the Port of Houston that handles both bulk and liquids
products. The rail terminal complements our existing Texas petroleum coke
terminal operations and maximizes the value of our existing deepwater terminal
by providing customers with both rail and vessel transportation options for
bulk products. Thirdly, we acquired the entire membership interest of Lomita
Rail Terminal LLC, a limited liability company that owns a high-volume rail
ethanol terminal in Carson, California. The terminal serves approximately 80%
of the Southern California demand for reformulated fuel blend ethanol with
expandable offloading/distribution capacity, and the acquisition expanded our
existing rail transloading operations. All of the acquired assets are included
in our Terminals business segment. A total of $17.8 million of goodwill was
assigned to our Terminals business segment and the entire amount is expected to
be deductible for tax purposes.

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(11) Transload Services, LLC

Effective
November 20, 2006, we acquired all of the membership interests of Transload
Services, LLC from Lanigan Holdings, LLC for an aggregate consideration of
approximately $16.6 million, consisting of $15.8 million in cash and $0.8
million of assumed liabilities. Transload Services, LLC is a leading provider
of innovative, high quality material handling and steel processing services,
operating 14 steel-related terminal facilities located in the Chicago
metropolitan area and various cities in the United States. Its operations include
transloading services, steel fabricating and processing, warehousing and
distribution, and project staging. Specializing in steel processing and
handling, Transload Services can inventory product, schedule shipments and
provide customers cost-effective modes of transportation. The combined
operations include over 92 acres of outside storage and 445,000 square feet of
covered storage that offers customers environmentally controlled warehouses
with indoor rail and truck loading facilities for handling temperature and
humidity sensitive products. The acquired assets are included in our Terminals
business segment, and the acquisition further expanded and diversified our
existing terminals materials services (rail transloading) operations.

A
total of $8.4 million of goodwill was assigned to our Terminals business
segment, and the entire amount is expected to be deductible for tax purposes.
We believe this acquisition resulted in the recognition of goodwill primarily
due to the fact that it establishes a business presence in several key markets,
taking advantage of the non-residential and highway construction demand for
steel that contributed to our acquisition price exceeding the fair value of
acquired identifiable net assets and liabilities in the aggregate, these
factors represented goodwill.

(12)
Devco USA L.L.C.

Effective
December 1, 2006, we acquired all of the membership interests in Devco USA
L.L.C., an Oklahoma limited liability company, for an aggregate consideration
of approximately $7.3 million, consisting of $4.8 million in cash, $1.6 million
in common units, and $0.9 million of assumed liabilities. The primary asset
acquired was a technology based identifiable intangible asset, a proprietary
process that transforms molten sulfur into premium solid formed pellets that
are environmentally friendly, easy to handle and store, and safe to transport.
The process was developed internally by Devcos engineers and employees. Devco,
a Tulsa, Oklahoma based company, has more than 20 years of sulfur handling
expertise and we believe the acquisition and subsequent application of this
acquired technology complements our existing dry-bulk terminal operations. We
allocated $6.5 million of our total purchase price to the value of this
intangible asset, and we have included the acquisition as part of our Terminals
business segment.

(13)
Roanoke, Virginia Products Terminal

Effective
December 15, 2006, we acquired a refined petroleum products terminal located in
Roanoke, Virginia from Motiva Enterprises, LLC for approximately $6.4 million
in cash. The terminal has storage capacity of approximately 180,000 barrels per
day for refined petroleum products like gasoline and diesel fuel. The terminal
is served exclusively by the Plantation Pipeline and Motiva has entered into a
long-term contract to use the terminal. The acquisition complemented the other
refined products terminals we own in the southeast region of the United States,
and the acquired terminal is included as part our Products Pipelines business
segment.

(14)
Interest in Cochin Pipeline

Effective
January 1, 2007, we acquired the remaining approximate 50.2% interest in the
Cochin pipeline system that we did not already own for an aggregate
consideration of approximately $47.8 million, consisting of $5.5 million in
cash and a note payable having a fair value of $42.3 million. As part of the
transaction, the seller also agreed to reimburse us for certain pipeline
integrity management costs over a five-year period in an aggregate amount not
to exceed $50 million. Upon closing, we became the operator of the pipeline.

The
Cochin Pipeline is a multi-product liquids pipeline consisting of approximately
1,900 miles of 12-inch diameter pipe operating between Fort Saskatchewan,
Alberta, and Windsor, Ontario, Canada. The entire Cochin pipeline system
traverses three provinces in Canada and seven states in the United States,
serving the Midwestern United States and eastern Canadian petrochemical and
fuel markets. Its operations are included as part of our Products Pipelines
business segment.

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As
of December 31, 2007, our allocation of the purchase price was preliminary,
pending final determination of deferred income tax balances at the time of
acquisition. We expect these final purchase price adjustments to be in the
first quarter of 2008.

(15)
Vancouver Wharves Terminal

On
May 30, 2007, we purchased the Vancouver Wharves bulk marine terminal from
British Columbia Railway Company, a crown corporation owned by the Province of
British Columbia, for an aggregate consideration of $57.2 million, consisting
of $38.8 million in cash and $18.4 million in assumed liabilities. The
Vancouver Wharves facility is located on the north shore of the Port of
Vancouvers main harbor, and includes five deep-sea vessel berths situated on a
139-acre site. The terminal assets include significant rail infrastructure, dry
bulk and liquid storage, and material handling systems which allow the terminal
to handle over 3.5 million tons of cargo annually. Vancouver Wharves also has
access to three major rail carriers connecting to shippers in western and
central Canada, and the U.S. Pacific Northwest. The acquisition both expanded
and complemented our existing terminal operations, and all of the acquired
assets are included in our Terminals business segment.

(16)
Marine Terminals, Inc. Assets

Effective
September 1, 2007, we acquired certain bulk terminals assets from Marine Terminals,
Inc. for an aggregate consideration of approximately $101.5 million, consisting
of $100.3 million in cash and an assumed liability of $1.2 million. The
acquired assets and operations are primarily involved in the handling and
storage of steel and alloys, and also provide stevedoring and harbor services,
scrap handling, and scrap processing services to customers in the steel and
alloys industry. The operations consist of two separate facilities located in
Blytheville, Arkansas, and individual terminal facilities located in Decatur,
Alabama, Hertford, North Carolina, and Berkley, South Carolina. Combined, the
five facilities handled approximately 13.4 million tons of steel products in
2006. Under long-term contracts, the acquired terminal facilities will continue
to provide handling, processing, harboring and warehousing services to Nucor
Corporation, one of the nations largest steel and steel products companies.

As
of December 31, 2007, we have preliminarily allocated $60.8 million of our combined
purchase price to Property, Plant and Equipment, net. The $40.5 million
allocated to deferred charges and other assets included $39.7 million of
intangible assets, representing the fair value of intangible customer
relationships which encompass both the contractual life of customer contracts
plus any future customer relationship value beyond the contract life. We expect to make further purchase price
adjustments to the acquired assets in the first half of 2008, based on further
analysis of fair market values. The acquisition both expanded and
complemented our existing ferro alloy terminal operations and will provide
Nucor and other customers further access to our growing national network of
marine and rail terminals. All of the acquired assets are included in our
Terminals business segment.

Pro
Forma Information

Pro
forma income statement information that assumes all of the acquisitions we have
made and joint ventures we have entered into since January 1, 2006, including
the ones listed above, had occurred as of January 1, 2006, is not materially
different from the information presented in our accompanying consolidated
statements of income.

Trans Mountain Pipeline System

On
April 30, 2007, we acquired the Trans Mountain pipeline system from Knight for
$549.1 million in cash. The transaction was approved by the independent
directors of both Knight and KMR following the receipt, by such directors, of
separate fairness opinions from different investment banks. We paid $549
million of the purchase price on April 30, 2007, and we paid the remaining $0.1
million in July 2007.

Effective
January 1, 2006, Knight (formerly KMI), our ultimate parent, according to the
provisions of Emerging Issues Task Force Issue No. 04-5, Determining Whether a
General Partner, or the General Partners as a Group, Controls a Limited
Partnership or Similar Entity When the Limited Partners Have Certain Rights,
was deemed to have control over us and no longer accounted for its investment
in us under the equity method of accounting, but instead included our accounts,
balances and results of operations in its consolidated financial statements. As

139

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required by the provisions of SFAS No. 141, we
accounted for our acquisition of Trans Mountain as a transfer of net assets
between entities under common control. For combinations of entities under
common control, the purchase cost provisions (as they relate to purchase
business combinations involving unrelated entities) of SFAS No. 141 explicitly
do not apply; instead the method of accounting prescribed by SFAS No. 141 for
such transfers is similar to the pooling-of-interests method of accounting.
Under this method, the carrying amount of net assets recognized in the balance
sheets of each combining entity are carried forward to the balance sheet of the
combined entity, and no other assets or liabilities are recognized as a result
of the combination (that is, no recognition is made for a purchase premium or
discount representing any difference between the cash consideration paid and
the book value of the net assets acquired).

Therefore,
following our acquisition of Trans Mountain from Knight on April 30, 2007, we
recognized the Trans Mountain assets and liabilities acquired at their carrying
amounts (historical cost) in the accounts of Knight (the transferring entity)
at the date of transfer. The accounting treatment for combinations of entities
under common control is consistent with the concept of poolings as combinations
of common shareholder (or unitholder) interests, as all of Trans Mountains
equity accounts were also carried forward intact initially, and subsequently
adjusted due to the cash consideration we paid for the acquired net assets.

In
addition to requiring that assets and liabilities be carried forward at
historical costs, SFAS No. 141 also prescribes that for transfers of net assets
between entities under common control, all income statements presented be
combined as of the date of common control. Accordingly, our consolidated
financial statements and all other financial information included in this
report have been restated to assume that the transfer of Trans Mountain net
assets from Knight to us had occurred at the date when both Trans Mountain and
we met the accounting requirements for entities under common control (January
1, 2006). As a result, financial statements and financial information presented
for prior periods in this report have been restated. These restatements include
Knights recognition of a goodwill impairment expense of $377.1 million
recorded in the first quarter of 2007. For more information on this impairment
expense, see Note 6.

The
Trans Mountain pipeline system, which transports crude oil and refined products
from Edmonton, Alberta, Canada to marketing terminals and refineries in British
Columbia and the state of Washington, recently completed a pump station
expansion and currently transports approximately 260,000 barrels per day. An
additional 35,000 barrel per day expansion that will increase capacity of the
pipeline to 300,000 barrels per day is expected to be in service by November
2008. In addition, due to the fact that Trans Mountains operations are managed
separately, involve different products and marketing strategies, and produce
discrete financial information that is separately evaluated internally by our
management, we have identified our Trans Mountain pipeline system as a separate
reportable business segment.

Divestitures

Douglas
Gas Gathering and Painter Gas Fractionation

Effective
April 1, 2006, we sold our Douglas natural gas gathering system and our Painter
Unit fractionation facility to Momentum Energy Group, LLC for approximately
$42.5 million in cash. Our investment in the net assets we sold in this
transaction, including all transaction related accruals, was approximately
$24.5 million, most of which represented property, plant and equipment, and we
recognized approximately $18.0 million of gain on the sale of these net assets.
We used the proceeds from these asset sales to reduce the outstanding balance
on our commercial paper borrowings.

Additionally,
upon the sale of our Douglas gathering system, we reclassified a net loss of
$2.9 million from Accumulated other comprehensive loss into net income on
those derivative contracts that effectively hedged uncertain future cash flows
associated with forecasted Douglas gathering transactions. We included the net
amount of the gain, $15.1 million, within the caption Other expense (income)
in our accompanying consolidated statement of income for the year ended
December 31, 2006. For more information on our accounting for derivative
contracts, see Note 14.

The
Douglas gathering system is comprised of approximately 1,500 miles of 4-inch to
16-inch diameter pipe that gathers approximately 26 million cubic feet per day
of natural gas from approximately 650 active receipt points.

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Gathered volumes are processed at our Douglas plant
(which we retained), located in Douglas, Wyoming. As part of the transaction,
we executed a long-term processing agreement with Momentum Energy Group, LLC
which dedicates volumes from the Douglas gathering system to our Douglas
processing plant. The Painter Unit, located near Evanston, Wyoming, consists of
a natural gas processing plant and fractionator, a nitrogen rejection unit, a
natural gas liquids terminal, and interconnecting pipelines with truck and rail
loading facilities. Prior to the sale, we leased the plant to BP, which
operated the fractionator and the associated Millis terminal and storage
facilities for its own account.

North
System Natural Gas Liquids Pipeline System  Discontinued Operations

On
July 2, 2007, we announced that we entered into an agreement to sell the North
System natural gas liquids pipeline and our 50% ownership interest in the
Heartland Pipeline Company (collectively referred to in this report as our
North System) to ONEOK Partners, L.P. for approximately $298.6 million in cash.
Our investment in net assets, including all transaction related accruals, was
approximately $145.8 million, most of which represented property, plant and
equipment, and we recognized approximately $152.8 million of gain on the sale
of these net assets.

The
North System consists of an approximately 1,600-mile interstate common carrier
pipeline system that delivers natural gas liquids and refined petroleum
products from south central Kansas to the Chicago area. Also included in the
sale were eight propane truck-loading terminals, located at various points in
three states along the pipeline system, and one multi-product terminal complex
located in Morris, Illinois. Prior to the sale, all of the assets were included
in our Products Pipelines business segment.

In
accordance with SFAS No. 144, Accounting for the Impairment or Disposal of
Long-Lived Assets, we accounted for the North System business as a
discontinued operation whereby the financial results of the North System have
been reclassified to discontinued operations in our accompanying consolidated
statements of income for all periods presented in this report. We reported the
net amount of the gain, $152.8 million, with the caption Gain on disposal of
North System within the discontinued operations section of our accompanying
consolidated statement of income for the year ended December 31, 2007.

Summarized financial information of the North System is as follows (in
millions):

|                                                   |  |                          |       |      |   |       |   |   |       |  
|-------------------------------------------------- |  | ------------------------ | ----- | ---- | - | ----- | - | - | ----- | -
|                                                   |  | Year Ended
 December 31, |      
|                                                   |  |                          |      
|                                                   |  | 2007                     |       | 2006 |   | 2005  |  
|                                                   |  |                          |       |      |   |       |  
|Operating revenues                                 |  | $                        | 41.1  |      | $ | 43.7  |   | $ | 41.2  |  
|Operating expenses                                 |  |                          | (14.8 | )    |   | (22.7 | ) |   | (35.2 | )
|Depreciation and
 amortization                     |  |                          | (7.0  | )    |   | (8.9  | ) |   | (8.2  | )
|Earnings from equity
 investments                  |  |                          | 1.8   |      |   | 2.2   |   |   | 2.1   |  
|Amortization of excess cost
 of equity investments |  |                          |      |      |   | (0.1  | ) |   | (0.1  | )
|Other, net  income
 (expense)                     |  |                          |      |      |   | 0.1   |   |   |      |  
|                                                   |  |                          |       |      |   |       |   |   |       |  
|Income (loss) from operations                      |  |                          | 21.1  |      |   | 14.3  |   |   | (0.2  | )
|Income from disposal                               |  |                          | 152.8 |      |   |      |   |   |      |  
|                                                   |  |                          |       |      |   |       |   |   |       |  
|Total earnings from discontinued operations        |  | $                        | 173.9 |      | $ | 14.3  |   | $ | (0.2  | )
|                                                   |  |                          |       |      |   |       |   |   |       |  

In
our accompanying consolidated statements of cash flows, we elected to not
separately present the North Systems operating and investing cash flows as
discontinued operations, and, due to
the fact that the sale of the North System does not change the structure of our
internal organization in a manner that causes a change to our reportable
business segments pursuant to the provisions of SFAS No. 131, Disclosures
about Segments of an Enterprise and Related Information, we have included the
North Systems financial disclosures within our Products Pipelines business
segment disclosures for all periods presented in this report.

4. Asset Retirement Obligations

We
account for our legal obligations associated with the retirement of long-lived
assets pursuant to Statement of Financial Accounting Standards No. 143, Accounting
for Asset Retirement Obligations. SFAS No. 143 provides accounting and
reporting guidance for legal obligations associated with the retirement of
long-lived assets that result from the acquisition, construction or normal
operation of a long-lived asset.

141

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SFAS
No. 143 requires companies to record a liability relating to the retirement and
removal of assets used in their businesses. Under SFAS No. 143, the fair value
of asset retirement obligations are recorded as liabilities on a discounted
basis when they are incurred, which is typically at the time the assets are
installed or acquired. Amounts recorded for the related assets are increased by
the amount of these obligations. Over time, the liabilities will be accreted
for the change in their present value and the initial capitalized costs will be
depreciated over the useful lives of the related assets. The liabilities are
eventually extinguished when the asset is taken out of service.

In
our CO2 business segment, we are required to plug and abandon oil
and gas wells that have been removed from service and to remove our surface
wellhead equipment and compressors. As of December 31, 2007 and 2006, we have
recognized asset retirement obligations relating to these requirements at
existing sites within our CO2 segment in the aggregate amounts of
$49.2 million and $47.2 million, respectively.

In
our Natural Gas Pipelines business segment, if we were to cease providing utility
services, we would be required to remove surface facilities from land belonging
to our customers and others. We believe we can reasonably estimate both the
time and costs associated with the retirement of these facilities. As of
December 31, 2007 and 2006, we have recognized asset retirement obligations
relating to the businesses within our Natural Gas Pipelines segment in the
aggregate amounts of $3.0 million and $3.1 million, respectively.

We
have included $1.4 million of our total asset retirement obligations as of both
December 31, 2007 and December 31, 2006 within Accrued other current
liabilities in our accompanying consolidated balance sheets. The remaining
$50.8 million obligation as of December 31, 2007 and $48.9 million obligation
as of December 31, 2006 are reported separately as non-current liabilities in
our accompanying consolidated balance sheets. No assets are legally restricted
for purposes of settling our asset retirement obligations. A reconciliation of
the beginning and ending aggregate carrying amount of our asset retirement
obligations for each of the years ended December 31, 2007 and 2006 is as
follows (in millions):

|                                   |  |                          |      |      |   |      |  
|---------------------------------- |  | ------------------------ | ---- | ---- | - | ---- | -
|                                   |  | Year Ended
 December 31, |     
|                                   |  |                          |     
|                                   |  | 2007                     |      | 2006 |  
|                                   |  |                          |      |      |  
|Balance at beginning of
 period    |  | $                        | 50.3 |      | $ | 43.2 |  
|Liabilities incurred               |  |                          | 0.4  |      |   | 6.8  |  
|Liabilities settled                |  |                          | (1.1 | )    |   | (2.2 | )
|Accretion expense                  |  |                          | 2.6  |      |   | 2.5  |  
|Revisions in estimated cash
 flows |  |                          |     |      |   |     |  
|                                   |  |                          |      |      |   |      |  
|Balance at end of period           |  | $                        | 52.2 |      | $ | 50.3 |  
|                                   |  |                          |      |      |   |      |  

We
have various other obligations throughout our businesses to remove facilities
and equipment on rights-of- way and other leased facilities. We currently
cannot reasonably estimate the fair
value of these obligations because the associated assets have indeterminate
lives. These assets include
pipelines, certain processing plants and distribution facilities, and certain
bulk and liquids terminal facilities. An asset retirement obligation, if any,
will be recognized once sufficient information is available to reasonably
estimate the fair value of the obligation.

5. Income Taxes

Components
of the income tax provision applicable to continuing operations for federal,
foreign and state taxes are as follows (in millions):

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|                         |  |                           |      |      |   |      |   |   |      |  
|------------------------ |  | ------------------------- | ---- | ---- | - | ---- | - | - | ---- | -
|                         |  | Year Ended December
  31, |     
|                         |  |                           |     
|                         |  | 2007                      |      | 2006 |   | 2005 |  
|                         |  |                           |      |      |   |      |  
|Taxes currently payable: |  |                           |      |      |   |      |   |   |      |  
|Federal                  |  | $                         | 12.7 |      | $ | 12.8 |   | $ | 9.6  |  
|State                    |  |                           | 8.2  |      |   | 2.3  |   |   | 2.1  |  
|Foreign                  |  |                           | 31.5 |      |   | 11.2 |   |   | 0.4  |  
|                         |  |                           |      |      |   |      |   |   |      |  
|Total                    |  |                           | 52.4 |      |   | 26.3 |   |   | 12.1 |  
|Taxes deferred:          |  |                           |      |      |   |      |   |   |      |  
|Federal                  |  |                           | 11.8 |      |   | 1.6  |   |   | 8.1  |  
|State                    |  |                           | 6.2  |      |   | 0.2  |   |   | 0.8  |  
|Foreign                  |  |                           | 0.6  |      |   | 0.9  |   |   | 3.5  |  
|                         |  |                           |      |      |   |      |   |   |      |  
|Total                    |  |                           | 18.6 |      |   | 2.7  |   |   | 12.4 |  
|                         |  |                           |      |      |   |      |   |   |      |  
|Total tax provision      |  | $                         | 71.0 |      | $ | 29.0 |   | $ | 24.5 |  
|                         |  |                           |      |      |   |      |   |   |      |  
|Effective tax rate       |  |                           | 14.6 | %    |   | 2.8  | % |   | 2.9  | %

The
difference between the statutory federal income tax rate and our effective
income tax rate is summarized as follows:

|                                                                |  |                           |       |      |  |       |    |  |       |   
|--------------------------------------------------------------- |  | ------------------------- | ----- | ---- |  | ----- | -- |  | ----- | --
|                                                                |  | Year Ended December
  31, |      
|                                                                |  |                           |      
|                                                                |  | 2007                      |       | 2006 |  | 2005  |   
|                                                                |  |                           |       |      |  |       |   
|Federal income tax rate                                         |  |                           | 35.0  | %    |  | 35.0  | %  |  | 35.0  | % 
|Increase (decrease) as a result of:                             |  |                           |       |      |  |       |    |  |       |   
|Partnership
earnings not
  subject to tax                       |  |                           | (35.0 | )%   |  | (35.0 | )% |  | (35.0 | )%
|Corporate
subsidiary earnings
  subject to tax                  |  |                           | 3.0   | %    |  | 1.0   | %  |  | 1.1   | % 
|Income tax
expense attributable
  to corporate equity earnings  |  |                           | 2.3   | %    |  | 0.5   | %  |  | 1.1   | % 
|Income tax
expense attributable
  to foreign corporate earnings |  |                           | 6.6   | %    |  | 1.1   | %  |  | 0.5   | % 
|State
taxes                                                     |  |                           | 2.7   | %    |  | 0.2   | %  |  | 0.2   | % 
|                                                                |  |                           |       |      |  |       |    |  |       |   
|Effective tax rate                                              |  |                           | 14.6  | %    |  | 2.8   | %  |  | 2.9   | % 
|                                                                |  |                           |       |      |  |       |    |  |       |   

Our deferred
tax assets and liabilities as of December 31, 2007 and 2006 result from the following (in millions):

|                                                     |  |              |       |      |   |       | 
|---------------------------------------------------- |  | ------------ | ----- | ---- | - | ----- | 
|                                                     |  | December 31, |      
|                                                     |  |              |      
|                                                     |  | 2007         |       | 2006 |  
|                                                     |  |              |       |      |  
|Deferred tax assets:                                 |  |              |       |      |   |       | 
|Book
accruals                                        |  | $            | 13.1  |      | $ | 1.4   | 
|Net Operating
Loss/Alternative minimum
  tax credits |  |              | 1.2   |      |   | 3.0   | 
|Other                                                |  |              | 1.7   |      |   | 1.3   | 
|                                                     |  |              |       |      |   |       | 
|Total deferred tax assets                            |  |              | 16.0  |      |   | 5.7   | 
|                                                     |  |              |       |      |   |       | 
|Deferred tax liabilities:                            |  |              |       |      |   |       | 
|Property,
plant and equipment                        |  |              | 189.9 |      |   | 106.9 | 
|Other                                                |  |              | 28.5  |      |   | 84.0  | 
|                                                     |  |              |       |      |   |       | 
|Total deferred tax liabilities                       |  |              | 218.4 |      |   | 190.9 | 
|                                                     |  |              |       |      |   |       | 
|Net deferred tax liabilities                         |  | $            | 202.4 |      | $ | 185.2 | 
|                                                     |  |              |       |      |   |       | 

We had
available, at December 31, 2007, approximately $0.13 million of foreign minimum
tax credit carryforwards, which will expire between the years 2013 and 2016,
and $1.1 million of state net operating loss carryforwards, which will expire
between the years 2008 and 2025. We believe it is more likely than not that the
net operating loss carryforwards will be utilized prior to their expiration; therefore,
no valuation allowance is necessary.

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6. Property, Plant and Equipment

Classes and
Depreciation

As of
December 31, 2007 and 2006, our property, plant and equipment consisted of the
following (in millions):

|                                                                                 |  |              |          |      |   |          |  
|-------------------------------------------------------------------------------- |  | ------------ | -------- | ---- | - | -------- | -
|                                                                                 |  | December 31, |         
|                                                                                 |  |              |         
|                                                                                 |  | 2007         |          | 2006 |  
|                                                                                 |  |              |          |      |  
|Natural gas, liquids, crude oil and carbon dioxide pipelines                     |  | $            | 5,498.4  |      | $ | 4,795.9  |  
|Natural gas, liquids, carbon dioxide pipeline, and terminals station
  equipment |  |              | 5,076.2  |      |   | 4,549.3  |  
|Natural gas, liquids (including linefill), and transmix processing               |  |              | 168.3    |      |   | 172.7    |  
|Other                                                                            |  |              | 1,060.4  |      |   | 844.9    |  
|Accumulated depreciation and depletion                                           |  |              | (2,044.0 | )    |   | (1,641.2 | )
|                                                                                 |  |              |          |      |   |          |  
|                                                                                 |  |              | 9,759.3  |      |   | 8,721.6  |  
|Land and land right-of-way                                                       |  |              | 551.5    |      |   | 532.9    |  
|Construction work in process                                                     |  |              | 1,280.5  |      |   | 851.6    |  
|                                                                                 |  |              |          |      |   |          |  
|Property, Plant and Equipment, net                                               |  | $            | 11,591.3 |      | $ | 10,106.1 |  
|                                                                                 |  |              |          |      |   |          |  

Depreciation
and depletion expense charged against property, plant and equipment consisted
of $529.3 million in 2007, $416.6 million in 2006 and $339.6 million in 2005.

Casualty
Gain

On August
29, 2005, Hurricane Katrina made landfall in the United States Gulf Coast
causing widespread damage to residential and commercial real and personal
property. In addition, on September 23, 2005, Hurricane Rita struck the
Texas-Louisiana Gulf Coast causing additional damage to insured interests. The
primary assets we operate that were impacted by these storms included several
bulk and liquids terminal facilities located in the states of Louisiana and
Mississippi, and certain of our Gulf Coast liquids terminals facilities, which
are located along the Houston Ship Channel. Specifically, with regard to
physical property damage, our International Marine Terminals facility suffered extensive
property damage and a general loss of business due to the effects of Hurricane
Katrina. IMT is a Louisiana
partnership owned 66 2/3% by us. It operates a multi-purpose bulk
commodity transfer terminal facility located in Port Sulphur, Louisiana.

All of our
terminal facilities affected by these storms are currently open, and all of the
facilities are covered by property casualty insurance. Some of the facilities
are also covered by business interruption insurance. To account for our property
casualty damage, we recognized repair expense related to hurricane damage as
incurred. We also transferred off our books the net book value of the assets
that were damaged or destroyed, and we offset the book value of all damaged and
destroyed assets with indemnity proceeds received (and receivable in the
future) according to the provisions of the insurance policies in force. We also
incurred capital expenditures related to the repair and replacement of damaged
assets.

When an
insured asset is damaged or destroyed, the relevant accounts must be adjusted
to the date of the casualty, and settlement with the insurance companies must
be completed. The maximum amount recoverable from property damage is the fair
market value of the property at the date of loss (the replacement value), or
the amount stipulated in the insurance contract. Although net book values are
irrelevant in determining indemnifications from insurers, under current
accounting provisions, asset book values are used for accounting purposes to
measure the gain or loss resulting from casualty settlements. Also, because
indemnifications under insurance policies are based upon fair market values,
indemnifications often exceed the book value of the assets destroyed or
damaged, and any excess of insurance indemnifications over the book value of
damaged assets represents a book casualty gain.

In the
fourth quarter of 2006, we reached settlements with our insurance carriers on
all of our property damage claims related to the 2005 hurricane season,
including IMTs claims. As a result of these settlements, we recognized a
property casualty gain of $15.2 million, excluding all hurricane repair and
clean-up expenses. This casualty gain represented the excess of indemnity
proceeds received or recoverable over the book value of damaged or destroyed
assets. We also collected, in 2006, property insurance indemnities of $13.1
million, and we disclosed these cash receipts separately as Property casualty
indemnifications within investing activities on our accompanying consolidated
statement of cash flows. In addition, as of December 31, 2006, we signed proofs
of loss totaling $8.0 million for expected future property damage proceeds, and
we received these indemnity proceeds in January 2007.

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With the settlement of these claims, we released all remaining
estimated property insurance receivables and estimated property
insurance-related damage claim amounts, as these hurricane property damage
claims are now closed; however, we did recognize additional casualty gains of
approximately $1.8 million in the first quarter of 2007 (before minority
interest allocations), based upon our final determination of the book value of
the fixed assets destroyed or damaged, and indemnities pursuant to flood insurance
coverage.

In addition
to this casualty gain, 2006 income and expense items related to hurricane
activity included the following: (i) a $2.8 million increase in
operating and maintenance expenses from hurricane repair and clean-up activities,
(ii) a $1.1 million increase in income tax expense associated with overall
hurricane income and expense items, (iii) a $0.4 million decrease in general
and administrative expenses from the allocation of overhead expenses to
hurricane related capital projects, and (iv) a $3.1 million increase in
minority interest expense related to the allocation of IMTs earnings from
hurricane income and expense items to minority interest. Combined, the
hurricane income and expense items, including the casualty gain, resulted in a
total increase in net income of $8.6 million in 2006. For the year 2006, we spent approximately $12.2 million for hurricane
repair and replacement costs and including accruals, sustaining capital
expenditures for hurricane repair and replacement costs totaled $14.2 million.

7. Investments

Our
significant equity investments as of December 31, 2007 consisted of:

| |   |                                           
| | - | ------------------------------------------
| |  | Plantation Pipe Line Company (51%);       
| |   |                                           
| |  | West2East Pipeline LLC (51%);             
| |   |                                           
| |  | Red Cedar Gathering Company (49%);        
| |   |                                           
| |  | Midcontinent Express Pipeline LLC (50%);  
| |   |                                           
| |  | Thunder Creek Gas Services, LLC (25%); and
| |   |                                           
| |  | Cortez Pipeline Company (50%).            

We operate
and own an approximate 51% ownership interest in Plantation Pipe Line Company,
and an affiliate of ExxonMobil owns the remaining approximate 49% interest.
Each investor has an equal number of directors on Plantations board of directors,
and board approval is required for certain corporate actions that are
considered participating rights. Therefore, we do not control Plantation Pipe
Line Company, and we account for our investment under the equity method of
accounting.

Similarly,
we operate and own a 51% ownership interest in West2East Pipeline LLC, a
limited liability company that is the sole owner of Rockies Express Pipeline
LLC. ConocoPhillips owns a 24% ownership interest in West2East Pipeline LLC and Sempra
Energy holds the remaining 25% interest. As discussed in Note 3, when
construction of the entire Rockies Express Pipeline project is completed, our
ownership interest will be reduced to 50% at which time the capital accounts of
West2East Pipeline LLC will be trued up to reflect our 50% economics in the
project. According to the provisions of current accounting standards, due to
the fact that we will receive 50% of the economics of the Rockies Express
project on an ongoing basis, we are not considered the primary beneficiary of
West2East Pipeline LLC and thus, we account for our investment under the equity
method of accounting. Prior to June 30, 2006, we owned a 66 2/3% ownership
interest in West2East Pipeline LLC and we accounted for our investment under
the full consolidation method. Following the decrease in our ownership interest
to 51% effective June 30, 2006, we deconsolidated this entity and began to
account for our investment under the equity method. As of December 31, 2006, we
had no material investment in the net assets of West2East Pipeline LLC due to
the fact that the amount of its assets, primarily property, plant and
equipment, was largely offset by the amount of its liabilities, primarily debt.

We
also own a 50% interest in Midcontinent Express Pipeline LLC, which filed an
application with the FERC in October 2007 requesting a certificate of public
convenience and necessity that would authorize construction and

145

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operation of
an approximate 500-mile natural gas transmission system. Energy Transfer
Partners, L.P. owns the remaining 50% interest. The Midcontinent Express
Pipeline will create long-haul, firm natural gas transportation takeaway
capacity, either directly or indirectly, from natural gas producing regions
located in Texas, Oklahoma and Arkansas. The total project is expected to cost
approximately $1.3 billion, and will have an initial transportation capacity of
approximately 1.4 billion cubic feet per day of natural gas. Furthermore, in
January 2008, Midcontinent Express and MarkWest Pioneer, L.L.C., a subsidiary
of MarkWest Energy Partners, L.P., entered into an option agreement which
provides MarkWest a one-time right to purchase a 10% ownership interest in
Midcontinent Express after the pipeline is fully constructed and placed into service.
If the option is exercised, we and Energy Transfer Partners will each own 45%
of Midcontinent Express, while MarkWest will own the remaining 10%.

Our total
investments consisted of the following (in millions):

|                                  |  |              |       |      |   |       | 
|--------------------------------- |  | ------------ | ----- | ---- | - | ----- | 
|                                  |  | December 31, |      
|                                  |  |              |      
|                                  |  | 2007         |       | 2006 |  
|                                  |  |              |       |      |  
|Plantation Pipe Line Company      |  | $            | 195.4 |      | $ | 199.6 | 
|West2East Pipeline LLC            |  |              | 191.9 |      |   |      | 
|Red Cedar Gathering Company       |  |              | 135.6 |      |   | 160.6 | 
|Midcontinent Express Pipeline LLC |  |              | 63.0  |      |   |      | 
|Thunder Creek Gas Services, LLC   |  |              | 37.0  |      |   | 37.2  | 
|Cortez Pipeline Company           |  |              | 14.2  |      |   | 16.2  | 
|All Others                        |  |              | 18.3  |      |   | 12.7  | 
|                                  |  |              |       |      |   |       | 
|Total Equity Investments          |  | $            | 655.4 |      | $ | 426.3 | 
|                                  |  |              |       |      |   |       | 

Our
earnings (losses) from equity investments were as follows (in millions):

|                                  |  |                           |       |      |   |      |   |   |      |  
|--------------------------------- |  | ------------------------- | ----- | ---- | - | ---- | - | - | ---- | -
|                                  |  | Year Ended December
  31, |      
|                                  |  |                           |      
|                                  |  | 2007                      |       | 2006 |   | 2005 |  
|                                  |  |                           |       |      |   |      |  
|Red Cedar Gathering Company       |  | $                         | 28.0  |      | $ | 36.3 |   | $ | 32.0 |  
|Cortez Pipeline Company           |  |                           | 19.2  |      |   | 19.2 |   |   | 26.3 |  
|Plantation Pipe Line Company      |  |                           | 29.4  |      |   | 12.8 |   |   | 24.9 |  
|Thunder Creek Gas Services, LLC   |  |                           | 2.2   |      |   | 2.4  |   |   | 2.8  |  
|Midcontinent Express Pipeline LLC |  |                           | 1.4   |      |   |     |   |   |     |  
|West2East Pipeline LLC            |  |                           | (12.4 | )    |   |     |   |   |     |  
|All Others                        |  |                           | 1.9   |      |   | 3.3  |   |   | 3.6  |  
|                                  |  |                           |       |      |   |      |   |   |      |  
|Total                             |  | $                         | 69.7  |      | $ | 74.0 |   | $ | 89.6 |  
|                                  |  |                           |       |      |   |      |   |   |      |  
|Amortization of excess costs      |  | $                         | (5.8  | )    | $ | (5.6 | ) | $ | (5.5 | )
|                                  |  |                           |       |      |   |      |   |   |      |  

Summarized
combined unaudited financial information for our significant equity investments
(listed above) is reported below (in millions; amounts represent 100% of
investee financial information):

|                                                                                                |  |                           |       |      |   |       |  |   |       | 
|----------------------------------------------------------------------------------------------- |  | ------------------------- | ----- | ---- | - | ----- |  | - | ----- | 
|                                                                                                |  | Year Ended December
  31, |      
|                                                                                                |  |                           |      
|Income Statement                                                                                |  | 2007                      |       | 2006 |   | 2005  | 
|                                                                                                |  |                           |       |      |   |       | 
|Revenues                                                                                        |  | $                         | 473.0 |      | $ | 441.9 |  | $ | 440.7 | 
|Costs and expenses                                                                              |  |                           | 355.1 |      |   | 299.5 |  |   | 279.6 | 
|                                                                                                |  |                           |       |      |   |       |  |   |       | 
|Earnings before extraordinary
  items and cumulative effect of a change in accounting principle |  |                           | 117.9 |      |   | 142.4 |  |   | 161.1 | 
|Net income                                                                                      |  | $                         | 117.9 |      | $ | 142.4 |  | $ | 161.1 | 
|                                                                                                |  |                           |       |      |   |       |  |   |       | 

|                         |  |              |         |      |   |         | 
|------------------------ |  | ------------ | ------- | ---- | - | ------- | 
|                         |  | December 31, |        
|                         |  |              |        
|Balance Sheet            |  | 2007         |         | 2006 |  
|                         |  |              |         |      |  
|Current assets           |  | $            | 138.3   |      | $ | 95.5    | 
|Non-current assets       |  |              | 3,519.5 |      |   | 1,506.0 | 
|Current liabilities      |  |              | 319.5   |      |   | 213.2   | 
|Non-current liabilities  |  |              | 2,624.1 |      |   | 1,127.3 | 
|Partners/owners equity |  |              | 714.2   |      |   | 261.0   | 

8. Intangibles

Our
intangible assets include goodwill, lease value, contracts, customer
relationships, technology-based assets and agreements.

146

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Goodwill
and Excess Investment Cost

As
an investor, the price we pay to acquire an ownership interest in an investee
will most likely differ from the underlying interest in book value, with book
value representing the investees net assets per its financial statements. This differential relates to both discrepancies
between the investees recognized net assets at book value and at current fair
values and to any premium we pay to acquire the investment. Under ABP
No. 18, any such premium paid by an investor, which is analogous to goodwill,
must be identified.

For our
investments in affiliated entities that are included in our consolidation, the excess
cost over underlying fair value of net assets is referred to as goodwill and reported
separately as Goodwill in our accompanying consolidated balance sheets.
Goodwill is not subject to amortization but must be tested for impairment at
least annually. This test requires goodwill to be assigned to an appropriate
reporting unit and to determine if the implied fair value of the reporting
units goodwill is less than its carrying amount.

Changes
in the carrying amount of our goodwill for each of the two years ended December
31, 2006 and 2007 are summarized as follows (in millions):

|                                      |  |                     |   |                        |  |     |  |           |       |                    |  |       |   |      |  |  |  |   |       |   |  |  |   |        |   |  |  |   |         |   | 
|------------------------------------- |  | ------------------- | - | ---------------------- |  | --- |  | --------- | ----- | ------------------ |  | ----- | - | ---- |  |  |  | - | ----- | - |  |  | - | ------ | - |  |  | - | ------- | - | 
|                                      |  | Products
 Pipelines |   | Natural Gas
 Pipelines |  | CO2 |  | Terminals |       | Trans
 Mountain(a) |  | Total |  
|                                      |  |                     |   |                        |  |     |  |           |       |                    |  |       |  
|Balance as of December 31, 2005       |  |                     | $ | 263.2                  |  |     |  | $         | 288.4 |                    |  |       | $ | 46.1 |  |  |  | $ | 201.3 |   |  |  | $ |       |   |  |  | $ | 799.0   |   | 
|Acquisitions
and purchase price adjs. |  |                     |   |                       |  |     |  |           |      |                    |  |       |   |     |  |  |  |   | 30.0  |   |  |  |   | 593.2  |   |  |  |   | 623.2   |   | 
|Disposals                             |  |                     |   |                       |  |     |  |           |      |                    |  |       |   |     |  |  |  |   |      |   |  |  |   |       |   |  |  |   |        |   | 
|Impairments                           |  |                     |   |                       |  |     |  |           |      |                    |  |       |   |     |  |  |  |   |      |   |  |  |   |       |   |  |  |   |        |   | 
|Currency
translation adjustments      |  |                     |   |                       |  |     |  |           |      |                    |  |       |   |     |  |  |  |   |      |   |  |  |   | (1.2   | ) |  |  |   | (1.2    | ) | 
|                                      |  |                     |   |                        |  |     |  |           |       |                    |  |       |   |      |  |  |  |   |       |   |  |  |   |        |   |  |  |   |         |   | 
|Balance as
 of December 31, 2006      |  |                     | $ | 263.2                  |  |     |  | $         | 288.4 |                    |  |       | $ | 46.1 |  |  |  | $ | 231.3 |   |  |  | $ | 592.0  |   |  |  | $ | 1,421.0 |   | 
|Acquisitions
and purchase price adjs. |  |                     |   |                       |  |     |  |           |      |                    |  |       |   |     |  |  |  |   | (2.2  | ) |  |  |   |       |   |  |  |   | (2.2    | ) | 
|Disposals                             |  |                     |   |                       |  |     |  |           |      |                    |  |       |   |     |  |  |  |   |      |   |  |  |   |       |   |  |  |   |        |   | 
|Impairments                           |  |                     |   |                       |  |     |  |           |      |                    |  |       |   |     |  |  |  |   |      |   |  |  |   | (377.1 | ) |  |  |   | (377.1  | ) | 
|Currency
translation adjustments      |  |                     |   |                       |  |     |  |           |      |                    |  |       |   |     |  |  |  |   |      |   |  |  |   | 36.1   |   |  |  |   | 36.1    |   | 
|                                      |  |                     |   |                        |  |     |  |           |       |                    |  |       |   |      |  |  |  |   |       |   |  |  |   |        |   |  |  |   |         |   | 
|Balance as
 of December 31, 2007      |  |                     | $ | 263.2                  |  |     |  | $         | 288.4 |                    |  |       | $ | 46.1 |  |  |  | $ | 229.1 |   |  |  | $ | 251.0  |   |  |  | $ | 1,077.8 |   | 
|                                      |  |                     |   |                        |  |     |  |           |       |                    |  |       |   |      |  |  |  |   |       |   |  |  |   |        |   |  |  |   |         |   | 

|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------ | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                
|(a)                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              | On April 18, 2007, we announced that we would
 acquire the Trans Mountain pipeline system from Knight (formerly KMI), and
 this transaction was completed April 30, 2007 (discussed in Note 3).
 Following the provisions of generally accepted accounting principles, this
 transaction caused Knight to consider the fair value of the Trans Mountain
 pipeline system, and to determine whether goodwill related to these assets
 was impaired. Knight recorded a goodwill impairment charge of $377.1 million
 in the first quarter of 2007.
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|For our
 investments in entities that are not fully consolidated but instead are
 included in our financial statements under the equity method of accounting,
 the premium we pay that represents excess cost over underlying
 fair value of net assets is referred to as equity method goodwill, and under
 SFAS No. 142, this excess cost is not subject to amortization but rather to
 impairment testing pursuant to APB No. 18. The impairment test under APB No.
 18 considers whether the fair value of the equity investment as a whole, not
 the underlying net assets, has declined and whether that decline is other
 than temporary. Therefore, in addition to our annual impairment test of
 goodwill, we periodically reevaluate the amount at which we carry the excess
 of cost over fair value of net assets accounted for under the equity method,
 as well as the amortization period for such assets, to determine whether
 current events or circumstances warrant adjustments to our carrying value
 and/or revised estimates of useful lives in accordance with APB Opinion No.
 18. As of both December 31, 2007 and 2006, we have reported $138.2 million in
 equity method goodwill within the caption Investments in our accompanying
 consolidated balance sheets.
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|We
 also periodically reevaluate the difference between the fair value of net
 assets accounted for under the equity method and our proportionate share of the
 underlying book value (that is, the investees net assets per its financial
 statements) of the investee at date of acquisition. In almost all instances,
 this differential, relating to the discrepancy between our share of the
 investees recognized net assets at book values and at current fair values,
 represents our share of undervalued depreciable assets, and since those
 assets (other than land) are subject to depreciation, we amortize this
 portion of our investment cost against our share of investee earnings. We
 reevaluate this differential, as well as the amortization period for such
 undervalued depreciable assets, to determine whether current events or
 circumstances warrant adjustments to our carrying value and/or revised
 estimates of useful lives in accordance with                                                                                                                                                                                                                                                                                                            

147

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|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  |                  
|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- | -----------------
|APB Opinion
 No. 18. The caption Investments in our accompanying consolidated balance
 sheets includes excess fair value of net assets over book value costs of
 $174.7 million as of December 31, 2007 and $177.1 million as of December 31,
 2006.                                                                                                                                                                                                                                           
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  |                  
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  | 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, are being amortized on a straight-line
 basis over their estimated useful 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):

|                                                  |  |                    |   |                    |   |  |  |   |       |   | 
|------------------------------------------------- |  | ------------------ | - | ------------------ | - |  |  | - | ----- | - | 
|                                                  |  | December 31,
 2007 |   | December 31,
 2006 |  
|                                                  |  |                    |   |                    |  
|Customer relationships,
 contracts and agreements |  |                    |   |                    |   |  |  |   |       |   | 
|Gross carrying
amount                             |  |                    | $ | 264.1              |   |  |  | $ | 224.4 |   | 
|Accumulated
amortization                          |  |                    |   | (36.9              | ) |  |  |   | (23.1 | ) | 
|                                                  |  |                    |   |                    |   |  |  |   |       |   | 
|Net carrying
amount                               |  |                    |   | 227.2              |   |  |  |   | 201.3 |   | 
|                                                  |  |                    |   |                    |   |  |  |   |       |   | 
|                                                  |  |                    |   |                    |   |  |  |   |       |   | 
|Technology-based assets,
 lease value and other   |  |                    |   |                    |   |  |  |   |       |   | 
|Gross carrying
amount                             |  |                    |   | 13.3               |   |  |  |   | 13.3  |   | 
|Accumulated
amortization                          |  |                    |   | (1.9               | ) |  |  |   | (1.4  | ) | 
|                                                  |  |                    |   |                    |   |  |  |   |       |   | 
|Net carrying
amount                               |  |                    |   | 11.4               |   |  |  |   | 11.9  |   | 
|                                                  |  |                    |   |                    |   |  |  |   |       |   | 
|                                                  |  |                    |   |                    |   |  |  |   |       |   | 
|Total Other intangibles,
 net                     |  |                    | $ | 238.6              |   |  |  | $ | 213.2 |   | 
|                                                  |  |                    |   |                    |   |  |  |   |       |   | 

The
increase in the carrying amount of customer relationships, contracts and
agreements since December 31, 2006 was primarily due to the acquisition of
intangible customer relationships included in our purchase of certain assets
from Marine Terminals, Inc. effective September 1, 2007. As of the acquisition
date, we preliminarily allocated $39.8 million of our combined purchase price
for Marine Terminals, Inc.s assets to intangible customer relationships, and
we estimated the expected useful life of these intangibles to be 20 years. For
more information on this acquisition, see Note 3.

Amortization
expense on our intangibles consisted of the following (in millions):

|                                                  |  |                         |      |      |   |      |  |   |     | 
|------------------------------------------------- |  | ----------------------- | ---- | ---- | - | ---- |  | - | --- | 
|                                                  |  | Year Ended December
31,
|                                                  |  |                         |      |      |   |      | 
|                                                  |  | 2007                    |      | 2006 |   | 2005 | 
|                                                  |  |                         |      |      |   |      | 
|Customer relationships,
 contracts and agreements |  | $                       | 13.8 |      | $ | 13.5 |  | $ | 8.6 | 
|Technology-based assets,
 lease value and other   |  |                         | 0.5  |      |   | 0.2  |  |   | 0.1 | 
|                                                  |  |                         |      |      |   |      |  |   |     | 
|Total amortization                                |  | $                       | 14.3 |      | $ | 13.7 |  | $ | 8.7 | 
|                                                  |  |                         |      |      |   |      |  |   |     | 

As of December
31, 2007, our weighted average amortization period for our intangible assets
was approximately 18.25 years. Our estimated amortization expense for these
assets for each of the next five fiscal years is approximately $15.5 million,
$14.4 million, $14.2 million, $14.1 million and $14.1 million, respectively.

|        | 
|------- | 
|9. Debt | 

Short-Term
Debt

Our
outstanding short-term debt as of December 31, 2007 and 2006 consisted of the
following (in millions):

|                                          |  |                    |   |                    |  |  |  |   |         |  | 
|----------------------------------------- |  | ------------------ | - | ------------------ |  |  |  | - | ------- |  | 
|                                          |  | December 31,
 2007 |   | December 31,
 2006 | 
|                                          |  |                    |   |                    | 
|Commercial paper borrowings               |  |                    | $ | 589.1              |  |  |  | $ | 1,098.2 |  | 
|Short-term portion of:                    |  |                    |   |                    |  |  |  |   |         |  | 
|5.35% senior
notes due August 15, 2007    |  |                    |   |                   |  |  |  |   | 250.0   |  | 
|5.40% note due
March 31, 2012(a)          |  |                    |   | 9.9                |  |  |  |   |        |  | 
|5.23% senior
notes due January 2, 2014(b) |  |                    |   | 6.2                |  |  |  |   | 5.9     |  | 
|7.84% senior
notes due July 23, 2008(c)   |  |                    |   | 5.0                |  |  |  |   | 5.0     |  | 
|                                          |  |                    |   |                    |  |  |  |   |         |  | 
|Total short-term debt                     |  |                    | $ | 610.2              |  |  |  | $ | 1,359.1 |  | 
|                                          |  |                    |   |                    |  |  |  |   |         |  | 

148

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(a)     
Our subsidiaries, Kinder
Morgan Operating L.P. A and Kinder Morgan Canada Company, are the obligors on
           the note.

(b)     
Our subsidiary, Kinder
Morgan Texas Pipeline, L.P., is the obligor on the notes.

(c)     
Our subsidiary, Central
Florida Pipe Line LLC, is the obligor on the notes.

The
weighted average interest rate on all of our borrowings was approximately 6.40%
during 2007 and 6.18% during 2006.

Credit
Facilities

On
February 22, 2006, we entered into a second unsecured bank credit facility, a
nine-month credit facility in the amount of $250 million, expiring on November
21, 2006. This facility contained borrowing rates and restrictive financial
covenants that were similar to the borrowing rates and covenants under our
pre-existing five-year unsecured $1.6 billion bank facility due August 18,
2010.

Effective
August 28, 2006, we terminated our $250 million nine-month facility and we
increased our five-year bank credit facility from $1.6 billion to $1.85
billion. The five-year unsecured bank credit facility remains due August 18,
2010; however, the bank facility can be amended to allow for borrowings up to
$2.1 billion. There were no borrowings under our five-year credit facility as
of December 31, 2007 or as of December 31, 2006.

Our
five-year credit facility is with a syndicate of financial institutions and
Wachovia Bank, National Association is the administrative agent. As of December
31, 2007, the amount available for borrowing under our credit facility was reduced
by an aggregate amount of $1,126.9 million, consisting of (i) our outstanding
commercial paper borrowings ($589.1 million as of December 31, 2007); (ii) a
combined $298 million in three letters of credit that support our hedging of
commodity price risks associated with the sale of natural gas, natural gas
liquids and crude oil; (iii) a $100 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; (iv) a combined
$46.6 million in two letters of credit that support tax-exempt bonds; (v) a
$19.9 million letter of credit that supports the construction of our Kinder
Morgan Louisiana Pipeline (a natural gas pipeline); (vi) a $37.5 million letter
of credit that supports our indemnification obligations on the Series D note
borrowings of Cortez Capital Corporation; and (vii) a combined $35.8 million in
other letters of credit supporting other obligations of us and our
subsidiaries.

Our
five-year credit facility permits us to obtain bids for fixed rate loans from
members of the lending syndicate. Interest on our 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.

Our credit
facility included the following restrictive covenants as of December 31, 2007:

| |   |                                                                                                                                               |                                                                                                                                                                                                                      
| | - | --------------------------------------------------------------------------------------------------------------------------------------------- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | total debt divided by earnings
 before interest, income taxes, depreciation and amortization for the
 preceding four quarters may not exceed:
| |   |                                                                                                                                               |                                                                                                                                                                                                                      
| |   |                                                                                                                                              | 5.5, in the case of any such
 period ended on the last day of (i) a fiscal quarter in which we make any
 Specified Acquisition, or (ii) the first or second fiscal quarter next
 succeeding such a fiscal quarter; or
| |   |                                                                                                                                               |                                                                                                                                                                                                                      
| |   |                                                                                                                                              | 5.0, in the case of any such
 period ended on the last day of any other fiscal quarter;                                                                                                                              
| |   |                                                                                                                                               |                                                                                                                                                                                                                      
| |  | certain limitations on entering
 into mergers, consolidations and sales of assets;                                                           
| |   |                                                                                                                                               |                                                                                                                                                                                                                      
| |  | limitations on granting liens;
 and                                                                                                          
| |   |                                                                                                                                               |                                                                                                                                                                                                                      
| |  | prohibitions on making any
 distribution to holders of units if an event of default exists or would exist
 upon making such distribution.    

In addition
to normal repayment covenants, under the terms of our credit facility, the
occurrence at any time of any of the following would constitute an event of
default (i) our failure to make required payments of any item of

149

---



indebtedness or any payment in respect of any hedging agreement,
provided that the aggregate outstanding principal amount for all such
indebtedness or payment obligations in respect of all hedging agreements is
equal to or exceeds $75 million; (ii) our general partners failure to make
required payments of any item of indebtedness, provided that the aggregate
outstanding principal amount for all such indebtedness is equal to or exceeds
$75 million; (iii) adverse judgments rendered against us for the payment of
money in an aggregate amount in excess of $75 million, if this same amount
remains undischarged for a period of thirty consecutive days during which
execution shall not be effectively stayed; and (iv) voluntary or involuntary
commencements of any proceedings or petitions seeking our liquidation,
reorganization or any other similar relief under any federal, state or foreign
bankruptcy, insolvency, receivership or similar law.

Excluding
the relatively non-restrictive specified negative covenants and events of
defaults, our credit facility does not contain any provisions designed to
protect against a situation where a party to an agreement is unable to find a
basis to terminate that agreement while its counterpartys impending financial
collapse is revealed and perhaps hastened through the default structure of some
other agreement. The credit
facility also does not contain a material adverse change clause coupled
with a lockbox provision; however, the facility does provide that the margin we
will pay with respect to borrowings and the facility fee that we will pay on
the total commitment will vary based on our senior debt investment rating. None
of our debt is subject to payment acceleration as a result of any change to our
credit ratings.

Commercial Paper
Program

In
April 2006, we increased our commercial paper program by $250 million to
provide for the issuance of up to $1.85 billion. Our $1.85 billion unsecured
five-year bank credit facility supports our commercial paper program, and
borrowings under our commercial paper program reduce the borrowings allowed
under our credit facility. As of December 31, 2007, we had $589.1 million of
commercial paper outstanding with a weighted average interest rate of 5.58%. As
of December 31, 2006, we had $1,098.2 million of commercial paper outstanding
with an average interest rate of 5.42%. The borrowings under our commercial
paper program were used principally to finance the acquisitions and capital
expansions we made during 2007 and 2006.

Long-Term
Debt

Our
outstanding long-term debt, excluding the value of interest rate swaps, as of
December 31, 2007 and 2006 was $6,455.9 million and $4,384.3 million,
respectively. The balances consisted of the following (in millions):

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|                                                                                        |  |               |   |         |   |  |  |   |          |   | 
|--------------------------------------------------------------------------------------- |  | ------------- | - | ------- | - |  |  | - | -------- | - | 
|                                                                                        |  | December
 31, |  
|                                                                                        |  |               |  
|                                                                                        |  | 2007          |   | 2006    |  
|                                                                                        |  |               |   |         |  
|Kinder
 Morgan Energy Partners, L.P. borrowings:                                        |  |               |   |         |   |  |  |   |          |   | 
|5.35% senior
notes due August 15, 2007                                                  |  |               | $ |        |   |  |  | $ | 250.0    |   | 
|6.30% senior
notes due February 1, 2009                                                 |  |               |   | 250.0   |   |  |  |   | 250.0    |   | 
|7.50% senior
notes due November 1, 2010                                                 |  |               |   | 250.0   |   |  |  |   | 250.0    |   | 
|6.75% senior
notes due March 15, 2011                                                   |  |               |   | 700.0   |   |  |  |   | 700.0    |   | 
|7.125% senior
notes due March 15, 2012                                                  |  |               |   | 450.0   |   |  |  |   | 450.0    |   | 
|5.85% senior
notes due September 15, 2012                                               |  |               |   | 500.0   |   |  |  |   |         |   | 
|5.00% senior
notes due December 15, 2013                                                |  |               |   | 500.0   |   |  |  |   | 500.0    |   | 
|5.125% senior
notes due November 15, 2014                                               |  |               |   | 500.0   |   |  |  |   | 500.0    |   | 
|6.00% senior
notes due February 1, 2017                                                 |  |               |   | 600.0   |   |  |  |   |         |   | 
|7.400% senior
notes due March 15, 2031                                                  |  |               |   | 300.0   |   |  |  |   | 300.0    |   | 
|7.75% senior
notes due March 15, 2032                                                   |  |               |   | 300.0   |   |  |  |   | 300.0    |   | 
|7.30% senior
notes due August 15, 2033                                                  |  |               |   | 500.0   |   |  |  |   | 500.0    |   | 
|5.80% senior
notes due March 15, 2035                                                   |  |               |   | 500.0   |   |  |  |   | 500.0    |   | 
|6.50% senior
notes due February 1, 2037                                                 |  |               |   | 400.0   |   |  |  |   |         |   | 
|6.95% senior
notes due January 15, 2038                                                 |  |               |   | 550.0   |   |  |  |   |         |   | 
|Commercial
paper borrowings                                                             |  |               |   | 589.1   |   |  |  |   | 1,098.2  |   | 
|Subsidiary
 borrowings:                                                                 |  |               |   |         |   |  |  |   |          |   | 
|Central Florida
Pipe Line LLC-7.840% senior notes due July 23, 2008                     |  |               |   | 5.0     |   |  |  |   | 10.0     |   | 
|Arrow Terminals
L.P.-IL Development Revenue Bonds due January 1, 2010                   |  |               |   | 5.3     |   |  |  |   | 5.3      |   | 
|Kinder Morgan
Operating L.P. A-5.40% BP note, due March 31, 2012                      |  |               |   | 23.6    |   |  |  |   |         |   | 
|Kinder Morgan
Canada Company-5.40% BP note, due March 31, 2012                          |  |               |   | 21.0    |   |  |  |   |         |   | 
|Kinder Morgan
Texas Pipeline, L.P.-5.23% Senior Notes, due January 2,
 2014             |  |               |   | 43.2    |   |  |  |   | 49.1     |   | 
|Kinder Morgan
Liquids Terminals LLC-N.J. Development Revenue Bonds due
 Jan. 15, 2018   |  |               |   | 25.0    |   |  |  |   | 25.0     |   | 
|Kinder Morgan
Operating L.P. B-Jackson-Union Cos. IL Revenue Bonds
 due April 1, 2024 |  |               |   | 23.7    |   |  |  |   | 23.7     |   | 
|International
Marine Terminals-Plaquemines, LA Revenue Bonds due March
 15, 2025        |  |               |   | 40.0    |   |  |  |   | 40.0     |   | 
|Other
miscellaneous subsidiary debt                                                     |  |               |   | 1.4     |   |  |  |   | 1.4      |   | 
|Unamortized debt discount
 on senior notes                                              |  |               |   | (11.2   | ) |  |  |   | (9.3     | ) | 
|Current portion of
 long-term debt                                                      |  |               |   | (610.2  | ) |  |  |   | (1,359.1 | ) | 
|                                                                                        |  |               |   |         |   |  |  |   |          |   | 
|Total
 Long-term debt                                                                   |  |               | $ | 6,455.9 |   |  |  | $ | 4,384.3  |   | 
|                                                                                        |  |               |   |         |   |  |  |   |          |   | 

Senior
Notes

During
2007, we completed three separate public offerings of senior notes, and on
August 15, 2007, we repaid $250 million of 5.35% senior notes that matured on
that date. With regard to the three offerings, we received proceeds, net of
underwriting discounts and commissions, as follows:

| |   |                                                                                                                                                                                                                                                
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | $992.8
 million from a January 30, 2007 public offering of a total of $1.0 billion in
 principal amount of senior notes, consisting of $600 million of 6.00% notes
 due February 1, 2017, and $400 million of 6.50% notes due February 1, 2037;
| |   |                                                                                                                                                                                                                                                
| |  | $543.9 million
 from a June 21, 2007 public offering of $550 million in principal amount of
 6.95% senior notes due January 15, 2038; and                                                                                                      
| |   |                                                                                                                                                                                                                                                
| |  | $497.8
 million from an August 28, 2007 public offering of $500 million in principal
 amount of 5.85% senior notes due September 15, 2012.                                                                                                     

We
used the proceeds from each of these offerings to reduce the borrowings under
our commercial paper program. As of December 31, 2007 and 2006, the outstanding
balance on the various series of our senior notes (excluding unamortized debt
discount) was $6,288.8 million and $4,490.7 million, respectively. For a
listing of the various outstanding series of our senior notes, see the table
above included in Long-Term Debt.

On
February 12, 2008, we completed an additional public offering of senior notes.
We issued a total of $900 million in principal amount of senior notes,
consisting of $600 million of 5.95% notes due February 15, 2018, and

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$300 million
of 6.95% notes due January 15, 2038. We received proceeds from the issuance of
the notes, after underwriting discounts and commissions, of approximately
$894.1 million, and we used the proceeds to reduce the borrowings under our
commercial paper program. The notes due in 2038 constitute a further issuance
of the $550 million aggregate principal amount of 6.95% notes issued on June
21, 2007 (referred to above) and will form a single series with those notes.

Interest
Rate Swaps

Information
on our interest rate swaps is contained in Note 14.

Subsidiary
Debt

Our
subsidiaries are obligors on the following debt. The agreements governing these
obligations contain various affirmative and negative covenants and events of
default. We do not believe that these provisions will materially affect
distributions to our partners.

Central
Florida Pipeline LLC Debt

Central
Florida Pipeline LLC is an obligor on an aggregate principal amount of $40
million of senior notes originally issued to a syndicate of eight insurance
companies. The senior notes have a fixed annual interest rate of 7.84% with
repayments in annual installments of $5 million beginning July 23, 2001. The
final payment is due July 23, 2008. Interest is payable semiannually on January
1 and July 23 of each year. In both July 2007 and July 2006, we
made an annual repayment of $5.0 million and as of December 31, 2007, Central
Floridas outstanding balance under the senior notes was $5.0 million.

Arrow
Terminals L.P.

Arrow
Terminals L.P. is an obligor on a $5.3 million principal amount of Adjustable
Rate Industrial Development Revenue Bonds issued by the Illinois Development
Finance Authority. The bonds have a maturity date of January 1, 2010, and interest on these bonds is paid and computed
quarterly at the Bond Market Association Municipal Swap Index. The bonds are
collateralized by a first mortgage on assets of Arrows Chicago operations and
a third mortgage on assets of Arrows Pennsylvania operations. As of December
31, 2007, the interest rate was 3.595%. The bonds are also backed by a $5.4
million letter of credit issued by JP Morgan Chase that backs-up the $5.3
million principal amount of the bonds and $0.1 million of interest on the bonds
for up to 45 days computed at 12% per annum on the principal amount thereof.

Kinder
Morgan Texas Pipeline, L.P. Debt

Kinder
Morgan Texas Pipeline, L.P. is the obligor on a series of unsecured senior
notes with a fixed annual stated interest rate as of August 1, 2005, of 8.85%.
The assumed principal amount, along with interest, is due in monthly
installments of approximately $0.7 million. The final payment is due January 2,
2014. As of December 31, 2007, KMTPs outstanding balance under the senior
notes was $43.2 million.

Additionally,
the unsecured senior notes may be prepaid at any time in amounts of at least
$1.0 million and at a price equal to the higher of par value or the present
value of the remaining scheduled payments of principal and interest on the
portion being prepaid.

Kinder
Morgan Liquids Terminals LLC Debt

Kinder
Morgan Liquids Terminals LLC is the obligor on $25.0 million of Economic
Development Revenue Refunding Bonds issued by the New Jersey Economic
Development Authority. These bonds have a maturity date of January 15, 2018.
Interest on these bonds is computed on the basis of a year of 365 or 366 days,
as applicable, for the actual number of days elapsed during Commercial Paper,
Daily or Weekly Rate Periods and on the basis of a 360-day year consisting of
twelve 30-day months during a Term Rate Period. As of December 31, 2007, the
interest rate was 3.57%. We have an outstanding letter of credit issued by
Citibank in the amount of $25.3 million that

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backs-up the $25.0 million principal amount of the bonds and $0.3
million of interest on the bonds for up to 42 days computed at 12% on a per
annum basis on the principal thereof.

Kinder
Morgan Operating L.P. B Debt

This
$23.7 million principal amount of tax-exempt bonds due April 1, 2024 was issued
by the Jackson-Union Counties Regional Port District. These bonds bear interest
at a weekly floating market rate. As of December 31, 2007, the interest rate on
these bonds was 3.33%. Also, as of December 31, 2007, we had an outstanding
letter of credit issued by Wachovia in the
amount of $24.1 million that backs-up the $23.7 million principal amount of the
bonds and $0.4 million of interest on the bonds for up to 55 days computed at
12% per annum on the principal amount thereof.

International
Marine Terminals Debt

We
own a 66 2/3% interest in International Marine Terminals partnership. The
principal assets owned by IMT are dock and wharf facilities financed by the
Plaquemines Port, Harbor and Terminal District (Louisiana) $40.0 million
Adjustable Rate Annual Tender Port Facilities Revenue Refunding Bonds
(International Marine Terminals Project) Series 1984A and 1984B. As of December
31, 2007, the interest rate on these bonds was 3.65%.

On
March 15, 2005, these bonds were refunded and the maturity date was extended
from March 15, 2006 to March 15, 2025. No other changes were made under the
bond provisions. The bonds are backed by two letters of credit issued by KBC
Bank N.V. On March 19, 2002, an Amended and Restated Letter of Credit
Reimbursement Agreement relating to the letters of credit in the amount of
$45.5 million was entered into by IMT and KBC Bank. In connection with that
agreement, we agreed to guarantee the obligations of IMT in proportion to our
ownership interest. Our obligation is approximately $30.3 million for
principal, plus interest and other fees.

Kinder
Morgan Operating L.P. A Debt

Effective
January 1, 2007, we acquired the remaining approximate 50.2% interest in the
Cochin pipeline system that we did not already own (see Note 3). As part of our
purchase price, two of our subsidiaries issued a long-term note payable to the
seller having a fair value of $42.3 million. We valued the debt equal to the
present value of amounts to be paid, determined using an annual interest rate
of 5.40%. The principal amount of the note, along with interest, is due in five
annual installments of $10.0 million beginning March 31, 2008. The final
payment is due March 31, 2012. Our subsidiaries Kinder Morgan Operating L.P.
A and Kinder Morgan Canada Company are the obligors on the note, and as of
December 31, 2007, the outstanding balance under the note was $44.6 million.

Maturities
of Debt

The
scheduled maturities of our outstanding debt, excluding value of interest rate
swaps, as of December 31, 2007, are summarized as follows (in millions):

|           |  |            |   |         |  | 
|---------- |  | ---------- | - | ------- |  | 
|Year       |  | Commitment |  
|           |  |            |  
|2008       |  |            | $ | 610.2   |  | 
|2009       |  |            |   | 265.8   |  | 
|2010       |  |            |   | 270.7   |  | 
|2011       |  |            |   | 715.1   |  | 
|2012       |  |            |   | 964.3   |  | 
|Thereafter |  |            |   | 4,240.0 |  | 
|           |  |            |   |         |  | 
|Total      |  |            | $ | 7,066.1 |  | 
|           |  |            |   |         |  | 

Contingent
Debt

As
prescribed by the provisions of Financial Accounting Standards Board
Interpretation (FIN) No. 45, Guarantors Accounting and Disclosure
Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of
Others, we disclose certain types of guarantees or indemnifications we have
made. These disclosures cover certain types of guarantees included within debt
agreements, even if the likelihood of requiring our

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performance
under such guarantee is remote. The following is a description of our
contingent debt agreements as of December 31, 2007.

Cortez
Pipeline Company Debt

Pursuant
to a certain Throughput and Deficiency Agreement, the partners of Cortez
Pipeline Company (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 December 31, 2007, the debt facilities of Cortez Capital Corporation
consisted of (i) $64.3 million of Series D notes due May 15, 2013; (ii) a $125
million short-term commercial paper program; and (iii) a $125 million five-year
committed revolving credit facility due December 22, 2009 (to support the
above-mentioned $125 million commercial paper program). As of December 31,
2007, Cortez Capital Corporation had $93.0 million of commercial paper
outstanding with an average interest rate of approximately 5.66%, the average
interest rate on the Series D notes was 7.14%, and there were no borrowings
under the credit facility.

With
respect to Cortezs Series D notes, Shell Oil Company shares our several
guaranty obligations jointly and severally; however, we are obligated to
indemnify Shell for liabilities it incurs in connection with such guaranty and
JP Morgan Chase issued a letter of credit on our behalf in December 2006 in the
amount of $37.5 million to secure our indemnification obligations to Shell for
50% of the $75 million in principal amount of Series D notes outstanding as of
December 31, 2006.

Red
Cedar Gathering Company Debt

Red
Cedar Gathering Company was the obligor on $55 million in aggregate principal
amount of Senior Notes due October 31, 2010. The Senior Notes were
collateralized by a first priority lien on the ownership interests, including
our 49% ownership interest, in Red Cedar Gathering Company. The Senior Notes
were also guaranteed by us and the other owner of Red Cedar Gathering Company
jointly and severally. As of December 31, 2006, $31.4 million in principal
amount of notes were outstanding.

In
March 2007, Red Cedar refinanced the outstanding balance of its existing Senior
Notes through a private placement of $100 million in principal amount of ten
year fixed rate notes. As a result of Red Cedar Gathering Companys retirement
of the remaining $31.4 million outstanding principal amount of its Senior
Notes, we are no longer contingently liable for any Red Cedar Gathering Company
debt.

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 December 31, 2007, this letter of credit had a face amount of
$22.5 million.

Rockies
Express Pipeline LLC Debt

Pursuant
to certain guaranty agreements, all three member owners of West2East Pipeline
LLC (which owns all of the member interests in Rockies Express Pipeline LLC)
have agreed to guarantee, severally in the same proportion as their percentage
ownership of the member interests in West2East Pipeline LLC, borrowings under
Rockies Express (i) $2.0 billion five-year, unsecured revolving credit
facility due April 28, 2011; (ii) $2.0 billion commercial paper program; and
(iii) $600 million in principal amount of floating rate senior notes due August
20,

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2009. The
three member owners and their respective ownership interests consist of the
following: our subsidiary Kinder Morgan W2E Pipeline LLC  51%, a subsidiary of
Sempra Energy  25%, and a subsidiary of ConocoPhillips  24%.

Borrowings
under the Rockies Express commercial paper program are primarily used to
finance the construction of the Rockies Express interstate natural gas pipeline
and to pay related expenses. The credit facility, which can be amended to allow
for borrowings up to $2.5 billion, supports borrowings under the commercial
paper program, and borrowings under the commercial paper program reduce the
borrowings allowed under the credit facility.

On
September 20, 2007, Rockies Express issued $600 million in principal amount of
senior unsecured floating rate notes. The notes have a maturity date of August
20, 2009, and interest on these notes is paid and computed quarterly on an
interest rate of three-month LIBOR plus a spread. Upon issuance of the notes,
Rockies Express entered into two floating-to-fixed interest rate swap
agreements having a combined notional principal amount of $600 million and a
maturity date of August 20, 2009.

In
addition to the $600 million in senior notes, as of December 31, 2007, Rockies
Express Pipeline LLC had $1,625.4 million of commercial paper outstanding with
a weighted average interest rate of approximately 5.50%, and there were no
borrowings under its five-year credit facility. Accordingly, as of December 31,
2007, our contingent share of Rockies Express debt was $1,135.0 million (51%
of total borrowings).

Fair
Value of Financial Instruments

Fair
value as used in SFAS No. 107, Disclosures About Fair Value of Financial
Instruments, represents the amount at which an instrument could be exchanged
in a current transaction between willing parties. The estimated fair value of
our long-term debt, including its current portion and excluding the value of
interest rate swaps, is based upon prevailing interest rates available to us as
of December 31, 2007 and December 31, 2006 and is disclosed below (in
millions).

|           |  |                   |           |                        |  |                  |  |                        |           |  |  |           | 
|---------- |  | ----------------- | --------- | ---------------------- |  | ---------------- |  | ---------------------- | --------- |  |  | --------- | 
|           |  | December 31, 2007 |           | December 31, 2006      | 
|           |  |                   |           |                        | 
|           |  | Carrying
  Value  |           | Estimated
  Fair Value |  | Carrying
  Value |  | Estimated
  Fair Value |          
|           |  |                   |           |                        |  |                  |  |                        |          
|Total Debt |  |                   | $ 7,066.1 |                        |  | $ 7,201.8        |  |                        | $ 5,743.4 |  |  | $ 5,865.0 | 

10. Pensions and Other Post-Retirement
Benefits

Pension
and Post-Retirement Benefit Plans

Due
to our acquisition of Trans Mountain (see Note 3), Kinder Morgan Canada Inc. and
Trans Mountain Pipeline Inc. (as general partner of Trans Mountain Pipeline
L.P.) are sponsors of pension
plans for eligible Trans Mountain employees. The plans include registered
defined benefit pension plans, supplemental unfunded arrangements, which
provide pension benefits in excess of statutory limits, and defined
contributory plans. We also provide post-retirement benefits other than
pensions for retired employees. Our combined net periodic benefit costs for
these Trans Mountain pension and post-retirement benefit plans for 2007 and
2006 was approximately $3.2 million and $3.5 million, respectively, recognized ratably
over each year. As of December 31, 2007, we estimate our overall net periodic
pension and post-retirement benefit costs for these plans for the year 2008
will be approximately $3.1 million, although this estimate could change if
there is a significant event, such as a plan amendment or a plan curtailment,
which would require a remeasurement of liabilities. We expect to contribute
approximately $2.6 million to these benefit plans in 2008.

Additionally,
in connection with our acquisition of SFPP, L.P. and Kinder Morgan Bulk
Terminals, Inc. in 1998, we acquired certain liabilities for pension and
post-retirement benefits. We provide medical and life insurance benefits to
current employees, their covered dependents and beneficiaries of SFPP and
Kinder Morgan Bulk Terminals. We also provide the same benefits to former
salaried employees of SFPP. Additionally, we will continue to fund these costs
for those employees currently in the plan during their retirement years. SFPPs
post-retirement benefit plan is frozen and no additional participants may join
the plan. The noncontributory defined benefit pension plan covering the former
employees of Kinder Morgan Bulk Terminals is the Knight Inc. Retirement

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Plan. The
benefits under this plan are based primarily upon years of service and final
average pensionable earnings; however, benefit accruals were frozen as of
December 31, 1998.

Our
net periodic benefit cost for the SFPP post-retirement benefit plan were
credits of $0.2 million in 2007, $0.3 million in 2006, and $0.3 million in
2005. The credits resulted in increases to income, largely due to amortizations
of an actuarial gain and a negative prior service cost. As of December 31,
2007, we estimate no overall net periodic post-retirement benefit cost for the
SFPP post-retirement benefit plan for the year 2008; however, this estimate
could change if a future significant event would require a remeasurement of
liabilities. In addition, we expect to contribute approximately $0.4 million to
this post-retirement benefit plan in 2008.

On
September 29, 2006, the FASB issued SFAS No. 158, Employers Accounting for
Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB
Statement Nos. 87, 88, 106 and 132(R). One of the provisions of this Statement
requires an employer with publicly traded equity securities to recognize the
overfunded or underfunded status of a defined benefit pension plan or
post-retirement benefit plan (other than a multiemployer plan) as an asset or
liability in its statement of financial position and to provide the required
disclosures as of the end of the fiscal year ending after December 15, 2006.
Following adoption of SFAS No. 158, entities will report as part of the net
benefit liability on their balance sheets amounts that have not yet been
recognized as a component of benefit expense (for example, unrecognized prior
service costs or credits, net (actuarial) gain or loss, and transition
obligation or asset) with a corresponding adjustment to accumulated other
comprehensive income.

We
adopted SFAS No. 158 on December 31, 2006, and the primary impact on us from
adopting this Statement was to require us to fully recognize, in our
consolidated balance sheet, both the funded status of our pension and
post-retirement benefit plan obligations, and previously unrecognized prior
service costs and credits and actuarial gains and losses. As of December 31,
2006, the recorded value of our pension and post-retirement benefit obligations
for both the Trans Mountain pension and post-retirement benefit plans and the
SFPP post-retirement benefit plan was a combined $28.4 million.

The
following table discloses the incremental effect on our consolidated balance
sheet of applying SFAS No. 158 on December 31, 2006 (in millions):

|                                         |  |                      |  |             |   |                     |  |  |        |   |  |  |  |        |   | 
|---------------------------------------- |  | -------------------- |  | ----------- | - | ------------------- |  |  | ------ | - |  |  |  | ------ | - | 
|                                         |  | Before
  Application |  | Adjustments |   | After
  Application | 
|                                         |  |                      |  |             |   |                     | 
|Prepaid benefit cost                     |  |                      |  | $          |   |                     |  |  | $     |   |  |  |  | $     |   | 
|Accrued benefit liability                |  |                      |  | 30.3        |   |                     |  |  | (1.9   | ) |  |  |  | 28.4   |   | 
|Intangible asset                         |  |                      |  |            |   |                     |  |  |       |   |  |  |  |       |   | 
|Deferred income tax
  liability          |  |                      |  | (6.4        | ) |                     |  |  | (1.2   | ) |  |  |  | (7.6   | ) | 
|Minority interest                        |  |                      |  |            |   |                     |  |  |       |   |  |  |  |       |   | 
|Accumulated other
  comprehensive income |  |                      |  |            |   |                     |  |  | 3.1    |   |  |  |  | 3.1    |   | 

As
of December 31, 2007, the recorded value of our pension and post-retirement benefit
obligations for these plans was a combined $37.5 million. We consider our
overall pension and post-retirement benefit liability exposure to be minimal in
relation to the value of our total consolidated assets and net income.

Multiemployer
Plans

As
a result of acquiring several terminal operations, primarily our acquisition of
Kinder Morgan Bulk Terminals, Inc. effective July 1, 1998, we participate in
several multi-employer pension plans for the benefit of employees who are union
members. We do not administer these plans and contribute to them in accordance
with the provisions of negotiated labor contracts. Other benefits include a
self-insured health and welfare insurance plan and an employee health plan
where employees may contribute for their dependents health care costs. Amounts
charged to expense for these plans were approximately $6.7 million for the year
ended December 31, 2007, and $6.3 million for each of the years ended December
31, 2006 and 2005.

Kinder
Morgan Savings Plan

The
Kinder Morgan Savings Plan is a defined contribution 401(k) plan. The plan
permits all full-time employees of Knight, Inc. and KMGP Services Company, Inc.
to contribute between 1% and 50% of base

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compensation,
on a pre-tax basis, into participant accounts. In addition to a mandatory
contribution equal to 4% of base compensation per year for most plan
participants, our general partner may make special discretionary contributions.
Certain employees contributions are based on collective bargaining agreements.
The mandatory contributions are made each pay period on behalf of each eligible
employee. Participants may direct the
investment of their contributions and all employer contributions, including
discretionary contributions, into a variety of investments. Plan assets are
held and distributed pursuant to a trust agreement. The total amount charged to
expense for our Savings Plan was $11.7 million during 2007, $10.2 million
during 2006, and $7.9 million during 2005.

Employer contributions for employees vest on
the second anniversary of the date of hire. Effective October 1, 2005, for new
employees of our Terminals segment, a tiered employer contribution schedule was
implemented. This tiered schedule provides for employer contributions of 1% for
service less than one year, 2% for service between one and two years, 3% for
services between two and five years, and 4% for service of five years or more.
All employer contributions for Terminals employees hired after October 1, 2005
vest on the fifth anniversary of the date of hire (effective January 1, 2008,
this five year anniversary date for Terminals employees was changed to three
years to comply with changes in federal regulations).

At
its July 2007 meeting, the compensation committee of the KMR board of directors
approved a special contribution of an additional 1% of base pay into the
Savings Plan for each eligible employee. Each eligible employee will receive an
additional 1% company contribution based on eligible base pay each pay period
beginning with the first pay period of August 2007 and continuing through the
last pay period of July 2008. The additional 1% contribution does not change or
otherwise impact, the annual 4% contribution that eligible employees currently
receive and it will vest according to the same vesting schedule described in
the preceding paragraph. Since this additional 1% company contribution is
discretionary, compensation committee approval will be required annually for
each additional contribution. During the first quarter of 2008, excluding the
1% additional contribution described above, we will not make any additional
discretionary contributions to individual accounts for 2007.

Additionally,
in 2006, an option to make after-tax Roth contributions (Roth 401(k) option)
to a separate participant account was added to the Savings Plan as an
additional benefit to all participants. Unlike traditional 401(k) plans, where
participant contributions are made with pre-tax dollars, earnings grow
tax-deferred, and the withdrawals are treated as taxable income, Roth 401(k)
contributions are made with after-tax dollars, earnings are tax-free, and the
withdrawals are tax-free if they occur after both (i) the fifth year of
participation in the Roth 401(k) option, and (ii) attainment of age 59 1⁄2, death
or disability. The employer contribution will still be considered taxable
income at the time of withdrawal.

Cash
Balance Retirement Plan

Employees
of KMGP Services Company, Inc. and Knight are also eligible to participate in a
Cash Balance Retirement Plan. Certain employees continue to accrue benefits
through a career-pay formula, grandfathered according to age and years of
service on December 31, 2000, or collective bargaining arrangements. All other
employees accrue benefits through a personal retirement account in the Cash
Balance Retirement Plan. Under the plan, we make contributions on behalf of
participating employees equal to 3% of eligible compensation every pay period.
Interest is credited to the personal retirement accounts at the 30-year U.S.
Treasury bond rate, or an approved substitute, in effect each year. Employees
become fully vested in the plan after five years, and they may take a lump sum
distribution upon termination of employment or retirement.

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11. Partners Capital

Limited
Partner Units

As
of December 31, 2007 and 2006, our partners capital consisted of the following
limited partner units:

|                            |  |                     |             |                     |  |             | 
|--------------------------- |  | ------------------- | ----------- | ------------------- |  | ----------- | 
|                            |  | December 31,
  2007 |             | December 31,
  2006 | 
|                            |  |                     |             |                     | 
|Common units                |  |                     | 170,220,396 |                     |  | 162,816,303 | 
|Class B units               |  |                     | 5,313,400   |                     |  | 5,313,400   | 
|i-units                     |  |                     | 72,432,482  |                     |  | 62,301,676  | 
|                            |  |                     |             |                     |  |             | 
|Total limited
partner units |  |                     | 247,966,278 |                     |  | 230,431,379 | 
|                            |  |                     |             |                     |  |             | 

The
total limited partner units represent our limited partners interest and an
effective 98% economic interest in us, exclusive of our general partners
incentive distribution rights. Our general partner has an effective 2% interest
in us, excluding its incentive distribution rights.

As
of December 31, 2007, our common unit total consisted of 155,864,661 units held
by third parties, 12,631,735 units held by Knight and its consolidated
affiliates (excluding our general partner) and 1,724,000 units held by our
general partner. As of December 31, 2006, our common unit total consisted of
148,460,568 units held by third parties, 12,631,735 units held by Knight and
its consolidated affiliates (excluding our general partner) and 1,724,000 units
held by our general partner.

On
both December 31, 2007 and December 31, 2006, all of our 5,313,400 Class B
units were held entirely by a wholly-owned subsidiary of Knight. The Class B
units are similar to our common units except that they are not eligible for
trading on the New York Stock Exchange. All of our Class B units were issued to
a wholly-owned subsidiary of Knight in December 2000.

On
both December 31, 2007 and December 31, 2006, all of our i-units were held
entirely by KMR. Our i-units are a separate class of limited partner interests
in us and are not publicly traded. In accordance with its limited liability
company agreement, KMRs activities are restricted to being a limited partner
in us, and to controlling and managing our business and affairs and the
business and affairs of our operating limited partnerships and their
subsidiaries. Through the combined effect of the provisions in our partnership
agreement and the provisions of KMRs limited liability company agreement, the
number of outstanding KMR shares and the number of i-units will at all times be
equal.

Under
the terms of our partnership agreement, we agreed that we will not, except in
liquidation, make a distribution on an i-unit other than in additional i-units
or a security that has in all material respects the same rights and privileges
as our i-units. 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 will 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 unit.

The
cash equivalent of distributions of i-units will be treated as if it had
actually been distributed for purposes of determining the distributions to our
general partner. We will not distribute the cash to the holders of our i-units
but will instead retain the cash for use in our business. If additional units
are distributed to the holders of our common units, we will issue an equivalent
amount of i-units to KMR based on the number of i-units it owns. Based on the
preceding, KMR received a distribution of 1,258,778 i-units on November 14,
2007. These additional i-units distributed were based on the $0.88 per unit
distributed to our common unitholders on that date. During the year ended
December 31, 2007, KMR received distributions of 4,430,806 i-units. These
additional i-units distributed were based on the $3.39 per unit distributed to
our common unitholders during 2007. During 2006, KMR received distributions of
4,383,303 i-units, based on the $3.23 per unit distributed to our common
unitholders during 2006.

Equity
Issuances

In
August 2006, we issued, in a public offering, 5,750,000 of our common units,
including common units sold pursuant to the underwriters over-allotment
option, at a price of $44.80 per unit, less commissions and underwriting

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expenses. We
received net proceeds of approximately $248.0 million for the issuance of these
5,750,000 common units.

On
May 17, 2007, KMR issued 5,700,000 of its shares in a public offering at a
price of $52.26 per share. The net
proceeds from the offering were used by KMR to buy additional i-units from us,
and we received net proceeds of $297.9 million for the issuance of 5,700,000
i-units.

On
December 5, 2007, we issued, in a public offering, 7,130,000 of our common
units, including common units sold pursuant to the underwriters over-allotment
option, at a price of $48.09 per unit, less commissions and underwriting
expenses. We received net proceeds of $342.9 million for the issuance of these
7,130,000 common units.

We
used the proceeds from each of these three issuances to reduce the borrowings
under our commercial paper program. In addition, pursuant to our purchase and
sale agreement with Trans-Global Solutions, Inc., we issued 266,813 common
units in May 2007 to TGS to settle a purchase price liability related to our
acquisition of bulk terminal operations from TGS in April 2005. As agreed
between TGS and us, the units were issued equal to a value of $15.0 million.

In
addition, on February 12, 2008, we completed an offering of 1,080,000 of our
common units at a price of $55.65 per unit in a privately negotiated
transaction. We received net proceeds of $60.1 million for
the issuance of these 1,080,000 common units, and we used the proceeds to
reduce the borrowings under our commercial paper program.

Income
Allocation and Declared Distributions

For
the purposes of maintaining partner capital accounts, our partnership agreement
specifies that items of income and loss shall be allocated among the partners,
other than owners of i-units, in accordance with their percentage interests.
Normal allocations according to percentage interests are made, however, only
after giving effect to any priority income allocations in an amount equal to
the incentive distributions that are allocated 100% to our general partner.
Incentive distributions are generally defined as all cash distributions paid to
our general partner that are in excess of 2% of the aggregate value of cash and
i-units being distributed.

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. For the years ended
December 31, 2007, 2006 and 2005, we declared distributions of $3.48, $3.26 and
$3.13 per unit, respectively. Under the terms of our partnership agreement, our
total distributions to unitholders for 2007, 2006 and 2005 required incentive
distributions to our general partner in the amount of $611.9 million, $528.4
million and $473.9 million, respectively. The increased incentive distributions
paid for 2007 over 2006, and 2006 over 2005 reflect the increases in amounts
distributed per unit as well as the issuance of additional units. Distributions
for the fourth quarter of each year are declared and paid during the first
quarter of the following year.

Fourth
Quarter 2006 Incentive Distribution Waiver

According
to the provisions of the Knight Annual Incentive Plan, in order for the
executive officers of our general partner and KMR, and for the employees of
KMGP Services Company, Inc. and Knight who operate our business to earn a
non-equity cash incentive (bonus) for 2006, both we and Knight were required to
meet pre-established financial performance targets. The target for us was $3.28
in cash distributions per common unit for 2006. Due to the fact that we did not
meet our 2006 budget target, we had no obligation to fund our 2006 bonus plan;
however, at its January 17, 2007 board meeting, the board of directors of KMI
(now Knight) determined that it was in KMIs long-term interest to fund a
partial payout of our bonuses through a reduction in our general partners
incentive distribution.

Accordingly,
our general partner, with the approval of the compensation committees and
boards of KMI and KMR, waived $20.1 million of its 2006 incentive distribution
for the fourth quarter of 2006. The waived amount approximated an amount equal
to our actual bonus payout for 2006, which was approximately 75% of our
budgeted full bonus payout for 2006 of $26.5 million. Including the effect of
this waiver, our distributions to unitholders for

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2006 resulted
in payments of incentive distributions to our general partner in the amount of
$508.3 million. The waiver of $20.1 million of incentive payment in the fourth
quarter of 2006 reduced our general partners equity earnings by $19.9 million.

Fourth
Quarter 2007 Incentive Distribution

On
January 16, 2008, we declared a cash distribution of $0.92 per unit for the
quarterly period ended December 31, 2007. This distribution was paid on
February 14, 2008, to unitholders of record as of January 31, 2008. Our common
unitholders and Class B unitholders received cash. KMR, our sole i-unitholder,
received a distribution in the form of additional i-units based on the $0.92
distribution per common unit. The number of i-units distributed was 1,253,951.
For each outstanding i-unit that KMR held, a fraction of an i-unit (0.017312)
was issued. The fraction was determined by dividing:

|   |   |                                                                                                                                                                                                                                                              
|-- | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   |  | $0.92, the
 cash amount distributed per common unit                                                                                                                                                                                                          
|   |   |                                                                                                                                                                                                                                                              
|by |   |                                                                                                                                                                                                                                                              
|   |   |                                                                                                                                                                                                                                                              
|   |  | $53.143, the average of
KMRs limited
 liability shares closing market prices from January 14-28, 2008, 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.

This
February 14, 2008 distribution included an incentive distribution to our
general partner in the amount of $170.3 million. Since this distribution was
declared after the end of the quarter, no amount is shown in our December 31,
2007 balance sheet as a distribution payable.

12. Related Party Transactions

General and
Administrative Expenses

KMGP
Services Company, Inc., a subsidiary of our general partner, provides employees
and Kinder Morgan Services LLC, a wholly owned subsidiary of KMR, provides
centralized payroll and employee benefits services to (i) us; (ii) our
operating partnerships and subsidiaries; (iii) our general partner; and (iv)
KMR (collectively, the Group). Employees of KMGP Services Company, Inc. are
assigned to work for one or more members of the Group. The direct costs of all
compensation, benefits expenses, employer taxes and other employer expenses for
these employees are allocated and charged by Kinder Morgan Services LLC to the
appropriate members of the Group, and the members of the Group reimburse Kinder
Morgan Services LLC for their allocated shares of these direct costs. There is
no profit or margin charged by Kinder Morgan Services LLC to the members of the
Group. The administrative support necessary to implement these payroll and
benefits services is provided by the human resource department of Knight, and
the related administrative costs are allocated to members of the Group in
accordance with existing expense allocation procedures. The effect of these
arrangements is that each member of the Group bears the direct compensation and
employee benefits costs of its assigned or partially assigned employees, as the
case may be, while also bearing its allocable share of administrative costs.
Pursuant to our limited partnership agreement, we provide reimbursement for our
share of these administrative costs and such reimbursements will be accounted
for as described above. Additionally, we reimburse KMR with respect to costs
incurred or allocated to KMR in accordance with our limited partnership
agreement, the delegation of control agreement among our general partner, KMR,
us and others, and KMRs limited liability company agreement.

The
named executive officers of our general partner and KMR and other employees
that provide management or services to both Knight and the Group are employed
by Knight. Additionally, other Knight employees assist in the operation of our
Natural Gas Pipeline assets. These Knight employees expenses are allocated
without a profit component between Knight and the appropriate members of the
Group.

Additionally,
in accordance with SFAS No. 123R, Knight Holdco LLC is required to recognize
compensation expense in connection with their Class A-1 and Class B units over
the expected life of such units. As a subsidiary of Knight Holdco LLC, we are
allocated a portion of this compensation expense, although we have no obligation
nor do we expect to pay any of these costs.

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Partnership
Interests and Distributions

Kinder
Morgan G.P., Inc.

Kinder
Morgan G.P., Inc. serves as our sole general partner. Pursuant to our
partnership agreement, our general partners interests represent a 1% ownership
interest in us, and a direct 1.0101% ownership interest in each of our five
operating partnerships. Collectively, our general partner owns an effective 2%
interest in our operating partnerships, excluding incentive distributions
rights as follows:

| |   |                                                                                                                                           
| | - | ------------------------------------------------------------------------------------------------------------------------------------------
| |  | its 1.0101% direct general
partner
 ownership interest (accounted for as minority interest in our consolidated
 financial statements); and
| |   |                                                                                                                                           
| |  | its 0.9899% ownership interest
indirectly
 owned via its 1% ownership interest in us.                                                     

As
of December 31, 2007, our general partner owned 1,724,000 common units,
representing approximately 0.70% of our outstanding limited partner units.

Our
partnership agreement requires that we distribute 100% of Available Cash, as
defined in our partnership agreement, to our partners within 45 days following
the end of each calendar quarter in accordance with their respective percentage
interests. Available Cash consists generally of all of our cash receipts,
including cash received by our operating partnerships and net reductions in
reserves, less cash disbursements and net additions to reserves and amounts
payable to the former general partner of SFPP, L.P. in respect of its remaining
0.5% interest in SFPP.

Our
general partner is granted discretion by our partnership agreement, which
discretion has been delegated to KMR, subject to the approval of our general
partner in certain cases, to establish, maintain and adjust reserves for future
operating expenses, debt service, maintenance capital expenditures, rate
refunds and distributions for the next four quarters. These reserves are not
restricted by magnitude, but only by type of future cash requirements with
which they can be associated. When KMR determines our quarterly distributions,
it considers current and expected reserve needs along with current and expected
cash flows to identify the appropriate sustainable distribution level.

Our
general partner and owners of our common units and Class B units receive
distributions in cash, while KMR, the sole owner of our i-units, receives
distributions in additional i-units. We do not distribute cash to i-unit owners
but retain the cash for use in our business. However, the cash equivalent of
distributions of i-units is treated as if it had actually been distributed for
purposes of determining the distributions to our general partner. Each time we
make a distribution, the number of i-units owned by KMR and the percentage of
our total units owned by KMR increase automatically under the provisions of our
partnership agreement.

Available
cash is initially distributed 98% to our limited partners and 2% to our general
partner. These distribution percentages are modified to provide for incentive
distributions to be paid to our general partner in the event that quarterly
distributions to unitholders exceed certain specified targets.

Available
cash for each quarter is distributed:

| |   |                                                                                                                                                                                                                                                                          
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | first, 98% to the owners of all
classes of
 units pro rata and 2% to our general partner until the owners of all classes
 of units have received a total of $0.15125 per unit in cash or equivalent
 i-units for such quarter;                                           
| |   |                                                                                                                                                                                                                                                                          
| |  | second, 85% of any available
cash then
 remaining to the owners of all classes of units pro rata and 15% to our
 general partner until the owners of all classes of units have received a
 total of $0.17875 per unit in cash or equivalent i-units for such quarter;    
| |   |                                                                                                                                                                                                                                                                          
| |  | third, 75% of any available cash
then
 remaining to the owners of all classes of units pro rata and 25% to our
 general partner until the owners of all classes of units have received a
 total of $0.23375 per unit in cash or equivalent i-units for such quarter;
 and

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| |   |                                                                                                                                                                                                                                                      
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | fourth, 50% of any available
cash then
 remaining to the owners of all classes of units pro rata, to owners of common
 units and Class B units in cash and to owners of i-units in the equivalent
 number of i-units, and 50% to our general partner.

For
more information on incentive distributions paid to our general partner, see
Note 11 Income Allocation and Declared Distributions.

Knight
Inc.

Knight
Inc. remains the sole indirect stockholder of our general partner. Also, as of
December 31, 2007, Knight directly owned 8,838,095 common units, indirectly
owned 5,313,400 Class B units and 5,517,640 common units through its
consolidated affiliates, including our general partner, and owned 10,334,746
KMR shares, representing an indirect ownership interest of 10,334,746 i-units.
Together, these units represented approximately 12.1% of our outstanding
limited partner units. Including both its general and limited partner interests
in us, at the 2007 distribution level, Knight received approximately 49% of all
quarterly distributions from us, of which approximately 43% was attributable to
its general partner interest and the remaining 6% was attributable to its
limited partner interest. The actual level of distributions Knight will receive
in the future will vary with the level of distributions to our limited partners
determined in accordance with our partnership agreement.

Kinder
Morgan Management, LLC

As
of December 31, 2007, KMR, our general partners delegate, remained the sole
owner of our 72,432,482 i-units.

Asset
Acquisitions and Sales

From
time to time in the ordinary course of business, we buy and sell pipeline and
related services from Knight and its subsidiaries. Such transactions are
conducted in accordance with all applicable laws and regulations and on an
arms length basis consistent with our policies governing such transactions. In
conjunction with our acquisition of (i) certain Natural Gas Pipelines assets
and partnership interests from Knight in December 1999 and December 2000; and
(ii) all of the ownership interest in TransColorado Gas Transmission Company
LLC from two wholly-owned subsidiaries of Knight on November 1, 2004, Knight
agreed to indemnify us and our general partner with respect to approximately
$733.5 million of our debt. Knight would be obligated to perform under this
indemnity only if we are unable, and/or our assets were insufficient to satisfy
our obligations.

Operations

Natural
Gas Pipelines Business Segment

Knight
or its subsidiaries operate and maintain for us the assets comprising our
Natural Gas Pipelines business segment. Natural Gas Pipeline Company of
America, a subsidiary of Knight, operates Trailblazer Pipeline Company LLCs
assets under a long-term contract pursuant to which Trailblazer Pipeline
Company LLC incurs the costs and expenses related to NGPLs operating and
maintaining the assets. Trailblazer Pipeline Company LLC provides the funds for
its own capital expenditures. NGPL does not profit from or suffer loss related
to its operation of Trailblazer Pipeline Company LLCs assets.

The
remaining assets comprising our Natural Gas Pipelines business segment as well
as our Cypress Pipeline (and our North System until its sale in October 2007,
described in Note 3), which is part of our Products Pipelines business segment,
are operated under other agreements between Knight and us. Pursuant to the
applicable underlying agreements, we pay Knight either a fixed amount or actual
costs incurred as reimbursement for the corporate general and administrative
expenses incurred in connection with the operation of these assets. The amounts
paid to Knight for corporate general and administrative costs, including amounts
related to Trailblazer Pipeline Company LLC, were $1.0 million of fixed costs
and $48.1 million of actual costs incurred for 2007, $1.0 million of fixed
costs and $37.9 million of actual costs incurred for 2006, and $5.5 million of
fixed costs and $24.2 million of actual costs incurred for 2005.

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We
believe the amounts paid to Knight for the services they provided each year
fairly reflect the value of the services performed. However, due to the nature
of the allocations, these reimbursements may not exactly match the actual time
and overhead spent. We believe the fixed amounts that were agreed upon at the
time the contracts were entered into were reasonable estimates of the corporate
general and administrative expenses to be incurred by Knight and its
subsidiaries in performing such services. We also reimburse Knight and its
subsidiaries for operating and maintenance costs and capital expenditures
incurred with respect to our assets.

CO2
Business Segment

Knight
or its subsidiaries operate and maintain for us the power plant we constructed
at the SACROC oil field unit, located in the Permian Basin area of West Texas.
The power plant provides approximately half of SACROCs current electricity
needs. Kinder Morgan Power Company, a subsidiary of Knight, operates and
maintains the power plant under a five-year contract expiring in June 2010.
Pursuant to the contract, Knight incurs the costs and expenses related to
operating and maintaining the power plant for the production of electrical
energy at the SACROC field. Such costs include supervisory personnel and
qualified operating and maintenance personnel in sufficient numbers to
accomplish the services provided in accordance with good engineering, operating
and maintenance practices. Kinder Morgan Production Company fully reimburses
Knights expenses, including all agreed-upon labor costs, and also pays to
Knight an operating fee of $20,000 per month.

In
addition, Kinder Morgan Production Company is responsible for processing and
directly paying invoices for fuels utilized by the plant. Other materials,
including but not limited to lubrication oil, hydraulic oils, chemicals,
ammonia and any catalyst are purchased by Knight and invoiced monthly as
provided by the contract, if not paid directly by Kinder Morgan Production
Company. The amounts paid to Knight in 2007 and 2006 for operating and
maintaining the power plant were $3.1 million and $2.9 million, respectively.
Furthermore, we believe the amounts paid to Knight for the services they
provide each year fairly reflect the value of the services performed.

Risk
Management

Certain
of our business activities expose us to risks associated with 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 fixed rate
debt obligations. Pursuant to our managements approved risk management policy,
we use derivative contracts to hedge or reduce our exposure to these risks and
protect our profit margins, and we are prohibited from engaging in speculative
trading.

Our
commodity-related risk management activities are monitored by our risk
management committee, which is a separately designated standing committee whose
job responsibilities involve operations exposed to commodity market risk and
other external risks in the ordinary course of business. Our risk management
committee is charged with the review and enforcement of our managements risk
management policy. The committee is comprised of 19 executive-level employees
of Knight or KMGP Services Company, Inc. whose job responsibilities involve
operations exposed to commodity market risk and other external risks in the
ordinary course of our businesses. The committee is chaired by our President
and is charged with the following three responsibilities: (i) establish and
review risk limits consistent with our risk tolerance philosophy; (ii)
recommend to the audit committee of our general partners delegate any changes,
modifications, or amendments to our risk management policy; and (iii) address
and resolve any other high-level risk management issues.

In
addition, as discussed in Note 1, as a result of the going private transaction
of Knight, a number of individuals and entities became significant investors in
Knight. By virtue of the size of their ownership interest in Knight, two of
those investors became related parties to us (as that term is defined in
authoritative accounting literature): (i) American International Group, Inc.
and certain of its affiliates; and (ii) Goldman Sachs Capital Partners and
certain of its affiliates. We and/or our affiliates enter into transactions
with certain AIG affiliates in the ordinary course of their conducting insurance
and insurance-related activities, although no individual transaction is, and
all such transactions collectively are not, material to our consolidated
financial statements.

We
also conduct commodity risk management activities in the ordinary course of
implementing our risk management strategies in which the counterparty to
certain of our derivative transactions is an affiliate of Goldman Sachs. In
conjunction with these activities, we are a party (through one of our
subsidiaries engaged in the

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production of
crude oil) to a hedging facility with J. Aron & Company/Goldman Sachs which
requires us to provide certain periodic information, but does not require the
posting of margin. As a result of changes in the market value of our derivative
positions, we have created both amounts receivable from and payable to Goldman
Sachs affiliates.

The
following table summarizes the fair values of these energy commodity derivative
contracts associated with our commodity price risk management activities with
related parties and included on our accompanying consolidated balance sheets as
of December 31, 2007 (in millions):

|                                                 |          
|------------------------------------------------ | ---------
|Derivatives-net
 asset/(liability)               |          
|Accrued other
current liabilities                | $ (239.8)
|Other long-term
liabilities and deferred credits | $ (386.5)

For
more information on our risk management activities see Note 14.

KM
Insurance, Ltd.

KM
Insurance, Ltd., referred to as KMIL, is a Bermuda insurance company and
wholly-owned subsidiary of Knight. KMIL was formed during the second quarter of
2005 as a Class 2 Bermuda insurance company, the sole business of which is to
issue policies for Knight and us to secure the deductible portion of our
workers compensation, automobile liability, and general liability policies
placed in the commercial insurance market. We accrue for the cost of insurance,
which is included in the related party general and administrative expenses and
which totaled approximately $3.6 million in 2007 and $5.8 million in 2006.

Notes
Receivable

Plantation
Pipe Line Company

We
have a seven-year note receivable bearing interest at the rate of 4.72% per
annum from Plantation Pipe Line Company, our 51.17%-owned equity investee. The
outstanding note receivable balance was $89.7 million and $93.1 million as of
December 31, 2007 and December 31, 2006, respectively. Of these amounts, $2.4
million and $3.4 million were included within Accounts, notes and interest
receivable, netRelated parties as of December 31, 2007 and December 31,
2006, respectively, and the remainder was included within Notes receivableRelated
parties at each reporting date.

Knight
Inc.

As
of December 31, 2007, an affiliate of Knight owed to us a long-term note with a
principal amount of $0.6 million, and we included this balance within Notes
receivableRelated parties on our consolidated balance sheet as of that
date. This note currently has no fixed terms of repayment and is denominated in
Canadian dollars. As of December 31, 2006, we had an additional note receivable
denominated in Canadian dollars from a second affiliate of Knight (and which
became an affiliate of ours in 2007), and combined, the two notes had a
translated principal amount of $6.5 million. The above amounts represent the
translated amounts included in our consolidated financial statements in U.S.
dollars.

Additionally,
prior to our acquisition of Trans Mountain on April 30, 2007, Knight and
certain of its affiliates advanced cash to Trans Mountain. The advances were
primarily used by Trans Mountain for capital expansion projects. Knight and its
affiliates also funded Trans Mountains cash book overdrafts (outstanding
checks) as of April 30, 2007. Combined, the funding for these items totaled
$67.5 million, and we reported this amount within the caption Changes in
components of working capital: Accounts Receivable in the operating section of
our accompanying consolidated statement of cash flows.

Coyote
Gas Treating, LLC

Coyote
Gas Treating, LLC is a joint venture that was organized in December 1996. It is
referred to as Coyote Gulch in this report. The sole asset owned by Coyote
Gulch is a 250 million cubic feet per day natural gas treating facility located
in La Plata County, Colorado. Prior to the contribution of our ownership
interest in Coyote Gulch to

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Red Cedar
Gathering on September 1, 2006, we were the managing partner and owned a 50%
equity interest in Coyote Gulch.

As
of January 1, 2006, we had a $17.0 million note receivable from Coyote Gulch.
The term of the note was month-to-month. In March 2006, the owners of Coyote
Gulch agreed to transfer Coyote Gulchs notes payable to members equity.
Accordingly, we contributed the principal amount of $17.0 million related to
our note receivable to our equity investment in Coyote Gulch.

On
September 1, 2006, we and the Southern Ute Tribe (owners of the remaining 50%
interest in Coyote Gulch) agreed to transfer all of the members equity in
Coyote Gulch to the members equity of Red Cedar Gathering Company, a joint
venture organized in August 1994. Red Cedar owns and operates natural gas
gathering, compression and treating facilities in the Ignacio Blanco Field in
La Plata County, Colorado, and is owned 49% by us and 51% by the Southern Ute
Tribe. Under the terms of a five-year operating lease agreement that became
effective January 1, 2002, Red Cedar also operates the gas treating facility
owned by Coyote Gulch and is responsible for all operating and maintenance
expenses and capital costs.

Accordingly,
on September 1, 2006, we and the Southern Ute Tribe contributed the value of
our respective 50% ownership interests in Coyote Gulch to Red Cedar, and as a
result, Coyote Gulch became a wholly owned subsidiary of Red Cedar. The value
of our 50% equity contribution from Coyote Gulch to Red Cedar on September 1,
2006 was $16.7 million, and this amount remains included within Investments
on our consolidated balance sheet as of December 31, 2007.

Other

Generally,
KMR makes all decisions relating to the management and control of our business.
Our general partner owns all of KMRs voting securities and is its sole
managing member. Knight, through its wholly owned and controlled subsidiary
Kinder Morgan (Delaware), Inc., owns all the common stock of our general
partner. Certain conflicts of interest could arise as a result of the
relationships among KMR, our general partner, Knight and us. The officers of
Knight have fiduciary duties to manage Knight, including selection and
management of its investments in its subsidiaries and affiliates, in a manner
beneficial to themselves. In general, KMR has a fiduciary duty to manage us in
a manner beneficial to our unitholders. The partnership agreements for us and
our operating partnerships contain provisions that allow KMR to take into
account the interests of parties in addition to us in resolving conflicts of
interest, thereby limiting its fiduciary duty to our unitholders, as well as
provisions that may restrict the remedies available to our unitholders for
actions taken that might, without such limitations, constitute breaches of
fiduciary duty.

The
partnership agreements provide that in the absence of bad faith by KMR, the
resolution of a conflict by KMR will not be a breach of any duties. The duty of
the officers of Knight may, therefore, come into conflict with the duties of
KMR and its directors and officers to our unitholders. The audit committee of
KMRs board of directors will, at the request of KMR, review (and is one of the
means for resolving) conflicts of interest that may arise between Knight or its
subsidiaries, on the one hand, and us, on the other hand.

13. Leases and Commitments

Capital Leases

We
acquired certain leases classified as capital leases as part of our acquisition
of Kinder Morgan River Terminals LLC in October 2004. We lease our Memphis,
Tennessee port facility under an agreement accounted for as a capital lease.
The lease is for 24 years and expires in 2017.

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Amortization
of assets recorded under capital leases is included with depreciation expense.
The components of property, plant and equipment recorded under capital leases
are as follows (in millions):

|                                |  |                    |   |                    |   |  |  |   |      |   | 
|------------------------------- |  | ------------------ | - | ------------------ | - |  |  | - | ---- | - | 
|                                |  | December 31,
 2007 |   | December 31,
 2006 |  
|                                |  |                    |   |                    |  
|Leasehold improvements          |  |                    | $ | 2.2                |   |  |  | $ | 2.2  |   | 
|Less: Accumulated
 amortization |  |                    |   | (0.3               | ) |  |  |   | (0.2 | ) | 
|                                |  |                    |   |                    |   |  |  |   |      |   | 
|Total                           |  |                    | $ | 1.9                |   |  |  | $ | 2.0  |   | 
|                                |  |                    |   |                    |   |  |  |   |      |   | 

Future
commitments under capital lease obligations as of December 31, 2007 are as
follows (in millions):

|                                                 |  |  |            |      |   |  | 
|------------------------------------------------ |  |  | ---------- | ---- | - |  | 
|Year                                             |  |  | Commitment |     
|                                                 |  |  |            |     
|2008                                             |  |  | $          | 0.2  |   | 
|2009                                             |  |  |            | 0.2  |   | 
|2010                                             |  |  |            | 0.2  |   | 
|2011                                             |  |  |            | 0.2  |   | 
|2012                                             |  |  |            | 0.2  |   | 
|Thereafter                                       |  |  |            | 0.6  |   | 
|                                                 |  |  |            |      |   | 
|Subtotal                                         |  |  |            | 1.6  |   | 
|Less: Amount
representing interest               |  |  |            | (0.6 | ) | 
|                                                 |  |  |            |      |   | 
|Present value of minimum
 capital lease payments |  |  | $          | 1.0  |   | 
|                                                 |  |  |            |      |   | 

Operating
Leases

Including
probable elections to exercise renewal options, the remaining terms on our
operating leases range from one to 61 years. Future commitments related to
these leases as of December 31, 2007 are as follows (in millions):

|                       |  |  |            |       |  |  | 
|---------------------- |  |  | ---------- | ----- |  |  | 
|Year                   |  |  | Commitment |      
|                       |  |  |            |      
|2008                   |  |  | $          | 31.5  |  | 
|2009                   |  |  |            | 22.8  |  | 
|2010                   |  |  |            | 19.5  |  | 
|2011                   |  |  |            | 15.6  |  | 
|2012                   |  |  |            | 12.1  |  | 
|Thereafter             |  |  |            | 27.6  |  | 
|                       |  |  |            |       |  | 
|Total minimum payments |  |  | $          | 129.1 |  | 
|                       |  |  |            |       |  | 

The
largest of these lease commitments, in terms of total obligations payable by
December 31, 2008, include commitments supporting: (i) crude oil drilling rig operations for the
oil and gas activities of our CO2 business segment; (ii)
marine port terminal operations at our Nassau bulk product terminal, located in
Fernandina Beach, Florida; and (iii) natural gas storage in underground salt
dome caverns for our Texas intrastate natural gas pipeline group.

We
have not reduced our total minimum payments for future minimum sublease rentals
aggregating approximately $2.0 million. Total lease and rental expenses were
$49.2 million for 2007, $54.2 million for 2006 and $47.3 million for 2005.

Common Unit
Option Plan

During
1998, we established a common unit option plan, which provides that key
personnel of KMGP Services Company, Inc. and Knight are eligible to receive
grants of options to acquire common units. The number of common units
authorized under the option plan is 500,000. The option plan terminates in
March 2008. The options granted generally have a term of seven years, vest 40%
on the first anniversary of the date of grant and 20% on each of the next three
anniversaries, and have exercise prices equal to the market price of the common
units at the grant date.

As
of January 1, 2006, outstanding options to purchase 15,300 common units were
held by employees of Knight or KMGP Services Company, Inc. at an average
exercise price of $17.82 per unit. Outstanding options to purchase 10,000
common units were held by one of our general partners three non-employee
directors at an average exercise

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price of $21.44 per unit. All 25,300 outstanding options were fully
vested. During 2006, 4,200 options to purchase common units were cancelled or
forfeited, and 21,100 options to purchase common units were exercised at an

average price of $19.67 per unit. The common units underlying these
options had an average fair market value of $46.43 per unit. Accordingly, as of
December 31, 2006 and 2007, there were no outstanding options.

We account
for common unit options granted under our common unit option plan according
to the provisions of SFAS No. 123R (revised 2004), Share-Based Payment, which
became effective for us January 1, 2006. This Statement amends SFAS No. 123,
Accounting for Stock-Based Compensation, and requires companies to expense
the value of employee stock options and similar awards. According to the
provisions of SFAS No. 123R, share-based payment awards result in a cost that
will be measured at fair value on the awards grant date, based on the
estimated number of awards that are expected to vest. Companies will recognize
compensation cost for share-based payment awards as they vest, including the
related tax effects, and compensation cost for awards that vest would not be
reversed if the awards expire without being exercised.

However,
we have not granted common unit options or made any other share-based payment
awards since May 2000, and as described above, all outstanding options to
purchase our common units were fully vested as of January 1, 2006. Therefore,
the adoption of this Statement did not have an effect on our consolidated
financial statements due to the fact that we had reached the end of the
requisite service period for any compensation cost resulting from share-based
payments made under our common unit option plan.

Directors
Unit Appreciation Rights Plan

On April 1, 2003,
KMRs compensation committee established our Directors Unit Appreciation
Rights Plan. Pursuant to this plan, each of KMRs three non-employee directors
was eligible to receive common unit appreciation rights. Upon the exercise of
unit appreciation rights, we will pay, within thirty days of the exercise date,
the participant an amount of cash equal to the excess, if any, of the aggregate
fair market value of the unit appreciation rights exercised as of the exercise
date over the aggregate award price of the rights exercised. The fair market
value of one unit appreciation right as of the exercise date will be equal to
the closing price of one common unit on the New York Stock Exchange on that
date. The award price of one unit appreciation right will be equal to the
closing price of one common unit on the New York Stock Exchange on the date of
grant. Proceeds, if any, from the exercise of a unit appreciation right granted
under the plan will be payable only in cash (that is, no exercise will result
in the issuance of additional common units) and will be evidenced by a unit
appreciation rights agreement.

All unit
appreciation rights granted vest on the six-month anniversary of the date of
grant. If a unit appreciation right is not exercised in the ten year period
following the date of grant, the unit appreciation right will expire and not be
exercisable after the end of such period. In addition, if a participant ceases
to serve on the board for any reason prior to the vesting date of a unit
appreciation right, such unit appreciation right will immediately expire on the
date of cessation of service and may not be exercised.

On April 1,
2003, the date of adoption of the plan, each of KMRs three non-employee
directors were granted 7,500 unit appreciation rights. In addition, 10,000 unit
appreciation rights were granted to each of KMRs three non-employee directors
on January 21, 2004, at the first meeting of the board in 2004. During the
first board meeting of 2005, the plan was terminated and replaced by the Kinder
Morgan Energy Partners, L.P. Common Unit Compensation Plan for Non-Employee
Directors. All unexercised awards made under our Directors Unit Appreciation
Rights Plan remain outstanding.

No unit
appreciation rights were exercised during 2006. During 2007, 7,500 unit
appreciation rights were exercised by one director at an aggregate fair value
of $53.00 per unit. As of December 31, 2007, 45,000 unit appreciation rights
had been granted, vested and remained outstanding.

Kinder
Morgan Energy Partners, L.P. Common Unit Compensation Plan for Non-Employee
Directors

On January 18,
2005, KMRs compensation committee established the Kinder Morgan Energy
Partners, L.P. Common Unit Compensation Plan. The plan is administered by KMRs
compensation committee and KMRs board has sole discretion to terminate the
plan at any time. The primary purpose of this plan was to promote our interests

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and the interests of our unitholders by aligning the compensation of
the non-employee members of the board of directors of KMR with unitholders
interests. Further, since KMRs success is dependent on its operation and
management of our business and our resulting performance, the plan is expected
to align the compensation of the non-employee members of the board with the
interests of KMRs shareholders.

The plan
recognizes that the compensation to be paid to each non-employee director is
fixed by the KMR board, generally annually, and that the compensation is
payable in cash. Pursuant to the plan, in lieu of receiving cash compensation,
each non-employee director may elect to receive common units. Each election is
made generally at or around the first board meeting in January of each calendar
year and is effective for the entire calendar year. A non-employee director may
make a new election each calendar year. The total number of common units
authorized under this compensation plan is 100,000.

The initial
election under this plan for service in 2005 was made effective January 20,
2005. The elections for 2006, 2007 and 2008 were made effective January 17,
2006, January 17, 2007 and January 16, 2008, respectively. Each annual election
is evidenced by an agreement, the Common Unit Compensation
Agreement, between us and each non-employee
director, and this agreement contains the terms and conditions of each award.
Pursuant to this agreement, all common units issued under this plan are subject
to forfeiture restrictions that expire six months from the date of issuance.
Until the forfeiture restrictions lapse, common units issued under the plan may
not be sold, assigned, transferred, exchanged, or pledged by a non-employee
director. In the event the directors service as a director of KMR is
terminated prior to the lapse of the forfeiture restriction either for cause,
or voluntary resignation, each director will, for no consideration, forfeit to
us all common units to the extent then subject to the forfeiture restrictions.
Common units with respect to which forfeiture restrictions have lapsed cease to
be subject to any forfeiture restrictions, and we will provide each director a
certificate representing the units as to which the forfeiture restrictions have
lapsed. In addition, each non-employee director has the right to receive
distributions with respect to the common units awarded to him under the plan,
to vote such common units and to enjoy all other unitholder rights, including
during the period prior to the lapse of the forfeiture restrictions.

The
number of common units to be issued to a non-employee director electing to
receive the cash compensation in the form of common units will equal the amount
of such cash compensation awarded, divided by the closing price of the common units on the New York Stock Exchange on the
day the cash compensation is awarded (such
price, the fair market value), rounded down to the nearest 50 common
units. The common units will be issuable as specified in the Common Unit
Compensation Agreement. A non-employee director electing to receive the cash
compensation in the form of common units will receive cash equal to the
difference between (i) the cash compensation awarded to such non-employee director
and (ii) the number of common units to be issued to such non-employee director
multiplied by the fair market value of a
common unit. This cash payment is payable in four equal installments generally
around March 31, June 30, September 30 and December 31 of the calendar year in
which such cash compensation is awarded.

On January
18, 2005, the date of adoption of the plan, each of KMRs three non-employee
directors was awarded cash compensation of $119,750 for board service during
2005. Effective January 20, 2005, each non-employee director elected to receive
compensation of $79,750 in the form of our common units and was issued
1,750 common units pursuant to the plan and its agreements (based on the $45.55
closing market price of our common units on January 18, 2005, as reported on
the New York Stock Exchange). Also, consistent with the plan, the remaining
$40,000 cash compensation and the $37.50 of cash compensation that did not
equate to a whole common unit, based on the January 18, 2005 $45.55 closing
price, was paid to each of the non-employee directors as described above. No
other compensation was paid to the non-employee directors during 2005.

On January
17, 2006, each of KMRs three non-employee directors was awarded cash compensation
of $160,000 for board service during 2006. Effective January 17, 2006, each
non-employee director elected to receive compensation of $87,780 in the
form of our common units and was issued 1,750 common units pursuant to the plan
and its agreements (based on the $50.16 closing market price of our common
units on January 17, 2006, as reported on the New York Stock Exchange). The
remaining $72,220 cash compensation was paid to each of the non-employee
directors as described above. No other compensation was paid to the
non-employee directors during 2006.

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On January
17, 2007, each of KMRs three non-employee directors was awarded cash
compensation of $160,000 for board service during 2007. Effective January 17,
2007, each non-employee director elected to receive certain amounts of
compensation in the form of our common units and each were issued common units
pursuant to the plan and its agreements (based on the $48.44 closing market
price of our common units on January 17, 2007, as reported on the New York
Stock Exchange). Mr. Gaylord elected to receive compensation of $95,911.20
in the form of our common units and was issued 1,980 common units; Mr. Waughtal
elected to receive compensation of $159,852.00 in the form of our common
units and was issued 3,300 common units; and Mr. Hultquist elected to receive
compensation of $96,880.00 in the form of our common units and was issued
2,000 common units. All remaining cash compensation ($64,088.80 to Mr. Gaylord;
$148.00 to Mr. Waughtal; and $63,120.00 to Mr. Hultquist) was paid to each of
the non-employee directors as described above, and no other compensation was
paid to the non-employee directors during 2007.

On January
16, 2008, each of KMRs three non-employee directors was awarded cash
compensation of $160,000 for board service during 2008; however, during a plan
audit it was determined that each director was inadvertently paid an additional
dividend in 2007. As a result, each directors cash compensation for service
during 2008 was adjusted downward to reflect this error. The correction results
in cash compensation awarded for 2008 in the amounts of $158,380.00 for Mr.
Hultquist; $158,396.20 for Mr. Gaylord; and $157,327.00 for Mr. Waughtal.
Effective January 16, 2008, two of the three non-employee directors elected to
receive certain amounts of compensation in the form of our common units
and each was issued common units pursuant to the plan and its agreements (based
on the $55.81 closing market price of our common units on January 16, 2008, as
reported on the New York Stock Exchange). Mr. Gaylord elected to receive
compensation of $84,831.20 in the form of our common units and was issued 1,520
common units; and Mr. Waughtal elected to receive compensation of
$157,272.58 in the form of our common units and was issued 2,818 common units.
All remaining cash compensation ($73,565.00 to Mr. Gaylord; $54.42 to Mr.
Waughtal; and $158,380.00 to Mr. Hultquist) will be paid to each of the
non-employee directors as described above, and no other compensation will be
paid to the non-employee directors during 2008.

14.
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, and we account for these hedging transactions according to the
provisions of SFAS No. 133, Accounting for Derivative Instruments and Hedging
Activities and associated amendments, collectively, SFAS No. 133.

Energy
Commodity Price Risk Management

We
are exposed to risks associated with unfavorable 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 associated
with unfavorable 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.

Given
our portfolio of businesses as of December 31, 2007, our principal use of
energy commodity derivative contracts was to mitigate the risk associated with
market movements in the price of energy commodities. The unfavorable price
changes are often caused by shifts in the supply and demand for these
commodities, as well as their locations. 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.

Hedging
effectiveness and ineffectiveness

Pursuant
to SFAS No. 133, our energy commodity derivative contracts are designated as
cash flow hedges and for cash flow hedges, the portion of the change in the
value of derivative contracts that is effective in offsetting undesired changes
in expected cash flows (the effective portion) is reported as a component of
other comprehensive

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income
(outside current earnings, net income), but only to the extent that they can
later offset the undesired changes in expected cash flows during the period in
which the hedged cash flows affect earnings. To the contrary, the portion of
the change in the value of derivative contracts that is not effective in
offsetting undesired changes in expected cash flows (the ineffective portion),
as well as any component excluded from the computation of the effectiveness of
the derivative contracts, is required to be recognized currently in earnings.
Reflecting the portion of changes in the value of derivative contracts that
were not effective in offsetting underlying changes in expected cash flows (the
ineffective portion of hedges), we recognized a loss of $0.1 million during
2007, a loss of $1.3 million during 2006 and a loss of $0.6 million during
2005, respectively. These recognized losses resulting from hedge
ineffectiveness are reported within the captions Natural gas sales, Gas
purchases and other costs of sales, and Product sales and other in our
accompanying consolidated statements of income, and for each of the years ended
2007, 2006 and 2005, we did not exclude any component of the derivative
contracts gain or loss from the assessment of hedge effectiveness.

During
the years 2007, 2006 and 2005, we reclassified $433.2 million, $428.1 million
and $424.0 million, respectively, of Accumulated other comprehensive loss
into earnings. With the exception of (i) an approximate $0.1 million loss
reclassified in the first quarter of 2007; and (ii) a $2.9 million loss
resulting from the discontinuance of cash flow hedges related to the sale of
our Douglas gathering assets in 2006 (described in Note 3), none of the
reclassification of Accumulated other comprehensive loss into earnings during
2007, 2006 or 2005 resulted from the discontinuance of cash flow hedges due to
a determination that the 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 resulted from the hedged forecasted
transactions actually affecting earnings (for example, when the forecasted
sales and purchases actually occurred).

Our
consolidated Accumulated other comprehensive loss balance was $1,276.6
million as of December 31, 2007 and $866.1 million as of December 31, 2006.
These consolidated totals included Accumulated other comprehensive loss
amounts associated with the commodity price risk management activities of
$1,377.2 million as of December 31, 2007 and $838.7 million as of December 31,
2006. Approximately $553.3 million of this total accumulated loss associated
with our commodity price risk management activities as of December 31, 2007 is
expected to be reclassified into earnings during the next twelve months (when
the associated forecasted sales and purchases are also expected to occur).

Fair
Value of Energy Commodity Derivative Contracts

The
fair values of the energy commodity derivative contracts we use, including commodity
futures and options contracts, fixed price swaps, and basis swaps are included
in our accompanying consolidated balance sheets within Other current assets,
Deferred charges and other assets, Accrued other current liabilities, and
Other long-term liabilities and deferred credits. The following table
summarizes the fair values of our energy commodity derivative contracts
associated with our commodity price risk management activities and included on
our accompanying consolidated balance sheets as of December 31, 2007 and
December 31, 2006 (in millions):

|                                                 |  |                   |   |                   |   |  |  |   |        |   | 
|------------------------------------------------ |  | ----------------- | - | ----------------- | - |  |  | - | ------ | - | 
|                                                 |  | December
 31,2007 |   | December
 31,2006 |  
|                                                 |  |                   |   |                   |  
|Derivatives-net
 asset/(liability)               |  |                   |   |                   |   |  |  |   |        |   | 
|Other current
assets                             |  |                   | $ | 37.0              |   |  |  | $ | 91.9   |   | 
|Deferred
charges and other assets                |  |                   |   | 4.4               |   |  |  |   | 12.7   |   | 
|Accrued other
current liabilities                |  |                   |   | (593.9            | ) |  |  |   | (431.4 | ) | 
|Other long-term
liabilities and deferred credits |  |                   | $ | (836.8            | ) |  |  | $ | (510.2 | ) | 

As
of December 31, 2007, the maximum length of time over which we have hedged our
exposure to the variability in future cash flows associated with commodity
price risk is through December 2012.

Credit
Risks

We
have counterparty credit risk as a result of our use of energy commodity
derivative contracts. Our over-the-counter swaps and options are contracts we
entered into with counterparties outside centralized trading facilities such as
a futures, options or stock exchange. These contracts are with a number of
parties, all of which had investment grade credit ratings as of December 31,
2007. We both owe money and are owed money under these

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derivative
contracts. While we enter into derivative contracts principally with investment
grade counterparties and actively monitor their credit ratings, it is
nevertheless possible that from time to time losses will result from
counterparty credit risk in the future.

Additionally,
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, 2007 and December 31, 2006, we had three
outstanding letters of credit totaling $298.0 million and $243.0 million,
respectively, in support of our hedging of commodity price risks associated
with the sale of natural gas, natural gas liquids and crude oil.

As
of December 31, 2007, we had cash margin deposits associated with our commodity
contract positions and over-the-counter swap partners totaling $67.9 million,
and we reported this amount as Restricted deposits in our accompanying
consolidated balance sheet as of December 31, 2007. As of December 31, 2006, our
counterparties associated with our commodity contract positions and
over-the-counter swap agreements had margin deposits with us totaling $2.3
million, and we reported this amount within Accrued other liabilities in our
accompanying consolidated balance sheet as of December 31, 2006.

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
floating 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.

As of
December 31, 2006, we were a party to interest rate swap agreements with
notional principal amounts of $2.1 billion. In the first six
months of 2007, we both entered into additional fixed-to-floating interest rate
swap agreements having a combined notional principal amount of $500 million and
terminated an existing fixed-to-floating interest rate swap agreement having a
notional principal amount of $100 million and a maturity date of March 15,
2032. We received $15.0 million from the early termination of this swap
agreement, and this amount is being amortized over the remaining term of the
original swap period.

On
August 15, 2007, two separate fixed-to-floating interest rate swap agreements
having a combined notional principal amount of $200 million matured, and as of
December 31, 2007, we had a combined notional principal amount of $2.3 billion
of fixed-to-floating 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. The
two swap agreements that matured on August 15, 2007 were associated with the $250
million of 5.35% senior notes that also matured on that date. In February 2007,
we entered into additional fixed-to-floating interest rate swap agreements
having a combined notional principal amount of $600 million. These swap
agreements were related to the $600 million of 5.95% senior notes we issued on
February 12, 2008, and have a maturity date of February 15, 2018.

All
of our interest rate swap agreements have a termination date that corresponds
to the maturity date of one of our series of senior notes and, as of December
31, 2007, 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. In addition, certain of our swap agreements
contain mutual cash-out provisions that allow us or our counterparties to
settle the agreement at certain future dates before maturity based on the
then-economic value of the swap agreement.

171

---



Hedging
effectiveness and ineffectiveness

Our
interest rate swap contracts have been designated as fair value hedges and meet
the conditions required to assume no ineffectiveness under SFAS No. 133.
Therefore, we have accounted for them using the shortcut method prescribed by
SFAS No. 133 and accordingly, we adjust the carrying value of each swap
contract to its fair value each quarter, with an offsetting entry to adjust the
carrying value of the debt securities whose fair value is being hedged. We
record interest expense equal to the variable rate payments under the swap
contracts.

Fair
Value of Interest Rate Swap Agreements

The
fair values of our interest rate swap agreements are included within Deferred
charges and other assets and Other long-term liabilities and deferred
credits in our accompanying consolidated balance sheets. 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 December 31, 2007, this unamortized premium totaled $14.2 million,
representing the unamortized proceeds we received from the swap agreement we
terminated in the first quarter of 2007.

The
following table summarizes the net fair value of our interest rate swap
agreements associated with our interest rate risk management activities and
included on our accompanying consolidated balance sheets as of December 31,
2007 and December 31, 2006 (in millions):

|                                                 |  |                   |   |                   |  |  |  |   |       |   | 
|------------------------------------------------ |  | ----------------- | - | ----------------- |  |  |  | - | ----- | - | 
|                                                 |  | December
 31,2007 |   | December
 31,2006 | 
|                                                 |  |                   |   |                   | 
|Derivatives-net
 asset/(liability)               |  |                   |   |                   |  |  |  |   |       |   | 
|Deferred
charges and other assets                |  |                   | $ | 138.0             |  |  |  | $ | 65.2  |   | 
|Other long-term
liabilities and deferred credits |  |                   |   |                  |  |  |  |   | (22.6 | ) | 
|                                                 |  |                   |   |                   |  |  |  |   |       |   | 
|Net fair value
of interest rate swaps            |  |                   | $ | 138.0             |  |  |  | $ | 42.6  |   | 
|                                                 |  |                   |   |                   |  |  |  |   |       |   | 

Furthermore,
we are exposed to credit related losses in the event of nonperformance by
counterparties to our interest rate swap agreements, and while we enter into
derivative contracts primarily with investment grade counterparties and
actively monitor their credit ratings, it is nevertheless possible that from
time to time losses will result from counterparty credit risk. As of December
31, 2007, all of our interest rate swap agreements were with counterparties
with investment grade credit ratings.

Other

Certain
of our business activities expose us to foreign currency fluctuations. However,
due to the limited size of this exposure, we do not believe the risks
associated with changes in foreign currency will have a material adverse effect on our business, financial position,
results of operations or cash flows. As a result, we do not significantly hedge
our exposure to fluctuations in foreign currency.

15.
Reportable Segments

We
divide our operations into five reportable business segments:

| |   |                        
| | - | -----------------------
| |  | Products
 Pipelines;   
| |   |                        
| |  | Natural Gas
 Pipelines;
| |   |                        
| |  | CO2;                   
| |   |                        
| |  | Terminals;
 and        
| |   |                        
| |  | Trans
 Mountain.       

172

---



Each
segment uses the same accounting policies as those described in the summary of
significant accounting policies (see Note 2). We evaluate
performance principally based on each segments earnings before depreciation,
depletion and amortization, which excludes general and administrative expenses,
third-party debt costs and interest expense, unallocable interest income and
income tax expense, and minority interest. 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.

Our
Products Pipelines segment derives its revenues primarily from the
transportation and terminaling of refined petroleum products, including
gasoline, diesel fuel, jet fuel and natural gas liquids. Our Natural Gas
Pipelines segment derives its revenues primarily from the sale, transport,
processing, treating, storage and gathering of natural gas. Our CO2
segment derives its revenues primarily from the production and sale of crude
oil from fields in the Permian Basin of West Texas and from the transportation
and marketing of carbon dioxide used as a flooding medium for recovering crude
oil from mature oil fields. Our Terminals segment derives its revenues
primarily from 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. Our Trans Mountain business segment derives its
revenues primarily from the transportation of crude oil and refined products
from Edmonton, Alberta to marketing terminals and refineries in the Greater
Vancouver area and Puget Sound in Washington State.

As
discussed in Note 3, due to the sale of our North System, an approximate
1,600-mile interstate common carrier pipeline system whose operating results
were included as part of our Products Pipelines business segment, we accounted
for the North System business as a discontinued operation. Consistent with the management approach of
identifying and reporting discrete financial information on operating segments,
we have included the North Systems financial results within our Products
Pipelines business segment disclosures for all periods presented in this
report and, as prescribed by SFAS No. 131, we have reconciled the total of our
reportable segments financial results to our consolidated financial results by
separately identifying, in the following pages where applicable, the North System
amounts as discontinued operations.

Financial
information by segment follows (in millions):

|                                    |  |      |         |      |   |         |   |   |         |  
|----------------------------------- |  | ---- | ------- | ---- | - | ------- | - | - | ------- | -
|                                    |  | 2007 |         | 2006 |   | 2005    |  
|                                    |  |      |         |      |   |         |  
|Revenues                            |  |      |         |      |   |         |   |   |         |  
|Products
Pipelines                  |  |      |         |      |   |         |   |   |         |  
|Revenues from
external
  customers  |  | $    | 844.4   |      | $ | 776.3   |   | $ | 711.8   |  
|Intersegment
revenues               |  |      |        |      |   |        |   |   |        |  
|Natural Gas
Pipelines               |  |      |         |      |   |         |   |   |         |  
|Revenues from
external
  customers  |  |      | 6,466.5 |      |   | 6,577.7 |   |   | 7,718.4 |  
|Intersegment
revenues               |  |      |        |      |   |        |   |   |        |  
|CO2                                 |  |      |         |      |   |         |   |   |         |  
|Revenues from
external
  customers  |  |      | 824.1   |      |   | 736.5   |   |   | 657.6   |  
|Intersegment
revenues               |  |      |        |      |   |        |   |   |        |  
|Terminals                           |  |      |         |      |   |         |   |   |         |  
|Revenues from
external
  customers  |  |      | 963.0   |      |   | 864.1   |   |   | 699.3   |  
|Intersegment
revenues               |  |      | 0.7     |      |   | 0.7     |   |   |        |  
|Trans Mountain                      |  |      |         |      |   |         |   |   |         |  
|Revenues from
external
  customers  |  |      | 160.8   |      |   | 137.8   |   |   |        |  
|Intersegment
revenues               |  |      |        |      |   |        |   |   |        |  
|                                    |  |      |         |      |   |         |   |   |         |  
|Total segment
revenues              |  |      | 9,259.5 |      |   | 9,093.1 |   |   | 9,787.1 |  
|Less: Total
intersegment
  revenues |  |      | (0.7    | )    |   | (0.7    | ) |   |        |  
|                                    |  |      |         |      |   |         |   |   |         |  
|                                    |  |      | 9,258.8 |      |   | 9,092.4 |   |   | 9,787.1 |  
|Less:
Discontinued operations       |  |      | (41.1   | )    |   | (43.7   | ) |   | (41.2   | )
|                                    |  |      |         |      |   |         |   |   |         |  
|Total
consolidated revenues         |  | $    | 9,217.7 |      | $ | 9,048.7 |   | $ | 9,745.9 |  
|                                    |  |      |         |      |   |         |   |   |         |  

173

---



|                                                        |  |      |         |      |   |         |   |   |         |  
|------------------------------------------------------- |  | ---- | ------- | ---- | - | ------- | - | - | ------- | -
|                                                        |  | 2007 |         | 2006 |   | 2005    |  
|                                                        |  |      |         |      |   |         |  
|Operating expenses(a)                                   |  |      |         |      |   |         |   |   |         |  
|Products
Pipelines                                      |  | $    | 451.8   |      | $ | 308.3   |   | $ | 366.0   |  
|Natural Gas
Pipelines                                   |  |      | 5,882.9 |      |   | 6,057.8 |   |   | 7,255.0 |  
|CO2                                                     |  |      | 304.2   |      |   | 268.1   |   |   | 212.6   |  
|Terminals                                               |  |      | 536.4   |      |   | 461.9   |   |   | 373.4   |  
|Trans
Mountain                                          |  |      | 65.9    |      |   | 53.3    |   |   |        |  
|                                                        |  |      |         |      |   |         |   |   |         |  
|Total segment
operating
  expenses                      |  |      | 7,241.2 |      |   | 7,149.4 |   |   | 8,207.0 |  
|Less: Total
intersegment
  operating expenses           |  |      | (0.7    | )    |   | (0.7    | ) |   |        |  
|                                                        |  |      |         |      |   |         |   |   |         |  
|                                                        |  |      | 7,240.5 |      |   | 7,148.7 |   |   | 8,207.0 |  
|Less:
Discontinued operations                           |  |      | (14.8   | )    |   | (22.7   | ) |   | (35.2   | )
|                                                        |  |      |         |      |   |         |   |   |         |  
|Total
consolidated operating
  expenses                 |  | $    | 7,225.7 |      | $ | 7,126.0 |   | $ | 8,171.8 |  
|                                                        |  |      |         |      |   |         |   |   |         |  
|                                                        |  |      |         |      |   |         |   |   |         |  
|Other expense (income)                                  |  |      |         |      |   |         |   |   |         |  
|Products
Pipelines                                      |  | $    | (154.8  | )    | $ |        |   | $ |        |  
|Natural Gas
Pipelines                                   |  |      | (3.2    | )    |   | (15.1   | ) |   |        |  
|CO2                                                     |  |      |        |      |   |        |   |   |        |  
|Terminals                                               |  |      | (6.3    | )    |   | (15.2   | ) |   |        |  
|Trans
Mountain(b)                                       |  |      | 377.1   |      |   | (0.9    | ) |   |        |  
|                                                        |  |      |         |      |   |         |   |   |         |  
|Total segment
Other expense
  (income)                  |  |      | 212.8   |      |   | (31.2   | ) |   |        |  
|Less:
Discontinued operations                           |  |      | 152.8   |      |   |        |   |   |        |  
|                                                        |  |      |         |      |   |         |   |   |         |  
|Total
consolidated Other
  expense (income)             |  | $    | 365.6   |      | $ | (31.2   | ) | $ |        |  
|                                                        |  |      |         |      |   |         |   |   |         |  
|                                                        |  |      |         |      |   |         |   |   |         |  
|Depreciation, depletion and amortization                |  |      |         |      |   |         |   |   |         |  
|Products
Pipelines                                      |  | $    | 89.2    |      | $ | 82.9    |   | $ | 79.1    |  
|Natural Gas
Pipelines                                   |  |      | 64.8    |      |   | 65.4    |   |   | 61.7    |  
|CO2                                                     |  |      | 282.2   |      |   | 190.9   |   |   | 149.9   |  
|Terminals                                               |  |      | 89.3    |      |   | 74.6    |   |   | 59.1    |  
|Trans
Mountain                                          |  |      | 21.5    |      |   | 19.0    |   |   |        |  
|                                                        |  |      |         |      |   |         |   |   |         |  
|Total segment
depreciation,
  depletion and amortiz.    |  |      | 547.0   |      |   | 432.8   |   |   | 349.8   |  
|Less:
Discontinued operations                           |  |      | (7.0    | )    |   | (8.9    | ) |   | (8.2    | )
|                                                        |  |      |         |      |   |         |   |   |         |  
|Total consol.
depreciation,
  depletion and amortiz.    |  | $    | 540.0   |      | $ | 423.9   |   | $ | 341.6   |  
|                                                        |  |      |         |      |   |         |   |   |         |  
|                                                        |  |      |         |      |   |         |   |   |         |  
|Earnings from equity investments                        |  |      |         |      |   |         |   |   |         |  
|Products
Pipelines                                      |  | $    | 32.5    |      | $ | 16.3    |   | $ | 28.5    |  
|Natural Gas
Pipelines                                   |  |      | 19.2    |      |   | 40.5    |   |   | 36.8    |  
|CO2                                                     |  |      | 19.2    |      |   | 19.2    |   |   | 26.3    |  
|Terminals                                               |  |      | 0.6     |      |   | 0.2     |   |   | 0.1     |  
|Trans
Mountain                                          |  |      |        |      |   |        |   |   |        |  
|                                                        |  |      |         |      |   |         |   |   |         |  
|Total segment
earnings from
  equity investments        |  |      | 71.5    |      |   | 76.2    |   |   | 91.7    |  
|Less:
Discontinued operations                           |  |      | (1.8    | )    |   | (2.2    | ) |   | (2.1    | )
|                                                        |  |      |         |      |   |         |   |   |         |  
|Total
consolidated equity
  earnings                    |  | $    | 69.7    |      | $ | 74.0    |   | $ | 89.6    |  
|                                                        |  |      |         |      |   |         |   |   |         |  
|                                                        |  |      |         |      |   |         |   |   |         |  
|Amortization of excess cost of equity investments       |  |      |         |      |   |         |   |   |         |  
|Products
Pipelines                                      |  | $    | 3.4     |      | $ | 3.4     |   | $ | 3.4     |  
|Natural Gas
Pipelines                                   |  |      | 0.4     |      |   | 0.3     |   |   | 0.2     |  
|CO2                                                     |  |      | 2.0     |      |   | 2.0     |   |   | 2.0     |  
|Terminals                                               |  |      |        |      |   |        |   |   |        |  
|Trans
Mountain                                          |  |      |        |      |   |        |   |   |        |  
|                                                        |  |      |         |      |   |         |   |   |         |  
|Total segment
amortization of
  excess cost of invests. |  |      | 5.8     |      |   | 5.7     |   |   | 5.6     |  
|Less:
Discontinued operations                           |  |      |        |      |   | (0.1    | ) |   | (0.1    | )
|                                                        |  |      |         |      |   |         |   |   |         |  
|Total consol.
amortization of
  excess cost of invests. |  | $    | 5.8     |      | $ | 5.6     |   | $ | 5.5     |  
|                                                        |  |      |         |      |   |         |   |   |         |  
|                                                        |  |      |         |      |   |         |   |   |         |  
|Interest income                                         |  |      |         |      |   |         |   |   |         |  
|Products
Pipelines                                      |  | $    | 4.4     |      | $ | 4.5     |   | $ | 4.6     |  
|Natural Gas
Pipelines                                   |  |      |        |      |   | 0.1     |   |   | 0.7     |  
|CO2                                                     |  |      |        |      |   |        |   |   |        |  
|Terminals                                               |  |      |        |      |   |        |   |   |        |  
|Trans
Mountain                                          |  |      |        |      |   |        |   |   |        |  
|                                                        |  |      |         |      |   |         |   |   |         |  
|Total segment
interest income                           |  |      | 4.4     |      |   | 4.6     |   |   | 5.3     |  
|Unallocated
interest income                             |  |      | 1.3     |      |   | 3.1     |   |   | 4.1     |  
|                                                        |  |      |         |      |   |         |   |   |         |  
|Total
consolidated interest
  income                    |  | $    | 5.7     |      | $ | 7.7     |   | $ | 9.4     |  
|                                                        |  |      |         |      |   |         |   |   |         |  

174

---



|                                                                                                                         |  |      |         |      |   |         |   |   |         |  
|------------------------------------------------------------------------------------------------------------------------ |  | ---- | ------- | ---- | - | ------- | - | - | ------- | -
|                                                                                                                         |  | 2007 |         | 2006 |   | 2005    |  
|                                                                                                                         |  |      |         |      |   |         |  
|Other, net-income (expense)                                                                                              |  |      |         |      |   |         |   |   |         |  
|Products
Pipelines                                                                                                       |  | $    | 5.0     |      | $ | 7.6     |   | $ | 1.5     |  
|Natural Gas
Pipelines                                                                                                    |  |      | 0.2     |      |   | 0.6     |   |   | 2.0     |  
|CO2                                                                                                                      |  |      |        |      |   | 0.8     |   |   |        |  
|Terminals                                                                                                                |  |      | 1.0     |      |   | 2.1     |   |   | (0.2    | )
|Trans
Mountain                                                                                                           |  |      | 8.0     |      |   | 1.0     |   |   |        |  
|                                                                                                                         |  |      |         |      |   |         |   |   |         |  
|Total segment
other, net-income
  (expense)                                                                              |  |      | 14.2    |      |   | 12.1    |   |   | 3.3     |  
|Less:
Discontinued operations                                                                                            |  |      |        |      |   | (0.1    | ) |   |        |  
|                                                                                                                         |  |      |         |      |   |         |   |   |         |  
|Total
consolidated other,
  net-income (expense)                                                                         |  | $    | 14.2    |      | $ | 12.0    |   | $ | 3.3     |  
|                                                                                                                         |  |      |         |      |   |         |   |   |         |  
|                                                                                                                         |  |      |         |      |   |         |   |   |         |  
|Income tax benefit (expense)                                                                                             |  |      |         |      |   |         |   |   |         |  
|Products
Pipelines                                                                                                       |  | $    | (19.7   | )    | $ | (5.2    | ) | $ | (10.3   | )
|Natural Gas
Pipelines                                                                                                    |  |      | (6.0    | )    |   | (1.4    | ) |   | (2.6    | )
|CO2                                                                                                                      |  |      | (2.1    | )    |   | (0.2    | ) |   | (0.4    | )
|Terminals                                                                                                                |  |      | (19.2   | )    |   | (12.3   | ) |   | (11.2   | )
|Trans
Mountain                                                                                                           |  |      | (19.4   | )    |   | (9.9    | ) |   |        |  
|                                                                                                                         |  |      |         |      |   |         |   |   |         |  
|Total segment
income tax
  benefit (expense)                                                                             |  |      | (66.4   | )    |   | (29.0   | ) |   | (24.5   | )
|Unallocated
income tax benefit
  (expense)                                                                               |  |      | (4.6    | )    |   |        |   |   |        |  
|                                                                                                                         |  |      |         |      |   |         |   |   |         |  
|Total
consolidated income tax
  benefit (expense)                                                                        |  | $    | (71.0   | )    | $ | (29.0   | ) | $ | (24.5   | )
|                                                                                                                         |  |      |         |      |   |         |   |   |         |  
|                                                                                                                         |  |      |         |      |   |         |   |   |         |  
|Segment earnings(c)                                                                                                      |  |      |         |      |   |         |   |   |         |  
|Products
Pipelines                                                                                                       |  | $    | 477.0   |      | $ | 404.9   |   | $ | 287.6   |  
|Natural Gas
Pipelines                                                                                                    |  |      | 535.0   |      |   | 509.1   |   |   | 438.4   |  
|CO2                                                                                                                      |  |      | 252.8   |      |   | 295.3   |   |   | 319.0   |  
|Terminals                                                                                                                |  |      | 326.7   |      |   | 333.5   |   |   | 255.5   |  
|Trans
Mountain                                                                                                           |  |      | (315.1  | )    |   | 57.5    |   |   |        |  
|                                                                                                                         |  |      |         |      |   |         |   |   |         |  
|Total segment
earnings                                                                                                   |  |      | 1,276.4 |      |   | 1,600.3 |   |   | 1,300.5 |  
|Interest and corporate administrative expenses(d)                                                                        |  |      | (686.1  | )    |   | (596.2  | ) |   | (488.3  | )
|                                                                                                                         |  |      |         |      |   |         |   |   |         |  
|Total
consolidated net income                                                                                            |  | $    | 590.3   |      | $ | 1,004.1 |   | $ | 812.2   |  
|                                                                                                                         |  |      |         |      |   |         |   |   |         |  
|                                                                                                                         |  |      |         |      |   |         |   |   |         |  
|Segment earnings before
  depreciation, depletion, amortization and amortization of excess cost of equity
investments(e) |  |      |         |      |   |         |   |   |         |  
|Products
Pipelines                                                                                                       |  | $    | 569.6   |      | $ | 491.2   |   | $ | 370.1   |  
|Natural Gas
Pipelines                                                                                                    |  |      | 600.2   |      |   | 574.8   |   |   | 500.3   |  
|CO2                                                                                                                      |  |      | 537.0   |      |   | 488.2   |   |   | 470.9   |  
|Terminals                                                                                                                |  |      | 416.0   |      |   | 408.1   |   |   | 314.6   |  
|Trans
Mountain                                                                                                           |  |      | (293.6  | )    |   | 76.5    |   |   |        |  
|                                                                                                                         |  |      |         |      |   |         |   |   |         |  
|Total segment
earnings before
  DD&A                                                                                     |  |      | 1,829.2 |      |   | 2,038.8 |   |   | 1,655.9 |  
|Total segment
depreciation,
  depletion and amortiz.                                                                     |  |      | (547.0  | )    |   | (432.8  | ) |   | (349.8  | )
|Total segment
amortization of
  excess cost of invests.                                                                  |  |      | (5.8    | )    |   | (5.7    | ) |   | (5.6    | )
|Interest and
corporate
  administrative expenses                                                                         |  |      | (686.1  | )    |   | (596.2  | ) |   | (488.3  | )
|                                                                                                                         |  |      |         |      |   |         |   |   |         |  
|Total
consolidated net income                                                                                            |  | $    | 590.3   |      | $ | 1,004.1 |   | $ | 812.2   |  
|                                                                                                                         |  |      |         |      |   |         |   |   |         |  
|                                                                                                                         |  |      |         |      |   |         |   |   |         |  
|Capital expenditures(f)                                                                                                  |  |      |         |      |   |         |   |   |         |  
|Products
Pipelines                                                                                                       |  | $    | 259.4   |      | $ | 196.0   |   | $ | 271.5   |  
|Natural Gas
Pipelines                                                                                                    |  |      | 264.0   |      |   | 271.6   |   |   | 102.9   |  
|CO2                                                                                                                      |  |      | 382.5   |      |   | 283.0   |   |   | 302.1   |  
|Terminals                                                                                                                |  |      | 480.0   |      |   | 307.7   |   |   | 186.6   |  
|Trans
Mountain                                                                                                           |  |      | 305.7   |      |   | 123.8   |   |   |        |  
|                                                                                                                         |  |      |         |      |   |         |   |   |         |  
|Total
consolidated capital
  expenditures                                                                                |  | $    | 1,691.6 |      | $ | 1,182.1 |   | $ | 863.1   |  
|                                                                                                                         |  |      |         |      |   |         |   |   |         |  
|                                                                                                                         |  |      |         |      |   |         |   |   |         |  
|Investments at December 31                                                                                               |  |      |         |      |   |         |   |   |         |  
|Products
Pipelines                                                                                                       |  | $    | 202.3   |      | $ | 211.1   |   | $ | 223.7   |  
|Natural Gas
Pipelines                                                                                                    |  |      | 427.5   |      |   | 197.9   |   |   | 177.1   |  
|CO2                                                                                                                      |  |      | 14.2    |      |   | 16.1    |   |   | 17.9    |  
|Terminals                                                                                                                |  |      | 10.6    |      |   | 0.5     |   |   | 0.6     |  
|Trans
Mountain                                                                                                           |  |      | 0.8     |      |   | 0.7     |   |   |        |  
|                                                                                                                         |  |      |         |      |   |         |   |   |         |  
|Total
consolidated investments                                                                                           |  | $    | 655.4   |      | $ | 426.3   |   | $ | 419.3   |  
|                                                                                                                         |  |      |         |      |   |         |   |   |         |  

175

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|                          |  |      |          |      |   |          |  |   |          | 
|------------------------- |  | ---- | -------- | ---- | - | -------- |  | - | -------- | 
|                          |  | 2007 |          | 2006 |   | 2005     | 
|                          |  |      |          |      |   |          | 
|Assets at December 31     |  |      |          |      |   |          |  |   |          | 
|Products
Pipelines        |  | $    | 4,045.0  |      | $ | 3,910.5  |  | $ | 3,873.9  | 
|Natural Gas
Pipelines     |  |      | 4,347.3  |      |   | 3,946.6  |  |   | 4,140.0  | 
|CO2                       |  |      | 2,004.5  |      |   | 1,870.8  |  |   | 1,772.8  | 
|Terminals                 |  |      | 3,036.4  |      |   | 2,397.5  |  |   | 2,052.5  | 
|Trans
Mountain            |  |      | 1,440.8  |      |   | 1,314.0  |  |   |         | 
|                          |  |      |          |      |   |          |  |   |          | 
|Total segment
assets      |  |      | 14,874.0 |      |   | 13,439.4 |  |   | 11,839.2 | 
|Corporate
assets(g)       |  |      | 303.8    |      |   | 102.8    |  |   | 84.3     | 
|                          |  |      |          |      |   |          |  |   |          | 
|Total
consolidated assets |  | $    | 15,177.8 |      | $ | 13,542.2 |  | $ | 11,923.5 | 
|                          |  |      |          |      |   |          |  |   |          | 

|    |                                                                                                                                                                                                                                                                                                                                                                               
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(a) | Includes natural gas
  purchases and other costs of sales, operations and maintenance expenses, fuel
  and power expenses and taxes, other than income taxes.                                                                                                                                                                                                                 
|    |                                                                                                                                                                                                                                                                                                                                                                               
|(b) | 2007 amount represents an
  expense of $377.1 million attributable to a goodwill impairment charge
  recognized by Knight, as discussed in Notes 3 and 8.                                                                                                                                                                                                                     
|    |                                                                                                                                                                                                                                                                                                                                                                               
|(c) | Includes revenues, earnings
  from equity investments, allocable interest income, and other, net, less
  operating expenses, allocable income taxes, other expense (income), depreciation,
  depletion and amortization, and amortization of excess cost of equity
  investments.                                                                                             
|    |                                                                                                                                                                                                                                                                                                                                                                               
|(d) | Includes unallocated
  interest income and income tax expense, interest and debt expense, general
  and administrative expenses, and minority interest expense.                                                                                                                                                                                                               
|    |                                                                                                                                                                                                                                                                                                                                                                               
|(e) | Includes revenues, earnings
  from equity investments, allocable interest income, and other, net, less
  operating expenses, allocable income taxes, and other expense (income).                                                                                                                                                                                              
|    |                                                                                                                                                                                                                                                                                                                                                                               
|(f) | Includes sustaining capital
  expenditures of $152.6 million in 2007 (not including Trans Mountain for
  periods prior to our acquisition date of April 30, 2007), $125.5 million in
  2006 (not including Trans Mountain) and $140.8 million in 2005. Sustaining
  capital expenditures are defined as capital expenditures which do not
  increase the capacity of an asset.
|    |                                                                                                                                                                                                                                                                                                                                                                               
|(g) | Includes cash and cash
  equivalents, margin and restricted deposits, certain unallocable deferred
  charges, and risk management assets related to the fair value of interest
  rate swaps.                                                                                                                                                                                  

We
do not attribute interest and debt expense to any of our reportable business
segments. For each of the years ended December 31, 2007, 2006 and 2005, we
reported (in millions) total consolidated interest expense of $397.1 million,
$345.5 million and $268.4 million, respectively.

Our
total operating revenues are derived from a wide customer base. For each of the three years ended December
31, 2007, 2006 and 2005, no revenues from transactions with a single external
customer amounted to 10% or more of our total consolidated revenues.

Following
is geographic information regarding the revenues and long-lived assets of our
business segments (in millions):

|                                               |  |      |          |      |   |          |  |   |         | 
|---------------------------------------------- |  | ---- | -------- | ---- | - | -------- |  | - | ------- | 
|                                               |  | 2007 |          | 2006 |   | 2005     | 
|                                               |  |      |          |      |   |          | 
|Revenues from external
customers               |  |      |          |      |   |          |  |   |         | 
|United
States                                  |  | $    | 8,986.3  |      | $ | 8,889.9  |  | $ | 9,715.1 | 
|Canada                                         |  |      | 211.9    |      |   | 139.3    |  |   | 11.8    | 
|Mexico and
other(a)                            |  |      | 19.5     |      |   | 19.5     |  |   | 19.0    | 
|                                               |  |      |          |      |   |          |  |   |         | 
|Total consol.
revenues from external customers |  | $    | 9,217.7  |      | $ | 9,048.7  |  | $ | 9,745.9 | 
|                                               |  |      |          |      |   |          |  |   |         | 
|                                               |  |      |          |      |   |          |  |   |         | 
|Long-lived assets at December
31(b)            |  |      |          |      |   |          |  |   |         | 
|United
States                                  |  | $    | 11,054.3 |      | $ | 9,917.2  |  | $ | 9,442.8 | 
|Canada                                         |  |      | 1,420.0  |      |   | 766.4    |  |   | 48.2    | 
|Mexico and
other                               |  |      | 89.5     |      |   | 91.4     |  |   | 92.3    | 
|                                               |  |      |          |      |   |          |  |   |         | 
|Total
consolidated long-lived assets           |  | $    | 12,563.8 |      | $ | 10,775.0 |  | $ | 9,583.3 | 
|                                               |  |      |          |      |   |          |  |   |         | 

|    |                                                                                                                                    
|--- | -----------------------------------------------------------------------------------------------------------------------------------
|(a) | Includes operations in
  Mexico and the Netherlands.                                                                               
|    |                                                                                                                                    
|(b) | Long-lived assets exclude
  (i) goodwill; (ii) other intangibles, net; and (iii) long-term note
  receivables from related parties.

176

---



16. Litigation, Environmental and Other Contingencies

Below
is a brief description of our ongoing material legal proceedings, including any
material developments that occurred in such proceedings during 2007. This note
also contains a description of any material legal proceeding initiated during
2007 in which we are involved.

Federal
Energy Regulatory Commission Proceedings

Our
SFPP, L.P. and CALNEV Pipe Line LLC subsidiaries are involved in proceedings
before the Federal Energy Regulatory Commission.  SFPP is the
subsidiary limited partnership that owns our Pacific operations.  CALNEV Pipe
Line LLC  and related terminals was acquired from GATX Corporation and is not
part of the Pacific Operations.  The tariffs and rates charged by SFPP and
CALNEV are subject to numerous ongoing proceedings at the Federal Energy
Regulatory Commission, referred to in this report as the FERC, including
shippers complaints and protests regarding interstate rates on these
pipeline systems. In general, these complaints allege the rates and tariffs
charged by SFPP and CALNEV are not just and reasonable.

As to
SFPP, the issues
involved in these proceedings include, among others: (i) whether certain of our
Pacific operations rates are grandfathered under the Energy Policy Act of
1992, referred to in this note as EPAct 1992, and therefore deemed to be just
and reasonable; (ii) whether substantially changed circumstances have
occurred with respect to any grandfathered rates such that those rates could be
challenged; (iii) whether indexed rate increases may become effective without
investigation; (iv) the capital structure to be used in computing the starting
rate base of our Pacific operations; (v) the level of income tax allowance we
may include in our rates; and (vi) the recovery of civil and regulatory
litigation expenses and certain pipeline reconditioning and environmental costs
incurred by our Pacific operations.

In
May 2005, the FERC issued a statement of general policy stating it will permit
pipelines to include in cost of service a tax allowance to reflect actual or
potential tax liability on their public utility income attributable to all
partnership or limited liability company interests, if the ultimate owner of
the interest has an actual or potential income tax liability on such income.
Whether a pipelines owners have such actual or potential income tax liability
will be reviewed by the FERC on a case-by-case basis. Although the new policy
is generally favorable for pipelines that are organized as pass-through
entities, it still entails rate risk due to the case-by-case review
requirement. The new tax allowance policy and the FERCs application of that
policy to our Pacific operations were appealed to the United States Court of
Appeals for the District of Columbia Circuit, referred to in this note as the
D.C. Court.

On
May 29, 2007, the D.C. Court issued an opinion upholding the FERCs tax
allowance policy. Because the extent to which an interstate oil pipeline is
entitled to an income tax allowance is subject to a case-by-case review at the
FERC, the level of income tax allowance to which SFPP will ultimately be
entitled is not certain. The D.C. Courts May 29 decision also upheld the
FERCs determination that a rate is no longer subject to grandfathering
protection under EPAct 1992 when there has been a substantial change in the
overall rate of return of the pipeline, rather than in one cost element.
Further, the D.C. Court declined to consider arguments that there were errors
in the FERCs method for determining substantial change, finding that the
parties had not first raised such allegations with the FERC. On July 13, 2007,
SFPP filed a petition for rehearing with the D.C. Court, arguing that SFPP did
raise allegations with the FERC respecting these calculation errors. The D.C.
Circuit denied rehearing of the May 29, 2007 decision on August 20, 2007, and
the decision is now final.

In
this note, we refer to SFPP, L.P. as SFPP; CALNEV Pipe Line LLC as Calnev;
Chevron Products Company as Chevron; Navajo Refining Company, L.P. as Navajo;
ARCO Products Company as ARCO; BP West Coast Products, LLC as BP WCP; Texaco
Refining and Marketing Inc. as Texaco; Western Refining Company, L.P. as
Western Refining; Mobil Oil Corporation as Mobil; ExxonMobil Oil Corporation as
ExxonMobil; Tosco Corporation as Tosco; ConocoPhillips Company as
ConocoPhillips; Ultramar Diamond Shamrock Corporation as Ultramar; Valero
Energy Corporation as Valero; Valero Marketing and Supply Company as Valero
Marketing; and America West Airlines, Inc., Continental Airlines, Inc.,
Northwest Airlines, Inc., Southwest Airlines Co. and US Airways, Inc.,
collectively, as the Airline Complainants.

177

---



Following is a listing of
certain active FERC proceedings pertaining to our Pacific operations:

|  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      
|- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | FERC Docket No. OR92-8, et al.Complainants/Protestants:
  Chevron; Navajo; ARCO; BP WCP; Western Refining; ExxonMobil; Tosco; and
  Texaco (Ultramar is an intervenor)Defendant: SFPP Consolidated proceeding
  involving shipper complaints against certain East Line and West Line rates.
  All five issues (and others) described four paragraphs above are involved in
  these proceedings. Portions of this proceeding were appealed (and
  re-appealed) to the D.C. Court and remanded to the FERC. BP WCP, Chevron, and
  ExxonMobil requested a hearing before the FERC on remanded grandfathering and
  income tax allowance issues. The FERC issued an Order on Rehearing, Remand,
  Compliance, and Tariff Filings on December 26, 2007, which denied the
  requests for a hearing, affirmed the income tax allowance policy and further
  clarified the implementation of that policy, and required SFPP to file a
  compliance filing;
|  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      
| | FERC Docket Nos.
  OR92-8-028,et al.Complainants/Protestants: BP WCP;
  ExxonMobil; Chevron;                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        
|  | ConocoPhillips; and
  UltramarDefendant: SFPP
  Proceeding involving shipper complaints against
  SFPPs Watson Station rates. A settlement was reached for April 1, 1999
  forward; whether SFPP owes reparations for shipments prior to that date is
  still before the FERC;                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
|  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      
| | FERC Docket No. OR96-2,et al.Complainants/Protestants: All
  Shippers except Chevron (which is an intervenor)Defendant: SFPP Consolidated
  proceeding involving shipper complaints against all SFPP rates. All five
  issues (and others) described four paragraphs above are involved in these
  proceedings. Portions of this proceeding were appealed (and re-appealed) to
  the D.C. Court and remanded to the FERC. The FERC issued an Order on
  Rehearing, Remand, Compliance, and Tariff Filings on December 26, 2007, which
  denied the requests for a hearing, affirmed the income tax allowance policy
  and further clarified the implementation of that policy, and required SFPP to
  file a compliance filing;                                                                                                                                                                                                                    
|  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      
| | FERC Docket Nos. OR02-4
  and OR03-5Complainant/Protestant: ChevronDefendant: SFPP                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|  | Chevron initiated
  proceeding to permit Chevron to become complainant in OR96-2. Appealed to the
  D.C. Court and held in abeyance pending final disposition of the OR96-2
  proceedings;                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
|  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      
| | FERC Docket No.
  OR04-3Complainants/Protestants: America West Airlines; Southwest Airlines;
  Northwest Airlines; and Continental AirlinesDefendant: SFPP Complaint
  alleges that West Line and Watson Station rates are unjust and unreasonable.
  Watson Station issues severed and consolidated into a proceeding focused only
  on Watson-related issues. The FERC has set the complaints against the West
  Line rates for hearing but denied the request to consolidate the dockets with
  the ongoing proceedings involving SFPPs North and Oregon Line rates;                                                                                                                                                                                                                                                                                                                                                                           
|  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      
| | FERC Docket Nos. OR03-5,
  OR05-4 and OR05-5Complainants/Protestants: BP WCP; ExxonMobil; and
  ConocoPhillips (other shippers intervened)Defendant: SFPP Complaints allege
  that SFPPs interstate rates are not just and reasonable. The FERC has set
  the complaints against the West and East Line rates for hearing, but denied
  the request to consolidate the dockets with the ongoing proceedings involving
  SFPPs North and Oregon Line rates;                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       
|  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      
| | FERC Docket No.
  OR03-5-001Complainants/Protestants: BP WCP; ExxonMobil; and ConocoPhillips
  (other shippers intervened)Defendant: SFPP The FERC severed the portions of
  the complaints in Docket Nos. OR03-5, OR05-4, and OR05-5 regarding SFPPs
  North and Oregon Line rates into a separate proceeding in Docket No.
  OR03-5-001, which has been set for hearing;                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        
|  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      
| | FERC Docket No.
  OR07-1Complainant/Protestant: TesoroDefendant: SFPP                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              
|  | Complaint alleges that
  SFPPs North Line rates are not just and reasonable. Complaint held in
  abeyance pending resolution at the D.C. Court of, among other things, income
  tax allowance and grandfathering issues. The D.C. Court issued an opinion on
  these issues on May 29, 2007, upholding the FERCs income tax allowance
  policy;                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    

178

---



|  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   
|- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | FERC Docket No.
  OR07-2Complainant/Protestant: TesoroDefendant: SFPP                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
|  | Complaint alleges that
  SFPPs West Line rates are not just and reasonable. Complaint held in
  abeyance pending resolution at the D.C. Court of, among other things, income
  tax allowance and grandfathering issues. The D.C. Court issued an opinion on
  these issues on May 29, 2007, upholding the FERCs income tax allowance
  policy. A request that the FERC set the complaint for hearing  which SFPP
  opposed  is pending before the FERC;                                                                                                                       
|  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   
| | FERC Docket No.
  OR07-3Complainants/Protestants: BP WCP; Chevron; ExxonMobil; Tesoro; and
  Valero MarketingDefendant: SFPP Complaint alleges that SFPPs North Line
  indexed rate increase was not just and reasonable. The FERC has dismissed the
  complaint and denied rehearing the dismissal. Petitions for review filed by
  BP WCP and ExxonMobil at the D.C. Court;                                                                                                                                                                                                  
|  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   
| | FERC Docket No.
  OR07-4Complainants/Protestants: BP WCP; Chevron; and ExxonMobilDefendants:
  SFPP; Kinder Morgan G.P., Inc.; and Knight Inc. Complaint alleges that SFPPs
  rates are not just and reasonable. Complaint held in abeyance pending
  resolution at the D.C. Court of, among other things, income tax allowance and
  grandfathering issues. The D.C. Court issued an opinion on these issues on
  May 29, 2007, upholding the FERCs income tax allowance policy;                                                                                             
|  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   
| | FERC Docket Nos. OR07-5
  and OR07-7 (consolidated)Complainants/Protestants: ExxonMobil and
  TesoroDefendants: Calnev; Kinder Morgan G.P., Inc.; and Knight Inc.                                                                                                                                                                                                                                                                                                                                                                                                               
|  | Complaints allege that
  none of Calnevs current rates are just or reasonable. In light of the D.C.
  Courts May 29, 2007 ruling, on July 19, 2007, the FERC, among other things,
  dismissed with prejudice the complaints against Kinder Morgan GP Inc. and Knight,
  Inc. and allowed complainants to file amended complaints. ExxonMobil filed a
  request for rehearing of the dismissal of the complaints against Kinder
  Morgan GP, Inc. and Knight Inc., which is currently pending before the FERC.
  The FERC has not acted on the amended complaints;               
|  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   
| | FERC Docket No.
  OR07-6Complainant/Protestant: ConocoPhillipsDefendant: SFPP                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   
|  | Complaint alleges that
  SFPPs North Line indexed rate increase was not just and reasonable. The FERC
  has dismissed the complaint and denied rehearing of the dismissal. The FERC
  had consolidated this case with OR07-3 and issued orders that applied to both
  OR07-3 and OR07-6. Although the FERC orders in these dockets have been
  appealed by certain of the complainants in OR07-3, they have not been appealed
  by ConocoPhillips in OR07-6;                                                                                                                     
|  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   
| | FERC Docket No. OR07-8
  (consolidated with Docket No. OR07-11)Complainant/Protestant: BP
  WCPDefendant: SFPP Complaint alleges that SFPPs 2005 indexed rate increase
  was not just and reasonable. On June 6, 2007, the FERC dismissed challenges
  to SFPPs underlying rate but held in abeyance the portion of the Complaint
  addressing SFPPs July 1, 2005 index-based rate increases. SFPP requested
  rehearing on July 6, 2007, which the FERC denied. On February 13, 2008, the
  FERC set this complaint for hearing, but referred it to settlement negotiations;
|  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   
| | FERC Docket No. OR07-9Complainant/Protestant:
  BP WCPDefendant: SFPP                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
|  | Complaint alleges that
  SFPPs ultra low sulphur diesel (ULSD) recovery fee violates the filed rate
  doctrine and that, in any event, the recovery fee is unjust and unreasonable.
  On July 6, 2007, the FERC dismissed the complaint. BP WCP requested
  rehearing, which the FERC denied. A petition for review was filed by BP WCP.
  The FERCs motion to dismiss or hold the case in abeyance is pending;                                                                                                                                                                 
|  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   
| | FERC Docket No.
  OR07-10Complainants/Protestants: BP WCP; ConocoPhillips; Valero; and
  ExxonMobilDefendant: Calnev                                                                                                                                                                                                                                                                                                                                                                                                                                                            
|  | Calnev filed a petition
  with the FERC on May 14, 2007, requesting that the FERC issue a declaratory
  order approving Calnevs proposed rate methodology and granting other relief
  with respect to a substantial proposed expansion of Calnevs mainline
  pipeline system. On July 20, 2007, the FERC granted Calnevs petition for
  declaratory order;                                                                                                                                                                                                                     

179

---



|  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                
|- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | FERC Docket No. OR07-11
  (consolidated with Docket No. OR07-8)Complainant/Protestant:
  ExxonMobilDefendant: SFPP Complaint alleges that SFPPs 2005 indexed rate
  increase was not just and reasonable. On February 13, 2008, the FERC set this
  complaint for hearing, but referred it to settlement negotiations.  It is
  consolidated with the complaint in Docket No. OR07-8;                                                                                                                                                                                                                                       
|  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                
| | FERC Docket No.
  OR07-14Complainants/Protestants: BP WCP and ChevronDefendants: SFPP;
  Calnev; Operating Limited Partnership D; Kinder Morgan Energy Partners,
  L.P.; Kinder Morgan Management LLC; Kinder Morgan General Partner, Inc.;
  Knight Inc.; and Knight Holdco, LLC Complaint alleges violations of the
  Interstate Commerce Act and FERCs cash management regulations, seeks review
  of the FERC Form 6 annual reports of SFPP and Calnev, and again requests
  interim refunds and reparations. The FERC dismissed the complaints;                                                                      
|  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                
| | FERC Docket No.
  OR07-16Complainant/Protestant: TesoroDefendant: Calnev                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
|  | Complaint challenges
  Calnevs 2005, 2006, and 2007 indexing adjustments. The FERC dismissed the
  complaint. A petition for review was filed by Tesoro. A scheduling order for
  briefs and oral argument has not yet been issued by the D.C. Court;                                                                                                                                                                                                                                                                                                                                                                         
|  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                
| | FERC Docket No.
  OR07-18Complainants/Protestants: Airline Complainants; Chevron; and Valero
  MarketingDefendant: Calnev Complaint alleges that Calnevs rates are unjust
  and unreasonable and that none of Calnevs rates are grandfathered under
  EPAct 1992. In December 2007, the FERC issued an order accepting and holding
  in abeyance the portion of the complaint against the non-grandfathered
  portion of Calnevs rates. The order also gave complainants 45 days to amend
  their complaint against the grandfathered portion of Calnevs rates in light
  of clarifications provided in the FERCs order;
|  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                
| | FERC Docket No.
  OR07-19Complainant/Protestant: ConocoPhillipsDefendant: Calnev                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|  | Complaint alleges that
  Calnevs rates are unjust and unreasonable and that none of Calnevs rates
  are grandfathered under EPAct 1992. In December 2007, the FERC issued an
  order accepting and holding in abeyance the portion of the complaint against
  the non-grandfathered portion of Calnevs rates. The order also gave
  complainants 45 days to amend their complaint against the grandfathered
  portion of Calnevs rates in light of clarifications provided in the FERCs
  order;                                                                                                                          
|  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                
| | FERC Docket No.
  OR07-20Complainant/Protestant: BP WCPDefendant: SFPP                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       
|  | Complaint alleges that
  SFPPs 2007 indexed rate increase was not just and reasonable. In December
  2007, the FERC dismissed the complaint. Complainant filed a request for
  rehearing which is currently pending before the FERC. In February 2008, the
  FERC accepted a joint offer of settlement that dismisses, with prejudice, the
  East Line index rate portion of the complaint in OR07-20;                                                                                                                                                                                                                        
|  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                
| | FERC Docket No.
  OR07-22Complainant/Protestant: BP WCPDefendant: Calnev                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
|  | Complaint alleges that
  Calnevs rates are unjust and unreasonable and that none of Calnevs rates
  are grandfathered under EPAct 1992. In December 2007, the FERC issued an
  order giving complainant 45 days to amend its complaint in light of guidance
  provided by the FERC;                                                                                                                                                                                                                                                                                                                                          
|  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                
| | FERC Docket No. IS05-230
  (North Line rate case)Complainants/Protestants: ShippersDefendant: SFPP
  SFPP filed to increase North Line rates to reflect increased costs due to
  installation of new pipe between Concord and Sacramento, California. Various
  shippers protested. Administrative law judge decision pending before the FERC
  on exceptions. On August 31, 2007, BP WCP and ExxonMobil filed a motion to
  reopen the record on the issue of SFPPs appropriate rate of return on
  equity, which SFPP answered on September 18, 2007. The FERC has yet to issue
  an order on shippers motion;           
|  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                
| | FERC Docket No.
  IS05-327Complainants/Protestants: ShippersDefendant: SFPP                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  
|  | SFPP filed to increase
  certain rates on its pipelines pursuant to FERCs indexing methodology.
  Various shippers protested, but FERC determined that the tariff filings were
  consistent with its regulations. The D.C. Court dismissed a petition for
  review, citing a lack of jurisdiction to review a decision by FERC not to
  order an investigation;                                                                                                                                                                                                                                                               

180

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|  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | FERC Docket No. IS06-283
  (East Line rate case)Complainants/Protestants: ShippersDefendant: SFPPSFPP
  filed to increase East Line rates to reflect increased costs due to
  installation of new pipe between El Paso, Texas and Tucson, Arizona. Various
  shippers protested. In November 2007, the parties submitted a joint offer of
  settlement which was certified to the FERC in December 2007. In February
  2008, the FERC accepted the joint offer of settlement which, among other
  things, resolved all protests and complaints related to the East Line Phase I
  Expansion Tariff;                                                                                                                                           
|  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
| | FERC Docket No.
  IS06-296Complainant/Protestant: ExxonMobilDefendant: Calnev                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|  | Calnev sought to increase
  its interstate rates pursuant to the FERCs indexing methodology. ExxonMobil
  filed a protest respecting Calnevs indexing adjustments. This proceeding is
  currently held in abeyance pending ongoing settlement discussions. Calnev has
  also filed a motion to dismiss or, to hold the investigation in abeyance,
  which is pending before the FERC. Calnev and ExxonMobil have reached an agreement
  in principle to settle this and other dockets;                                                                                                                                                                                                                                                        
|  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
| | FERC Docket No.
  IS06-356Complainants/Protestants: ShippersDefendant: SFPP                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   
|  | SFPP filed to increase
  certain rates on its pipelines pursuant to FERCs indexing methodology.
  Various shippers protested, but FERC found the tariff filings consistent with
  its regulations. FERC has rescinded the index increase for the East Line
  rates, and SFPP has requested rehearing. The D.C. Court dismissed a petition
  for review, citing the rehearing request pending before the FERC. On
  September 20, 2007, the FERC denied SFPPs request for rehearing. In November
  2007, all parties submitted a joint offer of settlement. In February 2008,
  the FERC accepted the joint offer of settlement which, among other things,
  resolved all protests and complaints related to the East Line 2006 Index
  Tariff;
|  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
| | FERC Docket No. IS07-137
  (ULSD surcharge)Complainants/Protestants: ShippersDefendant: SFPP SFPP
  filed tariffs to include a per barrel ULSD recovery fee and a surcharge for ULSD-related
  litigation costs on diesel products. Various shippers protested. Tariffs
  related to ULSD recovery fee accepted subject to refund and proceeding is
  being held in abeyance pending resolution of other proceedings involving
  SFPP. SFPP rescinded the ULSD litigation surcharge in compliance with FERC
  order. Request for rehearing filed by Chevron and Tesoro. The FERC ultimately
  denied rehearing in an order issued on November 13, 2007;                                                                                       
|  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
| | FERC Docket No.
  IS07-229Complainants/Protestants: BP WCP and ExxonMobilDefendant: SFPP SFPP
  filed to increase certain rates on its pipelines pursuant to FERCs indexing
  methodology. Two shippers filed protests. The FERC found the tariff filings
  consistent with its regulations but suspended the increased rates subject to
  refund pending challenges to SFPPs underlying rates. In November 2007, all
  parties submitted a joint offer of settlement. In February 2008, the FERC
  accepted the joint offer of settlement which, among other things, resolved
  all protests and complaints related to the East Line 2007 Index Tariff;                                                                                    
|  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
| | FERC Docket No.
  IS07-234Complainants/Protestants: BP WCP and ExxonMobilDefendant: Calnev
  Calnev filed to increase certain rates on its pipeline pursuant to FERCs
  indexing methodology. Two shippers protested. The FERC found the tariff
  filings consistent with its regulations but suspended the increased rates
  subject to refund pending challenges to SFPPs underlying rates. Calnev and
  ExxonMobil have reached an agreement in principle to settle this and other
  dockets;                                                                                                                                                                                                                                            
|  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
| | FERC Docket No.
  IS08-28Complainants/Protestants: ConocoPhillips; Chevron; BP WCP;
  ExxonMobil; Southwest Airlines; Western; and ValeroDefendant: SFPP SFPP
  filed to increase its East Line rates based on costs incurred related to an
  expansion. Various shippers filed protests, which SFPP answered. The FERC
  issued an order on November 29, 2007 accepting and suspending the tariff
  subject to refund. The proceeding is being held in abeyance pursuant to
  ongoing settlement negotiations; and                                                                                                                                                                                                                           
|  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
| | Motions to compel payment
  of interim damages (various dockets)Complainants/Protestants:
  ShippersDefendants: SFPP; Kinder Morgan G.P., Inc.; and Knight Inc. Motions
  seek payment of interim refunds or escrow of funds pending resolution of
  various complaints and protests involving SFPP. The FERC denied shippers
  refund requests in an order issued on December 26, 2007 in Docket Nos.
  OR92-8, et al.                                                                                                                                                                                                                                                                                                                      

181

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In
2003, we made aggregate payments of $44.9 million for reparations and refunds
pursuant to a FERC order related to Docket Nos. OR92-8, et al.
In December 2005, SFPP received a FERC order in OR92-8 and OR96-2 that
directed it to submit compliance filings and revised tariffs. In accordance with the FERCs December 2005
order and its February 2006 order on rehearing, SFPP submitted a compliance
filing to the FERC in March 2006, and rate reductions were implemented on May
1, 2006. We estimate the impact of the
rate reductions in 2007 was approximately $25 million, and we estimate that the
actual, partial year impact on 2006 distributable cash flow was approximately
$15.7 million. In addition, in December
2005, we recorded accruals of $105.0 million for expenses attributable to an
increase in our reserves related to our rate case liability.

In
December 2007, as a follow-up to the March 2006 compliance filing, SFPP
received a FERC order that directed us to submit revised compliance filings and
revised tariffs. In conjunction with
this order, our other FERC and CPUC rate cases, and other unrelated litigation
matters, we increased our litigation reserves by $140.0 million in the fourth
quarter of 2007. We assume that, with
respect to our SFPP litigation reserves, any additional reparations and accrued
interest thereon will be paid no earlier than the fourth quarter of 2008. We expect to file the revised compliance
filings on February 26, 2008, and to implement new rates on March 1, 2008.  We
estimate that the impact of the new rates on our 2008 budget will be less than $3.0 million.

In
general, if the shippers are successful in proving their claims, they are
entitled to reparations or refunds of any excess tariffs or rates paid during
the two year period prior to the filing of their complaint, and our Pacific
operations may be required to reduce the amount of its tariffs or rates for
particular services. These proceedings tend
to be protracted, with decisions of the FERC often appealed to the federal
courts. Based on our review of these
FERC proceedings, we estimate that shippers are seeking approximately $290 million in reparation
and refund payments and approximately $45 million in additional annual rate reductions.

California
Public Utilities Commission Proceedings

On
April 7, 1997, ARCO, Mobil and Texaco filed a complaint against SFPP with the
California Public Utilities Commission, referred to in this note as the
CPUC. The complaint challenges rates
charged by SFPP for intrastate transportation of refined petroleum products
through its pipeline system in the state of California and requests prospective
rate adjustments.

In
October 2002, the CPUC issued a resolution, referred to in this note as the
Power Surcharge Resolution, approving a 2001 request by SFPP to raise its
California rates to reflect increased power costs. The resolution approving the requested rate increase also
required SFPP to submit cost data for 2001, 2002, and 2003, and to assist the
CPUC in determining whether SFPPs overall rates for California intrastate
transportation services are reasonable.
The resolution reserves the right to require refunds, from the date of
issuance of the resolution, to the extent the CPUCs analysis of cost data to
be submitted by SFPP demonstrates that SFPPs California jurisdictional rates
are unreasonable in any fashion.

On
December 26, 2006, Tesoro filed a complaint challenging the reasonableness of
SFPPs intrastate rates for the three-year period from December 2003 through
December 2006 and requesting approximately $8 million in reparations. As a result of previous SFPP rate filings
and related protests, the rates that are the subject of the Tesoro complaint
are being collected subject to refund.

SFPP
also has various, pending ratemaking matters before the CPUC that are unrelated
to the above-referenced complaints and the Power Surcharge Resolution. Protests to these rate increase applications
have been filed by various shippers. As
a consequence of the protests, the related rate increases are being collected
subject to refund.

All
of the above matters have been consolidated and assigned to a single
administrative law judge. At the time
of this report, it is unknown when a decision from the CPUC regarding the CPUC
complaints and the Power Surcharge Resolution will be received. No schedule has been established for hearing
and resolution of the consolidated proceedings other than the 1997
CPUC complaint and the Power Surcharge Resolution. Based on our review of these CPUC proceedings, we estimate that
shippers are seeking approximately $100 million in reparation and refund payments
and approximately $35 million in annual rate reductions.

182

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Carbon
Dioxide Litigation

Shores
and First State Bank of Denton Lawsuits

Kinder
Morgan CO2 Company, L.P.
(referred to in this note as Kinder Morgan CO2), Kinder Morgan G.P., Inc., and
Cortez Pipeline Company were among the named defendants in Shores, et al. v.
Mobil Oil Corp., et al., No. GC-99-01184 (Statutory Probate Court, Denton
County, Texas filed December 22, 1999) and First State Bank of Denton, et al.
v. Mobil Oil Corp., et al., No. 8552-01 (Statutory Probate Court, Denton
County, Texas filed March 29, 2001).
These cases were originally filed as class actions on behalf of classes
of overriding royalty interest owners (Shores) and royalty interest owners (Bank
of Denton) for damages relating to alleged underpayment of royalties on carbon
dioxide produced from the McElmo Dome Unit.
On February 22, 2005, the trial judge dismissed both cases for lack of
jurisdiction. Some of the individual
plaintiffs in these cases re-filed their claims in new lawsuits (discussed
below).

Armor/Reddy
Lawsuit

On
May 13, 2004, William Armor filed a case alleging the same claims for
underpayment of royalties on carbon dioxide produced from the McElmo Dome Unit
against Kinder Morgan CO2, Kinder Morgan G.P., Inc., and Cortez Pipeline
Company among others. Armor v. Shell Oil
Company, et al, No. 04-03559 (14th Judicial District Court, Dallas
County, Texas filed May 13, 2004).

On
May 20, 2005, Josephine Orr Reddy and Eastwood Capital, Ltd. filed a case in
Dallas state district court alleging the same claims for underpayment of
royalties. Reddy and Eastwood Capital, Ltd.
v. Shell Oil Company, et al., No. 05-5021 (193rd Judicial District
Court, Dallas County, Texas filed May 20, 2005). The defendants included Kinder Morgan CO2 and Kinder
Morgan Energy Partners, L.P. On June
23, 2005, the plaintiff in the Armor lawsuit filed a motion to transfer and
consolidate the Reddy lawsuit with the Armor lawsuit. On June 28, 2005, the court in the Armor lawsuit ordered that the
Reddy lawsuit be transferred and consolidated into the Armor lawsuit.

Effective
March 5, 2007, the parties executed a final settlement agreement which providesfor the dismissal of the lawsuit and the
plaintiffs claims with prejudice to being refiled. On June 12, 2007, the Dallas state district court signed its
order dismissing the case and all claims with prejudice.

Gerald
O. Bailey et al. v. Shell Oil Co. et al/Southern District of Texas Lawsuit

Kinder
Morgan CO2, Kinder Morgan Energy Partners, L.P. and Cortez Pipeline Company are
among the defendants in a proceeding in the federal courts for the
southern district of Texas. Gerald O. Bailey et al. v. Shell Oil Company et al.,
(Civil Action Nos. 05-1029 and 05-1829 in the U.S. District Court for the
Southern District of Texasconsolidated by Order dated July 18, 2005). The plaintiffs are asserting claims for the
underpayment of royalties on carbon dioxide produced from the McElmo Dome
unit. The plaintiffs assert claims for
fraud/fraudulent inducement, real estate fraud, negligent misrepresentation,
breach of fiduciary and agency duties, breach of contract and covenants,
violation of the Colorado Unfair Practices Act, civil theft under Colorado law,
conspiracy, unjust enrichment, and open account. Plaintiffs Gerald O. Bailey, Harry Ptasynski, and W.L. Gray &
Co. have also asserted claims as private relators under the False Claims Act
and for violation of federal and Colorado antitrust laws. The plaintiffs seek actual damages, treble
damages, punitive damages, a constructive trust and accounting, and declaratory
relief. The defendants have filed
motions for summary judgment on all claims.
No trial date has been set.

Effective
March 5, 2007, all defendants and plaintiffs Bridwell Oil Company, the Alicia
Bowdle Trust, and the Estate of Margaret Bridwell Bowdle executed a final
settlement agreement which provides for the dismissal of these plaintiffs
claims with prejudice to being refiled.
On June 10, 2007, the Houston federal district court entered an order of
partial dismissal by which the claims by and against the settling plaintiffs
were dismissed with prejudice. The
claims asserted by Bailey, Ptasynski, and Gray are not included within the settlement
or the order of partial dismissal.

183

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Ptasynski
Colorado Federal District Court Lawsuit

On
April 7, 2006, Harry Ptasynski, one of the plaintiffs in the Bailey action
discussed above, filed suit against Kinder Morgan G.P., Inc. in Colorado
federal district court. Harry Ptasynski
v. Kinder Morgan G.P., Inc., No. 06-CV-00651 (LTB) (U.S. District Court for the
District of Colorado). Ptasynski, who holds
an overriding royalty interest at McElmo Dome, asserted claims for civil conspiracy,
violation of the Colorado Organized Crime Control Act, violation of Colorado
antitrust laws, violation of the Colorado Unfair Practices Act, breach of
fiduciary duty and confidential relationship, violation of the Colorado Payment
of Proceeds Act, fraudulent concealment, breach of contract and implied duties
to market and good faith and fair dealing, and civil theft and conversion. Ptasynski sought actual damages, treble
damages, forfeiture, disgorgement, and declaratory and injunctive relief. The Colorado court transferred the case to
Houston federal district court, and Ptasynski voluntarily dismissed the case on
May 19, 2006. Ptasynski also filed an
appeal in the Tenth Circuit seeking to overturn the Colorado courts order
transferring the case to Houston federal district court. Harry Ptasynski v. Kinder Morgan G.P., Inc.,
No. 06-1231 (10th Cir.). Briefing in
the appeal was completed on November 27, 2006.
On April 4, 2007, the Tenth Circuit Court of Appeals dismissed the
appeal as moot in light of Ptasynksis voluntary dismissal of the case.

Bridwell
Oil Company Wichita County Lawsuit

On
March 1, 2004, Bridwell Oil Company, one of the named plaintiffs in the above
described Bailey action, filed a new matter in which it asserted claims that
are virtually identical to the claims it asserted in the Bailey lawsuit. Bridwell Oil Co. v. Shell Oil Co. et al.,
No. 160,199-B (78th Judicial District Court, Wichita County, Texas filed March 1, 2004). The defendants in this action include, among
others, Kinder
Morgan CO2, Kinder Morgan Energy Partners, L.P., and Cortez Pipeline
Company. This case was abated pending
resolution of the Bailey action discussed above.

Effective
March 5, 2007, the parties executed a final settlement agreement which provides
for the dismissal of the lawsuit and the plaintiffs claims with prejudice to
being refiled. On June 14, 2007, the
Wichita County state district court signed its order dismissing the case and
all claims with prejudice.

CO2
Claims Arbitration

Cortez
Pipeline Company and Kinder Morgan CO2, successor to Shell CO2 Company,
Ltd., were among the named
defendants in CO2 Committee, Inc. v. Shell Oil Co., et al., an
arbitration initiated on November 28, 2005.
The arbitration arose from a dispute over a class action settlement
agreement which became final on July 7, 2003 and disposed of five lawsuits
formerly pending in the U.S. District Court, District of Colorado. The plaintiffs in such lawsuits primarily
included overriding royalty interest owners, royalty interest owners, and small
share working interest owners who alleged underpayment of royalties and other
payments on carbon dioxide produced from the McElmo Dome Unit. The settlement imposed certain future obligations
on the defendants in the underlying litigation. The plaintiff in the arbitration is an entity that was formed as
part of the settlement for the purpose of monitoring compliance with the
obligations imposed by the settlement agreement. The plaintiff alleged that, in calculating royalty and other
payments, defendants used a transportation expense in excess of what is allowed
by the settlement agreement, thereby causing alleged underpayments of
approximately $12 million. The
plaintiff also alleged that Cortez Pipeline Company should have used certain
funds to further reduce its debt, which, in turn, would have allegedly
increased the value of royalty and other payments by approximately $0.5
million. Defendants denied that there
was any breach of the settlement agreement.
On August 7, 2006, the arbitration panel issued its opinion finding that
defendants did not breach the settlement agreement. On October 25, 2006, the defendants filed an application to
confirm the arbitration decision in New Mexico federal district court. On June 21, 2007, the New Mexico federal
district court entered final judgment confirming the August 7, 2006 arbitration
decision.

On
October 2, 2007, the plaintiff initiated a second arbitration (CO2 Committee,
Inc. v. Shell CO2 Company, Ltd.,
aka Kinder Morgan CO2Company,
L.P., et al.) against Cortez Pipeline Company, Kinder Morgan CO2 and a Mobil
entity. The second arbitration asserts
claims similar to those asserted in the first arbitration. On October 11, 2007, the defendants filed a
Complaint for Declaratory Judgment and Injunctive Relief in federal district
court in New Mexico. The Complaint
seeks dismissal of the second arbitration on the basis of res judicata. In November 2007, the plaintiff in the
arbitration moved to dismiss the defendants Complaint on the grounds that the
issues

184

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presented
should be decided by a panel in a second arbitration. In December 2007, the defendants in the arbitration filed a
motion seeking summary judgment on their Complaint and dismissal of the second
arbitration. No hearing date has been
set.

MMS
Notice of Noncompliance and Civil Penalty

On
December 20, 2006, Kinder Morgan CO2 received a Notice of Noncompliance
and Civil Penalty: Knowing or
Willful Submission of False, Inaccurate, or Misleading InformationKinder
Morgan CO2 Company, L.P., Case No. CP07-001 from the U.S. Department of
the Interior, Minerals Management Service.
This Notice, and the MMS
position that Kinder Morgan CO2 has violated certain reporting
obligations, relates to a disagreement between
the MMS and Kinder Morgan CO2 concerning the approved transportation
allowance to be used in valuing McElmo Dome carbon dioxide for purposes of
calculating federal royalties. The
Notice of Noncompliance and Civil Penalty assesses a civil penalty of
approximately $2.2 million as of December 15, 2006 (based on a penalty of $500.00
per day for each of 17 alleged violations) for Kinder Morgan CO2s alleged
submission of false, inaccurate, or misleading information relating to the
transportation allowance, and federal royalties for CO2 produced at
McElmo Dome, during the period from June 2005 through October 2006. The MMS contends that false, inaccurate, or
misleading information was submitted in the 17 monthly Form 2014s containing
remittance advice reflecting the royalty
payments for the referenced period because they reflected Kinder Morgan CO2s
use of the Cortez Pipeline tariff as the transportation allowance. The MMS claims that the Cortez Pipeline
tariff is not the proper transportation
allowance and that Kinder Morgan CO2 should have used its reasonable
actual costs calculated in accordance with certain federal product valuation
regulations as amended effective June 1, 2005.
The MMS stated that civil penalties will continue to accrue at the same
rate until the alleged violations are corrected.

The
MMS set a due date of January 20, 2007 for Kinder Morgan CO2s payment of the
approximately $2.2 million in civil penalties, with interest to accrue
daily on that amount in the event payment is not made by such date.
Kinder Morgan CO2has not
paid the penalty. On January 2, 2007,
Kinder Morgan CO2 submitted a response to the Notice of Noncompliance
and Civil Penalty challenging the assessment in the Office of Hearings and
Appeals of the Department of the
Interior. On February 1, 2007, Kinder
Morgan CO2 filed a petition to stay the accrual of penalties until the
dispute is resolved. On February 22,
2007, an administrative law judge of the U.S. Department of the Interior issued an order denying Kinder
Morgan CO2s petition to stay the accrual of penalties. A hearing on the Notice of
Noncompliance and Civil Penalty was originally set for December 10, 2007. In
November 2007, the MMS and Kinder Morgan
CO2 filed a joint motion to vacate the
hearing date and stay the accrual of additional penalties to allow the
parties to discuss settlement. In
November 2007, the administrative law judge granted the joint motion, stayed
accrual of additional penalties for the period from November 6, 2007 to
February 18, 2008, and reset the hearing date to March 24, 2008. The parties conducted settlement conferences
on February 4, 2008 and February 12, 2008.

Kinder
Morgan CO2 disputes the Notice of Noncompliance and Civil Penalty and
believes that it has meritorious defenses. Kinder Morgan CO2 contends that use
of the Cortez pipeline tariff as the transportation allowance for purposes of
calculating federal royalties was approved by the MMS in 1984. This approval was later affirmed as open-ended by the Interior Board
of Land
Appeals in the 1990s. Accordingly,
Kinder Morgan CO2 has stated to the MMS that its use of the Cortez
tariff as the approved federal transportation allowance is authorized and proper. Kinder
Morgan CO2 also disputes the allegation that it has knowingly or
willfully submitted false, inaccurate, or misleading
information to the MMS. Kinder
MorganCO2s use of the Cortez Pipeline tariff as the approved federal transportation
allowance has been the subject of extensive discussion between the
parties. The MMS was, and is, fully apprised of that fact and of the royalty
valuation and payment process followed by Kinder Morgan CO2 generally.

MMS
Order to Report and Pay

On
March 20, 2007, Kinder Morgan CO2 received an Order to Report and Pay
from the Minerals Management Service. The MMS contends that Kinder Morgan CO2 has over-reported transportation
allowances and underpaid royalties in the amount of approximately $4.6 million
for the period from January 1, 2005 through December 31, 2006 as a result of
its use of the Cortez pipeline tariff as the transportation allowance in
calculating federal royalties. As noted in the discussion of the Notice of
Noncompliance and Civil Penalty proceeding, the MMS claims that the Cortez Pipeline tariff is not the proper
transportation allowance and that Kinder Morgan CO2 must use its

185

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reasonable
actual costs calculated in accordance with certain federal product valuation
regulations. The MMS set a due date of April 13, 2007 for Kinder Morgan
CO2s payment of the $4.6 million in claimed additional royalties, with
possible late payment charges and civil penalties for failure to pay the
assessed amount. Kinder Morgan CO2
has not paid the $4.6 million, and on April 19, 2007, it submitted a notice of
appeal and statement of reasons in response to the Order to Report and Pay,
challenging the Order and appealing it to the Director of the MMS in accordance with 30 CFR 290.100, et seq. Also on April 19, 2007,
Kinder Morgan CO2
submitted a petition to suspend
compliance with the Order to Report and Pay pending the appeal. The MMS granted Kinder Morgan CO2s petition
to suspend, and approved self-bonding on June 12, 2007. Kinder Morgan CO2 filed a supplemental statement
of reasons in support of its appeal of the Order to Report and Pay on June 15,
2007.

In addition to the March 2007
Order to Report and Pay, in April 2007, Kinder Morgan CO2 received an
Audit Issue Letter sent by the Colorado Department of Revenue on behalf of
the U.S. Department of the Interior. In
the letter, the Department of
Revenue states that Kinder Morgan CO2 has over-reported transportation
allowances and underpaid royalties (due to the use of the Cortez pipeline
tariff as the transportation allowance for purposes of federal royalties) in
the amount of $8.5 million for the period from April 2000 through December
2004. Kinder Morgan CO2 responded to the letter in May 2007, outlining its
position why use of the Cortez tariff-based transportation allowance is proper. On August 8, 2007, Kinder Morgan CO2
received an Order to Report and Pay Additional Royalties from the MMS. As alleged in the Colorado Audit Issue
Letter, the MMS contends that Kinder
Morgan CO2 has over-reported transportation allowances and underpaid
royalties in the amount of approximately $8.5 million for the period from April
2000 through December 2004. The MMSs
claims underlying the August 2007 Order to Report and Pay are similar to those
at issue in the March 2007 Order to Report and Pay. On September 7, 2007,
Kinder Morgan CO2 submitted a notice of appeal and statement of reasons
in response to the August 2007 Order to Report and Pay, challenging the Order
and appealing it to the Director of the MMS in accordance with 30 CFR 290.100, et seq.
Also on September 7, 2007, Kinder Morgan CO2 submitted a petition
to suspend compliance with the Order to
Report and Pay pending the appeal. The
MMS granted Kinder Morgan CO2s petition to suspend, and approved
self-bonding on September 11, 2007.

The
MMS and Kinder Morgan CO2 have agreed
to stay the March 2007 and August 2007 Order to Report and Pay
proceedings to allow the parties to discuss settlement. The parties conducted settlement conferences
on February 4, 2008 and February 12, 2008.

Kinder
Morgan CO2 disputes both the March and August 2007 Orders to Report and
Pay and the Colorado Department of Revenue Audit Issue Letter, and as noted
above, it contends that use of the Cortez pipeline tariff as the transportation
allowance for purposes of calculating federal royalties was approved by the MMS
in 1984 and was affirmed as open-ended by the Interior Board of Land Appeals in
the 1990s. The appeals to the MMS
Director of the Orders to Report and Pay do not provide for an oral
hearing. No further submission or
briefing deadlines have been set.

J.
Casper Heimann, Pecos Slope Royalty Trust and Rio Petro LTD, individually and
on behalf of all other private royalty and overriding royalty owners in the
Bravo Dome Carbon Dioxide Unit, New Mexico similarlysituated v. Kinder Morgan
CO2 Company, L.P., No. 04-26-CL (8th Judicial District Court, Union
County New Mexico)

This
case involves a purported class action against Kinder Morgan CO2
alleging that it has failed to pay the full royalty and overriding royalty
(royalty interests) on the true and proper settlement value of compressed
carbon dioxide produced from the Bravo Dome Unit during the period beginning
January 1, 2000. The complaint purports
to assert claims for violation of the New Mexico Unfair Practices Act,
constructive fraud, breach of contract and of the covenant of good faith and
fair dealing, breach of the implied covenant to market, and claims for an
accounting, unjust enrichment, and injunctive relief. The purported class is comprised of current and former owners,
during the period January 2000 to the present, who have private property
royalty interests burdening the oil and gas leases held by the defendant,
excluding the Commissioner of Public Lands, the United States of America, and
those private royalty interests that are not unitized as part of the Bravo Dome
Unit. The plaintiffs allege that they
were members of a class previously certified as a class action by the United
States District Court for the District of New Mexico in the matter Doris
Feerer, et al. v. Amoco Production Company, et al., USDC N.M. Civ. No. 95-0012
(the Feerer Class Action). Plaintiffs allege that Kinder Morgan CO2s
method of paying royalty interests is contrary to the settlement of the Feerer
Class Action. Kinder Morgan CO2
filed a motion to compel arbitration of this matter

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pursuant to
the arbitration provisions contained in the Feerer Class Action settlement
agreement, which motion was denied. Kinder Morgan CO2
appealed this decision to the New Mexico Court of Appeals, which affirmed the
decision of the trial court. The New
Mexico Supreme Court granted further review in October 2006, and after hearing
oral argument, the New Mexico Supreme Court quashed its prior order granting
review. In August 2007, Kinder Morgan CO2 filed a petition for writ of certiorari with the United States
Supreme Court seeking further review. The Petition was denied in
December 2007. The case is now
proceeding in the trial court as a certified class action and the case is set
for trial in September 2008.

In
addition to the matters listed above, audits and administrative inquiries
concerning Kinder Morgan CO2s payments on carbon dioxide produced from
the McElmo Dome and Bravo Dome Units are currently ongoing. These audits and inquiries involve federal
agencies and the States of Colorado and New Mexico.

Commercial
Litigation Matters

Union
Pacific Railroad Company Easements

SFPP,
L.P. and Union Pacific Railroad Company (the successor to Southern Pacific
Transportation Company and referred to in this Note as UPRR) are engaged in a
proceeding to determine the extent, if any, to which the rent payable by SFPP
for the use of pipeline easements on rights-of-way held by UPRR should be
adjusted pursuant to existing contractual arrangements for the ten year period
beginning January 1, 2004 (Union Pacific
Railroad Company vs. Santa Fe Pacific Pipelines, Inc., SFPP, L.P., Kinder
Morgan Operating L.P. D, Kinder Morgan G.P., Inc., et al.,Superior
Court of the State of California for the County of Los Angeles, filed July 28,
2004). In February 2007, a trial began
to determine the amount payable for easements on UPRR rights-of-way. The trial is ongoing and is expected to
conclude in the second quarter of 2008.

SFPP
and UPRR are also engaged in multiple disputes over the circumstances under
which SFPP must pay for a relocation of its pipeline within the UPRR right of
way and the safety standards that govern relocations. SFPP believes that it must pay for relocation of the pipeline
only when so required by the railroads common carrier operations, and in doing
so, it need only comply with standards set forth in the federal Pipeline Safety
Act in conducting relocations. In July
2006, a trial before a judge regarding the circumstances under which we must
pay for relocations concluded, and the judge determined that we must pay for
any relocations resulting from any legitimate business purpose of the
UPRR. We have appealed this
decision. In addition, UPRR contends
that it has complete discretion to cause the pipeline to be relocated at SFPPs
expense at any time and for any reason, and that SFPP must comply with the more
expensive American Railway Engineering and Maintenance-of-Way standards. Each party is seeking declaratory relief
with respect to its positions regarding relocations.

It
is difficult to quantify the effects of the outcome of these cases on SFPP
because SFPP does not know UPRRs plans for projects or other activities that
would cause pipeline relocations. Even
if SFPP is successful in advancing its positions, significant relocations for
which SFPP must nonetheless bear the expense (i.e. for railroad purposes, with
the standards in the federal Pipeline Safety Act applying) would have an
adverse effect on our financial position and results of operations. These effects would be even greater in the
event SFPP is unsuccessful in one or more of these litigations.

United
States of America, ex rel., Jack J. Grynberg v. K N Energy (Civil Action No.
97-D-1233, filed in the U.S. District Court, District of Colorado).

This
multi-district litigation proceeding involves four lawsuits filed in 1997
against numerous Kinder Morgan companies.
These suits were filed pursuant to the federal False Claims Act and
allege underpayment of royalties due to mismeasurement of natural gas produced
from federal and Indian lands. The
complaints are part of a larger series of similar complaints filed by Mr.
Grynberg against 77 natural gas pipelines (approximately 330 other defendants)
in various courts throughout the country which were consolidated and
transferred to the District of Wyoming.

In
May 2005, a Special Master appointed in this litigation found that because
there was a prior public disclosure of the allegations and that Grynberg was
not an original source, the Court lacked subject matter jurisdiction. As a result, the Special Master recommended
that the Court dismiss all the Kinder Morgan defendants. In October 2006,

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the United
States District Court for the District of Wyoming upheld the dismissal of each
case against the Kinder Morgan defendants on jurisdictional grounds. Grynberg has appealed this Order to the Tenth
Circuit Court of Appeals. A procedural
schedule has been issued and briefing before the Court of Appeals will be
completed in the spring of 2008. The
oral argument is expected to take place in September 2008.

Prior
to the dismissal order on jurisdictional grounds, the Kinder Morgan defendants
filed Motions to Dismiss and for Sanctions alleging that Grynberg filed his
Complaint without evidentiary support and for an improper purpose. On January 8, 2007, after the dismissal
order, the Kinder Morgan defendants also filed a Motion for Attorney Fees under
the False Claim Act. On April 24, 2007
the Court held a hearing on the Motions to Dismiss and for Sanctions and the
Requests for Attorney Fees. A decision
is still pending on the Motions to Dismiss and for Sanctions and the Requests
for Attorney Fees.

Weldon
Johnson and Guy Sparks, individually and as Representative of Others Similarly
Situated v. Centerpoint Energy, Inc. et. al., No. 04-327-2 (Circuit Court,
Miller County Arkansas).

On
October 8, 2004, plaintiffs filed the above-captioned matter against numerous
defendants including Kinder Morgan Texas Pipeline L.P.; Kinder Morgan Energy
Partners, L.P.; Kinder Morgan G.P., Inc.; KM Texas Pipeline, L.P.; Kinder
Morgan Texas Pipeline G.P., Inc.; Kinder Morgan Tejas Pipeline G.P., Inc.;
Kinder Morgan Tejas Pipeline, L.P.; Gulf Energy Marketing, LLC; Tejas Gas, LLC;
and MidCon Corp. (the Kinder Morgan
defendants). The complaint
purports to bring a class action on behalf of those who purchased natural gas
from the CenterPoint defendants from October 1, 1994 to the date of class
certification.

The
complaint alleges that CenterPoint Energy, Inc., by and through its affiliates,
has artificially inflated the price charged to residential consumers for
natural gas that it allegedly purchased from the non-CenterPoint defendants,
including the Kinder Morgan defendants.
The complaint further alleges that in exchange for CenterPoints purchase
of such natural gas at above market prices, the non-CenterPoint defendants,
including the Kinder Morgan defendants, sell natural gas to CenterPoints
non-regulated affiliates at prices substantially below market, which in turn
sells such natural gas to commercial and industrial consumers and gas marketers
at market price. The complaint purports
to assert claims for fraud, unlawful enrichment and civil conspiracy against
all of the defendants, and seeks relief in the form of actual, exemplary and punitive
damages, interest, and attorneys fees.
On June 8, 2007, the Arkansas Supreme Court held that the Arkansas
Public Service Commission has exclusive jurisdiction over any Arkansas
plaintiffs claims that consumers were overcharged for gas in Arkansas and
mandated that any such claims be dismissed from this lawsuit. On February 14,
2008, the Arkansas Supreme Court clarified its previously issued order and
mandated that the trial court dismiss the lawsuit in its entirety.  Based on
the information available to date
and our preliminary investigation, the Kinder Morgan defendants believe that
the claims against them are without merit and intend to defend against them
vigorously.

Federal
Investigation at Cora and Grand Rivers Coal Facilities

On
June 22, 2005, we announced that the Federal Bureau of Investigation was
conducting an investigation related to our coal terminal facilities located in
Rockwood, Illinois and Grand Rivers, Kentucky.
The investigation involved certain coal sales from our Cora, Illinois
and Grand Rivers, Kentucky coal terminals that occurred from 1997 through 2001. During this time period, we sold excess coal
from these two terminals for our own account, generating less than $15 million
in total net sales. Excess coal is the
weight gain that results from moisture absorption into existing coal during
transit or storage and from scale inaccuracies, which are typical in the
industry. During the years 1997 through
1999, we collected, and, from 1997 through 2001, we subsequently sold, excess
coal for our own account, as we believed we were entitled to do under
then-existing customer contracts. We
conducted an internal investigation of the allegations and discovered no
evidence of wrongdoing or improper activities at these two terminals.

In
the fourth quarter of 2007, we reached a civil settlement with the U.S.
Attorneys office for the Southern District of Illinois pursuant to which we
paid approximately $25 million, in aggregate, to the Tennessee Valley Authority
and other customers of the Cora and Grand Rivers terminals from 1997 through
1999. We made no admission or
acknowledgment of improper conduct as part of the settlement, and while we
continue to believe that our actions at our terminals were appropriate, we
determined that a civil resolution of the matter would be in our best
interest. The settlement has been finalized,
and we recorded a $25 million
increase in expense in the third quarter of 2007 associated with the settlement
of this liability.

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Queen
City Railcar Litigation

On
August 28, 2005, a railcar containing the chemical styrene began leaking
styrene gas in Cincinnati, Ohio while en route to our Queen City Terminal. The railcar was sent by the Westlake
Chemical Corporation from Louisiana, transported by Indiana & Ohio Railway,
and consigned to Westlake at its dedicated storage tank at Queen City
Terminals, Inc., a subsidiary of Kinder Morgan Bulk Terminals, Inc. The railcar leak resulted in the evacuation
of many residents and the alleged temporary closure of several businesses in
the Cincinnati area. A class action
complaint and a suit filed by the City of Cincinnati arising out of this
accident have been settled. However,
one member of the settlement class, the Estate of George W. Dameron, opted out
of the settlement, and the Adminstratrix of the Dameron Estate filed a wrongful
death lawsuit on November 15, 2006 in the Hamilton County Court of Common
Pleas, Case No. A0609990. The
complaint, which is asserted against each of the defendants involved in the
class action suit, alleges that styrene exposure caused the death of Mr.
Dameron. Without admitting fault or
liability, the parties have reached a settlement in principle of the Dameron
suit.

As
part of the settlement of the class action claims, the non-Kinder Morgan
defendants have agreed to settle remaining claims asserted by businesses and
will obtain a release of such claims favoring all defendants, including Kinder
Morgan and its affiliates, subject to the retention by all defendants of their
claims against each other for contribution and indemnity. Kinder Morgan expects that a claim will be
asserted by other defendants against Kinder Morgan seeking contribution or
indemnity for any settlements funded exclusively by other defendants, and
Kinder Morgan expects to vigorously defend against any such claims.

Leukemia
Cluster Litigation

Richard
Jernee, et al v. Kinder Morgan Energy Partners, et al, No. CV03-03482 (Second
Judicial District Court, State of Nevada, County of Washoe) (Jernee).

Floyd
Sands, et al v. Kinder Morgan Energy Partners, et al, No. CV03-05326 (Second Judicial District Court, State of
Nevada, County of Washoe) (Sands).

On
May 30, 2003, plaintiffs, individually and on behalf of Adam Jernee, filed a
civil action in the Nevada State trial court against us and several Kinder
Morgan related entities and individuals and additional unrelated defendants.
Plaintiffs in the Jernee matter claim that defendants negligently and
intentionally failed to inspect, repair and replace unidentified segments of
their pipeline and facilities, allowing harmful substances and emissions and
gases to damage the environment and health of human beings. Plaintiffs claim that Adam Jernees death
was caused by leukemia that, in turn, is believed to be due to exposure to
industrial chemicals and toxins.
Plaintiffs purport to assert claims for wrongful death, premises
liability, negligence, negligence per se, intentional infliction of emotional
distress, negligent infliction of emotional distress, assault and battery,
nuisance, fraud, strict liability (ultra hazardous acts), and aiding and
abetting, and seek unspecified special, general and punitive damages. On August 28, 2003, a separate group of
plaintiffs, represented by the counsel for the plaintiffs in the Jernee matter,
individually and on behalf of Stephanie Suzanne Sands, filed a civil action in
the Nevada State trial court against the same defendants and alleging the same
claims as in the Jernee case with respect to Stephanie Suzanne Sands. The Jernee case has been consolidated for
pretrial purposes with the Sands case.
In May 2006, the court granted defendants motions to dismiss as to the
counts purporting to assert claims for fraud, but denied defendants motions to
dismiss as to the remaining counts, as well as defendants motions to strike
portions of the complaint. Defendant
Kennametal, Inc. has filed a third-party complaint naming the United States and
the United States Navy (the United States) as additional defendants. In response, the United States removed the
case to the United States District Court for the District of Nevada and filed a
motion to dismiss the third-party complaint.
Plaintiff has also filed a motion to dismiss the United States and/or to
remand the case back to state court. By
order dated September 25, 2007, the United States District Court granted the
motion to dismiss the United States from the case and remanded the Jernee and
Sands cases back to the Second Judicial District Court, State of Nevada, County
of Washoe. The cases will now proceed
in the State Court. Based on the
information available to date, our own preliminary investigation, and the
positive results of investigations conducted by State and Federal agencies, we
believe that the remaining claims against us in these matters are without merit
and intend to defend against them vigorously.

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Pipeline
Integrity and Releases

From
time to time, our pipelines experience leaks and ruptures. These leaks and ruptures may cause
explosions, fire, damage to the environment, damage to property and/or personal
injury or death. In connection with
these incidents, we may be sued for damages caused by an alleged failure to
properly mark the locations of our pipelines and/or to properly maintain our
pipelines. Depending upon the facts and
circumstances of a particular incident, state and federal regulatory
authorities may seek civil and/or criminal fines and penalties.

We
believe that we conduct our operations in accordance with applicable law. We seek to cooperate with state and federal
regulatory authorities in connection with the clean-up of the environment
caused by such leaks and ruptures and with any investigations as to the facts
and circumstances surrounding the incidents.

Kleberg
County, Texas Gas Pipeline Rupture

On
February 12, 2008, Kinder Morgan Texas Pipeline incurred a failure on its
16-inch diameter natural gas pipeline in a remote area in Kleberg County,
Texas, which resulted in an explosion and fire. The incident caused some property damage, however no serious
physical injuries have been reported to date.
Kinder Morgan Texas Pipeline notified appropriate regulatory agencies
and is currently investigating the cause of the rupture.

Walnut
Creek, California Pipeline Rupture

On
November 9, 2004, excavation equipment operated by Mountain Cascade, Inc., a
third-party contractor on a water main installation project hired by East Bay
Municipal Utility District, struck and ruptured an underground petroleum
pipeline owned and operated by SFPP, L.P. in Walnut Creek, California. An explosion occurred immediately following
the rupture that resulted in five fatalities and several injuries to employees
or contractors of Mountain Cascade. The
explosion and fire also caused property damage.

On
May 5, 2005, the California Division of Occupational Safety and Health
(CalOSHA) issued two civil citations against us relating to this incident
assessing civil fines of approximately $0.1 million based upon our alleged failure
to mark the location of the pipeline properly prior to the excavation of the
site by the contractor. On June 27,
2005, the Office of the California State Fire Marshal, Pipeline Safety
Division, referred to in this report as the CSFM, issued a notice of violation
against us which also alleged that we did not properly mark the location of the
pipeline in violation of state and federal regulations. The CSFM assessed a proposed civil penalty
of $0.5 million. The location of the
incident was not our work site, nor did we have any direct involvement in the
water main replacement project. We
believe that SFPP acted in accordance with applicable law and regulations, and
further that according to California law, excavators, such as the contractor on
the project, must take the necessary steps (including excavating with hand
tools) to confirm the exact location of a pipeline before using any power
operated or power driven excavation equipment.
Accordingly, we disagree with certain of the findings of CalOSHA and the
CSFM, and we have appealed the civil penalties while, at the same time,
continuing to work cooperatively with CalOSHA and the CSFM to resolve these
matters.

On
September 21, 2007, KMGP Services Company, Inc., an affiliate of Knight, entered
into a plea agreement and civil settlement with the District Attorney of Contra
Costa County pertaining to this accident.
Under the terms of the plea agreement, KMGP Services Company, Inc.
agreed to plead no contest to six counts of violating the California Labor
Code. While initially constituted as
felonies under the California Labor Code, the plea agreement contemplates that
following the successful completion of an independent audit of our right-of-way
protection policies and practices (likely in approximately one year), we may
move to reduce the felony counts to misdemeanors. Pursuant to the plea agreement and civil settlement, in October
2007, we paid approximately $15 million.

As
a result of the accident, nineteen separate lawsuits were filed. The majority of the cases were personal
injury and wrongful death actions that alleged, among other things, that
SFPP/Kinder Morgan failed to properly field mark the area where the accident
occurred.

Following
court ordered mediation, the Kinder Morgan defendants have settled with
plaintiffs in all of the wrongful death cases and the personal injury and
property damages cases. These
settlements have either become

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final by order
of the court or are awaiting court approval.
The only civil cases which remain pending at present are: (i) a
cross-claim for contribution and indemnity by an engineering company defendant
against the Kinder Morgan defendants in which the court has entered summary
judgment in favor of the Kinder Morgan defendants; and (ii) a challenge to the
court-ordered allocation of settlement proceeds in one of the
court-approved wrongful death
settlements filed by a nonresident sibling in which the court has also granted
summary judgment in favor of the Kinder Morgan defendants. Both of these judgments in favor of the
Kinder Morgan defendants are subject to potential appeal.

Additionally,
following this accident, we reviewed and when appropriate, revised our pipeline
policies and procedures to improve safety.
We have undertaken a number of actions to reduce future third-party
damage to our pipelines, including adding line riders and locators, retaining
third-party expertise, instituting enhanced line location training and
education of employees and contractors, and investing in additional
state-of-the-art line locating equipment.
We have also committed to various procedural requirements pertaining to
construction near our pipelines.

Consent
Agreement Regarding Cordelia, Oakland and Donner Summit California Releases

On
May 21, 2007, we and SFPP entered into a Consent Agreement with various
governmental agencies to resolve civil claims relating to the unintentional
release of petroleum products during three pipeline incidents in northern
California. The releases occurred (i)
in the Suisun Marsh area near Cordelia in Solano County, in April 2004; (ii) in
Oakland in February 2005; and (iii) near Donner Pass in April 2005. The agreement was reached with the United
States Environmental Protection Agency, referred to in this note as the EPA,
Department of the Interior, Department of Justice and the National Oceanic and
Atmospheric Administration, as well as the State of California Department of
Fish and Game, Office of Spill Prevention and Response, and the Regional Water
Quality Control Boards for the San Francisco and Lahontan regions. Under the Consent Agreement, we agreed to
pay approximately $3.8 million in civil penalties, $1.3 million in natural
resource damages and assessment costs and approximately $0.2 million in agency
response and future remediation monitoring costs. All of the civil penalties have been reserved for as of September
30, 2007. In addition, we agreed to
perform enhancements in our Pacific Operations relative to its spill prevention,
response and reporting practices, the majority of which have already been
implemented.

The
Consent Agreement was filed with the United States District Court for the
Eastern District of California on May 29, 2007 and became effective July 26,
2007. We have substantially completed
remediation and restoration activities in consultation with the appropriate
state and federal regulatory agencies at the location of each release.

EPA
Notice of Proposed Debarment

On
August 21, 2007, SFPP received a Notice of Proposed Debarment issued by the
United States Environmental Protection Agency, referred to in this report as
the EPA. Pursuant to the Notice, the
Suspension and Debarment Division of the EPA is proposing to debar SFPP from
participation in future Federal contracts and assistance activities for a
period of three years. The purported
basis for the proposed debarment is SFPPs April, 2005 agreement with the
California Attorney General and the District Attorney of Solano County,
California to settle misdemeanor charges of the unintentional, non-negligent
discharge of diesel fuel, and the failure to provide timely notice of a
threatened discharge to appropriate state agencies, in connection with the
April 28, 2004 spill of diesel fuel into a marsh near Cordelia,
California. SFPP believes that the
proposed debarment is factually and legally unwarranted and intends to contest
it. In addition, SFPP is currently
engaged in discussions with the EPA to attempt to resolve this matter. Based upon our discussions to date, we do
not believe that this matter will result in
the debarment or suspension of SFPP.

Baker,
California

In
November 2004, our CALNEV Pipeline experienced a failure from external damage
near Baker, California, resulting in a release of gasoline that affected
approximately two acres of land in the high desert administered by the U.S.
Bureau of Land Management. Remediation
has been conducted and continues for product in the soils. All agency requirements have been met and
the site will be closed upon completion of the soil remediation. The

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California
Department of Fish & Game has alleged a small natural resource damage claim
that is currently under review. CALNEV expects to work cooperatively with the
Department of Fish & Game to resolve this claim.

Henrico
County, Virginia

On
April 17, 2006, Plantation Pipe Line Company, which transports refined
petroleum products across the southeastern United States and which is 51.17%
owned and operated by us, experienced a pipeline release of turbine fuel from
its 12-inch pipeline. The release occurred in a residential area and impacted
adjacent homes, yards and common areas, as well as a nearby stream. The
released product did not ignite and there were no deaths or injuries.
Plantation estimates the amount of product released to be approximately 553
barrels. Immediately following the release, the pipeline was shut down and
emergency remediation activities were initiated. Remediation and monitoring
activities are ongoing under the supervision of the EPA, and the Virginia
Department of Environmental Quality, referred to in this report as VDEQ.
Following settlement negotiations and discussions with VDEQ, Plantation and
VDEQ entered into a Special Order on Consent under which Plantation agreed to
pay a civil penalty of approximately $0.7 million to VDEQ as well as reimburse
VDEQ for less than $0.1 million in expenses and oversight costs to resolve the
matter. Plantation satisfied $0.2 million of the civil penalty by completing a
supplemental environmental project in the form of a $0.2 million donation to
the Henrico County Fire Department for the purchase of hazardous material spill
response equipment.

Dublin,
California

In
June 2006, our SFPP pipeline experienced a leak near Dublin, California,
resulting in a release of product that affected a limited area along a
recreation path. We have completed remediation activities and have petitioned
the California Regional Water Quality Control Board for closure. The cause of
the release was outside force damage.

Soda
Springs, California

In
August 2006, our SFPP pipeline experienced a failure near Soda Springs,
California, resulting in a release of product that affected a limited area
along Interstate Highway 80. Product impacts were primarily limited to soil in
an area between the pipeline and Interstate Highway 80. Remediation and
monitoring activities are ongoing under the supervision of the California
Department of Fish & Game and Nevada County. The cause of the release was
determined to be pinhole corrosion in an unpiggable 2-inch diameter bypass to
the mainline valve. The bypass was installed to allow pipeline maintenance
activity. The bypass piping was replaced at this location and all other similar
designs on the pipeline segment were excavated, evaluated and replaced as
necessary to avoid future risk of release. On January 30, 2008, we entered into
a settlement agreement with Nevada County and the state of California to
resolve any outstanding civil penalties claims related to this release for
$75,000.

Rockies
Express Pipeline LLC Wyoming Construction Incident

On
November 11, 2006, a bulldozer operated by an employee of Associated Pipeline
Contractors, Inc, (a third-party contractor to Rockies Express Pipeline LLC,
referred to in this Note as REX), struck an existing subsurface natural gas
pipeline owned by Wyoming Interstate Company, a subsidiary of El Paso Pipeline
Group. The pipeline was ruptured, resulting in an explosion and fire. The
incident occurred in a rural area approximately nine miles southwest of
Cheyenne, Wyoming. The incident resulted in one fatality (the operator of the
bulldozer) and there were no other reported injuries. The cause of the incident
is under investigation by the U.S. Department of Transportation Pipeline and
Hazardous Materials Safety Administration, referred to in this report as the
PHMSA. We are cooperating with this agency. Immediately following the incident,
REX and El Paso Pipeline Group reached an agreement on a set of additional
enhanced safety protocols designed to prevent the reoccurrence of such an
incident.

In
September 2007, the family of the deceased bulldozer operator filed a wrongful
death action against us, Rockies Express Pipeline LLC and several other parties
in the District Court of Harris County, Texas, 189 Judicial District, at case
number 2007-57916. The plaintiffs seek unspecified compensatory and exemplary
damages plus interest, attorneys fees and costs of suit. We have asserted
contractual claims for complete indemnification for any and all costs arising
from this incident, including any costs related to this lawsuit, against third
parties and their

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insurers. The
parties are currently engaged in discovery. We do not expect the cost of any
settlement or eventual judgment, if any, to be material.

Charlotte,
North Carolina

On
November 27, 2006, the Plantation Pipeline experienced a release of
approximately 4,000 gallons of gasoline from a Plantation Pipe Line Company
block valve on a delivery line into a terminal owned by a third party company.
Upon discovery of the release, Plantation immediately locked out the delivery
of gasoline through that pipe to prevent further releases. Product had flowed
onto the surface and into a nearby stream, which is a tributary of Paw Creek,
and resulted in loss of fish and other biota. Product recovery and remediation
efforts were implemented immediately, including removal of product from the
stream. The line was repaired and put back into service within a few days.
Remediation efforts are continuing under the direction of the North Carolina
Department of Environment and Natural Resources (the NCDENR), which issued a
Notice of Violation and Recommendation of Enforcement against Plantation on
January 8, 2007. Plantation continues to cooperate fully with the NCDENR.

Although
Plantation does not believe that penalties are warranted, it is engaging in
settlement discussions with the EPA regarding a potential civil penalty for the
November 2006 release as part of broader settlement negotiations with the EPA
regarding this spill and two other historic releases from Plantation, including
a February 2003 release near Hull, Georgia. Plantation has reached an agreement
in principle with the Department of Justice and the EPA for
all four releases for approximately $0.7 million, plus some additional work to
be performed to prevent future releases. The parties are negotiating a consent
decree.  Although it is not possible to predict
the ultimate outcome, we believe, based on our experiences to date, that the
ultimate resolution of such items will not have a material adverse impact on
our business, financial position, results of operations or cash flows.

In
addition, in April 2007, during pipeline maintenance activities near Charlotte,
North Carolina, Plantation discovered the presence of historical soil
contamination near the pipeline, and reported the presence of impacted soils to
the NCDENR. Subsequently, Plantation contacted the owner of the property to
request access to the property to investigate the potential contamination. The
results of that investigation indicate that there is soil and groundwater
contamination which appears to be from an historical turbine fuel release. The
groundwater contamination is underneath at least two lots on which there is
current construction of single family homes as part of a new residential
development. Further investigation and remediation are being conducted under
the oversight of the NCDENR. Plantation is working with the owner of the
property and the builder of the residential subdivision to address any
potential claims that they may bring.

Barstow,
California

The
United States Department of Navy has alleged that historic releases of methyl
tertiary-butyl ether, referred to in this report as MTBE, from CalNev Pipe Line
Companys Barstow terminal has (i) migrated underneath the Navys Marine Corps
Logistics Base in Barstow; (ii) impacted the Navys existing groundwater
treatment system for unrelated groundwater contamination not alleged to have
been caused by CalNev, and (iii) could affect the MCLBs water supply system.
Although CalNev believes that it has certain meritorious defenses to the Navys
claims, we are working with the Navy to agree upon an Administrative Settlement
Agreement and Order on Consent for CERCLA Removal Action to reimburse the Navy
for $0.5 million in past response actions, plus perform other work to ensure
protection of the Navys existing treatment system and water supply.

Oil
Spill Near Westridge Terminal, Burnaby, British Columbia

On
July 24, 2007, a third-party contractor installing a sewer line for the City of
Burnaby struck a crude oil pipeline segment included within our Trans Mountain
pipeline system near its Westridge terminal in Burnaby, BC, resulting in a
release of approximately 1,400 barrels of crude oil. The release impacted the
surrounding neighborhood, several homes and nearby Burrard Inlet. No injuries
were reported. To address the release, we initiated a comprehensive emergency
response in collaboration with, among others, the City of Burnaby, the BC
Ministry of Environment, the National Energy Board, and the National
Transportation Safety Board. Cleanup and environmental remediation is
continuing. The incident is currently under investigation by Federal and
Provincial agencies. We do not expect this matter to have a material adverse
impact on our results of operations or cash flows.

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On
December 20, 2007 we initiated a lawsuit entitled Trans Mountain Pipeline LP,
Trans Mountain Pipeline Inc. and Kinder Morgan Canada Inc. v. The City of
Burnaby, et al., Supreme Court of British Columbia, Vancouver Registry No.
S078716. The suit alleges that the City of Burnaby and its agents are liable in
damages including, but not limited to, all costs and expenses incurred by us as
a result of the rupture of the pipeline and subsequent release of crude oil.

Although
no assurance can be given, we believe that we have meritorious defenses to all
pending pipeline integrity actions set forth in this note and, to the extent an
assessment of the matter is possible, if it is probable that a liability has
been incurred and the amount of loss can be reasonably estimated, we believe
that we have established an adequate reserve to cover potential liability.

Additionally,
although it is not possible to predict the ultimate outcomes, we also believe,
based on our experiences to date, that the ultimate resolution of these matters
will not have a material adverse impact on our business, financial position,
results of operations or cash flows. As of December 31, 2007, and December 31,
2006, we have recorded a total reserve for legal fees, transportation rate
cases and other litigation liabilities in the amount of $247.9 million and
$112.0 million, respectively. The reserve is primarily related to various
claims from lawsuits arising from our Pacific operations pipeline
transportation rates, and the contingent amount is based on both the
circumstances of probability and reasonability of dollar estimates. We
regularly assess the likelihood of adverse outcomes resulting from these claims
in order to determine the adequacy of our liability provision.

Environmental
Matters

Exxon
Mobil Corporation v. GATX Corporation, Kinder Morgan Liquids Terminals, Inc.
and ST Services, Inc.

On
April 23, 2003, Exxon Mobil Corporation filed a complaint in the Superior Court
of New Jersey, Gloucester County. We filed our answer to the complaint on June
27, 2003, in which we denied ExxonMobils claims and allegations as well as
included counterclaims against ExxonMobil. The lawsuit relates to environmental
remediation obligations at a Paulsboro, New Jersey liquids terminal owned by
ExxonMobil from the mid-1950s through November 1989, by GATX Terminals Corp.
from 1989 through September 2000, later owned by ST Services, Inc. Prior to
selling the terminal to GATX Terminals, ExxonMobil performed the environmental
site assessment of the terminal required prior to sale pursuant to state law.
During the site assessment, ExxonMobil discovered items that required
remediation and the New Jersey Department of Environmental Protection issued an
order that required ExxonMobil to perform various remediation activities to
remove hydrocarbon contamination at the terminal. ExxonMobil, we understand, is
still remediating the site and has not been removed as a responsible party from
the states cleanup order; however, ExxonMobil claims that the remediation
continues because of GATX Terminals storage of a fuel additive, MTBE, at the
terminal during GATX Terminals ownership of the terminal. When GATX Terminals
sold the terminal to ST Services, the parties indemnified one another for
certain environmental matters. When GATX Terminals was sold to us, GATX
Terminals indemnification obligations, if any, to ST Services may have passed
to us. Consequently, at issue is any indemnification obligation we may owe to
ST Services for environmental remediation of MTBE at the terminal. The
complaint seeks any and all damages related to remediating MTBE at the
terminal, and, according to the New Jersey Spill Compensation and Control Act,
treble damages may be available for actual dollars incorrectly spent by the
successful party in the lawsuit for remediating MTBE at the terminal. The
parties are currently involved in mandatory mediation with respect to the
claims set out in the lawsuit.

On
June 25, 2007, the New Jersey Department of Environmental Protection, the
Commissioner of the New Jersey Department of Environmental Protection and the
Administrator of the New Jersey Spill Compensation Fund, referred to
collectively as the plaintiffs, filed a complaint against Exxon Mobil
Corporation and GATX Terminals Corporation. The complaint was filed in
Gloucester County, New Jersey. The plaintiffs have not yet served the complaint
on either of the named defendants. The plaintiffs seek the costs and damages
that the plaintiffs allegedly have incurred or will incur as a result of the
discharge of pollutants and hazardous substances at the Paulsboro, New Jersey
facility. The costs and damages that the plaintiffs seek include damages to
natural resources. In addition, the plaintiffs seek an order compelling the
defendants to perform or fund the assessment and restoration of those natural
resource damages that are the result of the defendants actions. As in the case
brought by Exxon Mobil against GATX Terminals Corporation, the issue is whether
the plaintiffs claims are within the scope of the indemnity obligations GATX
Terminals and therefore, Kinder Morgan Liquids Terminals, owes to ST Services.

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The
City of Los Angeles v. Kinder Morgan Energy Partners, L.P.; Kinder Morgan
Liquids Terminals LLC; Kinder Morgan Tank Storage Terminals LLC; Continental
Oil Company; Chevron Corporation,California Superior Court, County of Los Angeles,
Case No. NC041463.

We
and some of our subsidiaries are defendants in a lawsuit filed in 2005 alleging
claims for environmental cleanup costs and rent at the former Los Angeles
Marine Terminal in the Port of Los Angeles. Plaintiff alleges that terminal
cleanup costs could approach $18 million; however, Kinder Morgan believes that
the clean up costs should be substantially less and that cleanup costs must be
apportioned among all the parties to the litigation. Plaintiff also alleges
that it is owed approximately $2.8 million in past rent and an unspecified
amount for future rent. The judge bifurcated that rent issue from the causes of
action related to the cleanup costs and a trial regarding the rent issue was
set for October 2007.

Plaintiff
and the Kinder Morgan defendants have since agreed to a settlement in principle
under which we agreed to pay $3.2 million in satisfaction of all past and
future rent obligations. In the fourth quarter of 2007, we finalized the
settlement terms, filed with the court for final approval, and paid the $3.2
million in satisfaction of all past and future rent obligations.

Mission
Valley Terminal Lawsuit

In
August 2007, the City of San Diego, on its own behalf and purporting to act on
behalf of the People of the state of California, filed a lawsuit against us and
several affiliates seeking injunctive relief and unspecified damages allegedly
resulting from hydrocarbon and MTBE impacted soils and groundwater beneath the
citys stadium property in San Diego arising from historic operations at the
Mission Valley terminal facility. The case was filed in the Superior Court of
California, San Diego County, case number 37-2007-00073033-CU-OR-CTL. On
September 26, 2007, we removed the case to the United States District Court,
Southern District of California, case number 07CV1883WCAB. On October 3, 2007,
we filed a Motion to Dismiss all counts of the Complaint, which motion is
currently pending. To the extent any claims survive the Motion to Dismiss, we
intend to vigorously defend against the claims asserted in the complaint. This
site has been, and currently is, under the regulatory oversight and order of
the California Regional Water Quality Control Board. We do not expect the cost of
any settlement and remediation to be material.

Portland
Harbor DOJ/EPA Investigation

The
United States Department of Justice and the United States Environmental
Protection Agency are continuing to investigate potential criminal charges
relating to an alleged instance of improper disposal at sea of potash which
allegedly occurred at the request of or with the knowledge of employees or
third parties at a bulk terminal facility in Portland, Oregon which we operate.
We are fully cooperating with the investigation and are engaged in ongoing
discussions with the office of the United States Attorney for the District of
Oregon and the Department of Justice in an attempt to resolve this matter.

Louisiana
Department of Environmental Quality Settlement

After
conducting a voluntary compliance self-audit, in April 2006, we voluntarily
disclosed certain findings from the audit related to compliance with
environmental regulations and permits at our Harvey and St. Gabriel Terminals
to the Louisiana Department of Environmental Quality, referred to in this
report as the LDEQ. Following further discussion between the LDEQ and us, in
August 2007, the LDEQ issued a Consolidated Compliance Order and Notice of
Potential Penalty for each of the two facilities. We and the LDEQ have reached
agreement on a proposed settlement agreement under which we agree to finalize
certain work, which we have already undertaken to ensure compliance with the
environmental regulations at these two facilities, and to pay a penalty of $0.3
million. The proposed settlement agreement is undergoing public comment
pursuant to LDEQ regulations, and then will be finalized.

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Other
Environmental

We
are subject to environmental cleanup and enforcement actions from time to time.
In particular, the federal Comprehensive Environmental Response, Compensation
and Liability Act (CERCLA) generally imposes joint and several liability for
cleanup and enforcement costs on current or predecessor owners and operators of
a site, among others, without regard to fault or the legality of the original
conduct. Our operations are also subject to federal, state and local laws and
regulations relating to protection of the environment. Although we believe our
operations are in substantial compliance with applicable environmental law and
regulations, risks of additional costs and liabilities are inherent in
pipeline, terminal and carbon dioxide field and oil field operations, and there
can be no assurance that we will not incur significant costs and liabilities.
Moreover, it is possible that other developments, such as increasingly
stringent environmental laws, regulations and enforcement policies thereunder,
and claims for damages to property or persons resulting from our operations,
could result in substantial costs and liabilities to us.

We
are currently involved in several governmental proceedings involving air, water
and waste violations issued by various governmental authorities related to
compliance with environmental regulations. As we receive notices of
non-compliance, we negotiate and settle these matters. We do not believe that
these violations will have a material adverse affect on our business.

We
are also currently involved in several governmental proceedings involving
groundwater and soil remediation efforts under administrative orders or related
state remediation programs issued by various regulatory authorities related to
compliance with environmental regulations associated with our assets. We have
established a reserve to address the costs associated with the cleanup.

In
addition, we are involved with and have been identified as a potentially
responsible party in several federal and state superfund sites. Environmental
reserves have been established for those sites where our contribution is
probable and reasonably estimable. In addition, we are from time to time
involved in civil proceedings relating to damages alleged to have occurred as a
result of accidental leaks or spills of refined petroleum products, natural gas
liquids, natural gas and carbon dioxide. See Pipeline Integrity and Releases
above for additional information with respect to ruptures and leaks from our
pipelines.

Although
it is not possible to predict the ultimate outcomes, we believe that the
resolution of the environmental matters set forth in this note will not have a
material adverse effect on our business, financial position, results of
operations or cash flows. However, we are not able to reasonably estimate when
the eventual settlements of these claims will occur and changing circumstances
could cause these matters to have a material adverse impact. As of December 31,
2007, we have accrued an environmental reserve of$92.0 million, and we believe the establishment of this
environmental reserve is adequate such that the resolution of pending
environmental matters will not have a material adverse impact on our business,
cash flows, financial position or results of operations. As of December 31,
2006, our environmental reserve totaled $64.2 million. Additionally, many
factors may change in the future affecting our reserve estimates, such as (i)
regulatory changes; (ii) groundwater and land use near our sites; and (iii)
changes in cleanup technology.

Other

We
are a defendant in various lawsuits arising from the day-to-day operations of
our businesses. Although no assurance can be given, we believe, based on our
experiences to date, that the ultimate resolution of such items will not have a
material adverse impact on our business, financial position, results of
operations or cash flows.

17. Regulatory Matters

The
tariffs we charge for transportation on our interstate common carrier pipelines
are subject to rate regulation by the FERC, under the Interstate Commerce Act.
The Interstate Commerce Act requires, among other things, that interstate
petroleum products pipeline rates be just and reasonable and nondiscriminatory.
Pursuant to FERC Order No. 561, effective January 1, 1995, interstate petroleum
products pipelines are able to change their rates within prescribed ceiling
levels that are tied to an inflation index. FERC Order No. 561-A, affirming and
clarifying Order No. 561, expanded the circumstances under which interstate
petroleum products pipelines may employ cost-of-

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service
ratemaking in lieu of the indexing methodology, effective January 1, 1995. For
each of the years ended December 31, 2007, 2006 and 2005, the application of
the indexing methodology did not significantly affect tariff rates on our
interstate petroleum products pipelines.

FERC
Order No. 2004/690

Since
November 2003, the FERC issued Orders No. 2004, 2004-A, 2004-B, 2004-C, and
2004-D, adopting new Standards of Conduct as applied to natural gas pipelines.
The primary change from existing regulation was to make such standards
applicable to an interstate natural gas pipelines interaction with many more
affiliates (referred to as energy affiliates), including intrastate/Hinshaw
natural gas pipelines (in general, a Hinshaw pipeline is a pipeline that
receives gas at or within a state boundary, is regulated by an agency of that
state, and all the gas it transports is consumed within that state), processors
and gatherers and any company involved in natural gas or electric markets
(including natural gas marketers) even if they do not ship on the affiliated
interstate natural gas pipeline. Local distribution companies were excluded,
however, if they do not make sales to customers not physically attached to
their system. The Standards of Conduct require, among other things, separate
staffing of interstate pipelines and their energy affiliates (but support
functions and senior management at the central corporate level may be shared)
and strict limitations on communications from an interstate pipeline to an
energy affiliate.

Every
interstate natural gas pipeline was required to file an Order No. 2004
compliance plan with the FERC, and on July 20, 2006, the FERC accepted our
interstate pipelines May 19, 2005 compliance filing under Order No. 2004. On
November 17, 2006, the United States Court of Appeals for the District of
Columbia Circuit, in Docket No. 04-1183, vacated FERC Orders 2004, 2004-A,
2004-B, 2004-C, and 2004-D as applied to natural gas pipelines, and remanded
these same orders back to the FERC.

On
January 9, 2007, the FERC issued an Interim Rule, effective January 9, 2007, in
response to the courts action. In the Interim Rule, the FERC readopted the
Standards of Conduct, but revised or clarified with respect to issues which had
been appealed to the court. Specifically, the following changes were made:

| |   |                                                                                                                                                                       
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | the Standards of Conduct apply only to the
  relationship between interstate gas transmission pipelines and their
  marketing affiliates, not their energy affiliates;
| |   |                                                                                                                                                                       
| |  | all risk management personnel can be
  shared;                                                                                                                        
| |   |                                                                                                                                                                       
| |  | the requirement to post discretionary
  tariff actions was eliminated (but interstate gas pipelines must still maintain
  a log of discretionary tariff waivers);     
| |   |                                                                                                                                                                       
| |  | lawyers providing legal advice may be
  shared employees; and                                                                                                         
| |   |                                                                                                                                                                       
| |  | new interstate gas transmission pipelines
  are not subject to the Standards of Conduct until they commence service.                                                  

The
FERC clarified that all exemptions and waivers issued under Order No. 2004
remain in effect. On January 18, 2007, the FERC issued a notice of proposed
rulemaking seeking comments regarding whether or not the Interim Rule should be
made permanent for natural gas transmission providers. On March 21, 2007, FERC
issued an Order on Clarification and Rehearing of the Interim Rule that granted
clarification that the Standards of Conduct only apply to natural gas
transmission providers that are affiliated with a marketing or brokering entity
that conducts transportation transactions on such gas transmission providers
pipeline.

Notice
of Inquiry  Financial Reporting

On
February 15, 2007, the FERC issued a notice of inquiry seeking comment on the
need for changes or revisions to the FERCs reporting requirements contained in
the financial forms for gas and oil pipelines and electric utilities. Initial
comments were filed by numerous parties on March 27, 2007, and reply comments
were filed on April 27, 2007.

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On
September 20, 2007, the FERC issued for public comment in Docket No. RM07-9 a
proposed rule which would revise its financial forms to require that additional
information be reported by natural gas companies. The proposed rule would
require, among other things, that natural gas companies: (i) submit additional
revenue information, including revenue from shipper-supplied gas; (ii) identify
the costs associated with affiliate transactions; and (iii) provide additional
information on incremental facilities and on discounted and negotiated rates.
The FERC proposes an effective date of January 1, 2008, which means that forms
reflecting the new requirements for 2008 would be filed in early 2009. Comments
on the proposed rule were filed by numerous parties on November 13, 2007.

Notice
of Inquiry  Fuel Retention Practices

On
September 20, 2007, the FERC issued a Notice of Inquiry seeking comment on
whether it should change its current policy and prescribe a uniform method for
all interstate gas pipelines to use in recovering fuel gas and gas lost and
unaccounted for. The Notice of Inquiry included numerous questions regarding
fuel recovery issues and the effects of fixed fuel percentages as compared with
tracking provisions. Comments on the Notice of Inquiry were filed by numerous
parties on November 30, 2007.

Notice
of Proposed Rulemaking  Promotion of a More Efficient Capacity Release Market

On
November 15, 2007, the FERC issued a notice of proposed rulemaking in Docket
No. RM 08-1-000 regarding proposed modifications to its Part 284 regulations
concerning the release of firm capacity by shippers on interstate natural gas
pipelines. The FERC proposes to remove, on a permanent basis, the rate ceiling
on capacity release transactions of one year or less. Additionally, the FERC
proposes to exempt capacity releases made as part of an asset management
arrangement from the prohibition on tying and from the bidding requirements of
section 284.8. Initial comments were filed by numerous parties on January 25,
2008.

Notice
of Proposed Rulemaking  Natural Gas Price Transparency

On
April 19, 2007, the FERC issued a notice of proposed rulemaking in Docket Nos.
RM07-10-000 and AD06-11-000 regarding price transparency provisions of Section
23 of the Natural Gas Act and the Energy Policy Act. In the notice, the FERC
proposed to revise its regulations to (i) require that intrastate pipelines
post daily the capacities of, and volumes flowing through, their major receipt
and delivery points and mainline segments in order to make available the
information to track daily flows of natural gas throughout the United States;
and (ii) require that buyers and sellers of more than a de minimis volume of
natural gas report annual numbers and volumes of relevant transactions to the
FERC in order to make possible an estimate of the size of the physical U.S.
natural gas market, assess the importance of the use of index pricing in that
market, and determine the size of the fixed-price trading market that produces
the information. The FERC believes these revisions to its regulations will
facilitate price transparency in markets for the sale or transportation of
physical natural gas in interstate commerce. Initial comments were filed on
July 11, 2007 and reply comments were filed on August 23, 2007. In addition,
the FERC conducted an informal workshop in this proceeding on July 24, 2007, to
discuss implementation and other technical issues associated with the proposals
set forth in the NOPR.

On
December 26, 2007, the FERC issued Order No. 704 in this docket implementing
only the annual reporting provisions of the NOPR with minimal changes to the
original proposal. The order becomes effective February 4, 2008. The initial
report is due May 1, 2009 for calendar year 2008. Subsequent reports are due by
May 1 of each year for the previous calendar year. Order 704 will require most,
if not all Kinder Morgan natural gas pipelines to report annual volumes of
relevant transactions to the FERC.

In
addition, on December 21, 2007, the FERC issued a new notice of proposed
rulemaking in Docket No. RM08-2-000 regarding the daily posting provisions that
were contained in Docket Nos. RM07-10-000 and AD06-11-000. The new NOPR
proposes to exempt from the daily posting requirements those non-interstate
pipelines that (i) flow less than 10 million MMBtus of natural gas per year,
(ii) fall entirely upstream of a processing plant, and (iii) deliver more than
ninety-five percent (95%) of the natural gas volumes they flow directly to
end-users. However, the new NOPR expands the proposal to require that both
interstate and non-exempt non-interstate pipelines post daily the capacities
of, volumes scheduled at, and actual volumes flowing through, their major
receipt and delivery points and

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mainline
segments. Initial comments are due March 13, 2008 and reply comments are due
April 14, 2008. A Technical Conference is scheduled for April 3, 2008.

Notice
of Proposed Rulemaking - Rural Onshore Low Stress Hazardous Liquids Pipelines

On
September 6, 2006, the PHMSA published a notice of proposed rulemaking (PHMSA
71 FR 52504) that proposed to extend certain threat-focused pipeline safety
regulations to rural onshore low-stress hazardous liquid pipelines within a
prescribed buffer of previously defined U.S. states. Low-stress hazardous
liquid pipelines, except those in populated areas or that cross commercially
navigable waterways, have not been subject to the safety regulations in PHMSA
49 CFR Part 195.1. According to the PHMSA, unusually sensitive areas are areas
requiring extra protection because of the presence of sole-source drinking
water resources, endangered species, or other ecological resources that could
be adversely affected by accidents or leaks occurring on hazardous liquid
pipelines.

The
notice proposed to define a category of regulated rural onshore low-stress
lines (rural lines operating at or below 20% of specified minimum yield
strength, with a diameter of eight and five-eighths inches or greater, located
in or within a quarter-mile of a U.S. state) and to require operators of these
lines to comply with a threat-focused set of requirements in Part 195 that
already apply to other hazardous liquid pipelines. The proposed safety
requirements addressed the most common threatscorrosion and third party
damageto the integrity of these rural lines. The proposal intended to provide
additional integrity protection, to avoid significant adverse environmental
consequences, and to improve public confidence in the safety of unregulated
low-stress lines.

Since
the new notice is a proposed rulemaking in which the PHMSA will consider
initial and reply comments from industry participants, it is not clear what
impact the final rule will have on the business of our intrastate and
interstate pipeline companies.

Natural
Gas Pipeline Expansion Filings

Rockies
Express Pipeline-Currently Certificated Facilities

We
operate and own a 51% ownership interest in West2East Pipeline LLC, a limited
liability company that is the sole owner of Rockies Express Pipeline LLC.
ConocoPhillips owns a 24% ownership interest in West2East Pipeline LLC and
Sempra Energy holds the remaining 25% interest. When construction of the entire
Rockies Express Pipeline project is completed, our ownership interest will be
reduced to 50% at which time the capital accounts of West2East Pipeline LLC
will be trued up to reflect our 50% economics in the project. According to the
provisions of current accounting standards, due to the fact that we will
receive 50% of the economics of the Rockies Express project on an ongoing
basis, we are not considered the primary beneficiary of West2East Pipeline LLC
and thus, we account for our investment under the equity method of accounting.

On
August 9, 2005, the FERC approved the application of Rockies Express Pipeline
LLC, formerly known as Entrega Gas Pipeline LLC, to construct 327 miles of
pipeline facilities in two phases. For phase I (consisting of two pipeline
segments), Rockies Express was granted authorization to construct and operate
approximately 136 miles of pipeline extending northward from the Meeker Hub,
located at the northern end of our TransColorado pipeline system in Rio Blanco
County, Colorado, to the Wamsutter Hub in Sweetwater County, Wyoming (segment
1), and then construct approximately 191 miles of pipeline eastward to the
Cheyenne Hub in Weld County, Colorado (segment 2). Construction of segments 1
and 2 has been completed, with interim service commencing on segment 1 on
February 24, 2006, and full in-service of both segments on February 14, 2007.
For phase II, Rockies Express was authorized to construct three compressor
stations referred to as the Meeker, Big Hole and Wamsutter compressor stations.
The Meeker and Wamsutter stations went into service in January 2008.
Construction of the Big Hole compressor station is planned to commence in the
second quarter of 2008, in order to meet an expected in-service date of June
30, 2009.

Rockies
Express Pipeline-West Project

On
April 19, 2007, the FERC issued a final order approving the Rockies Express
application for authorization to construct and operate certain facilities
comprising its proposed Rockies Express-West Project. This project is the
first planned segment extension of the Rockies Express currently certificated
facilities, and it will be comprised of

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approximately
713 miles of 42-inch diameter pipeline extending from the Cheyenne Hub to an
interconnection with Panhandle Eastern Pipe Line located in Audrain County,
Missouri. The segment extension proposes to transport approximately 1.5 billion
cubic feet per day of natural gas across the following five states: Wyoming,
Colorado, Nebraska, Kansas and Missouri. The project will also include certain
improvements to existing Rockies Express facilities located to the west of the
Cheyenne Hub. Construction commenced on May 21, 2007, and the project entered
interim service to upstream delivery points on January 12, 2008. This project
is expected to be fully operational in March 2008.

Rockies
Express Pipeline-East Project

On
April 30, 2007, Rockies Express filed an application with the FERC requesting a
certificate of public convenience and necessity that would authorize
construction and operation of the Rockies Express-East Project. The Rockies
Express-East Project will be comprised of approximately 639 miles of 42-inch
diameter pipeline commencing from the terminus of the Rockies Express-West
pipeline to a terminus near the town of Clarington in Monroe County, Ohio and
will be capable of transporting approximately 1.8 billion cubic feet per day of
natural gas. On September 7, 2007, the FERC issued a Notice of Schedule for
Environmental Review for the Rockies Express-East Project, referred to as the
posted schedule. Rockies Express has requested that the FERC issue an updated
scheduling order to modify the posted schedule for earlier resolution. Without
a modification of the posted schedule, Rockies Express has concerns about its
ability to complete its project by June 2009. Rockies Express is working
closely with the FERC staff and other cooperating agencies to meet a revised
schedule that was developed in consultation with the FERC staff at a public
meeting convened on September 21, 2007. On November 23, 2007, the FERC issued a
draft environmental impact statement for the project, in advance of the posted
schedule. Comments on the environmental impact statement were submitted January
14, 2008, also in advance of the posted schedule. While there can be no
assurance that the FERC will approve the revised schedule, subject to that
approval, the Rockies Express-East Project is expected to begin partial service
on December 31, 2008, and to be in full service in June 2009.

TransColorado
Pipeline

On
April 19, 2007, the FERC issued an order approving TransColorado Gas
Transmission Company LLCs application for authorization to construct and
operate certain facilities comprising its proposed Blanco-Meeker Expansion
Project. This project provides for the transportation of up to approximately
250 million cubic feet per day of natural gas from the Blanco Hub area in San
Juan County, New Mexico through TransColorados existing interstate pipeline
for delivery to the Rockies Express Pipeline at an existing point of
interconnection located in the Meeker Hub in Rio Blanco County, Colorado.
Construction commenced on May 9, 2007, and the project was completed and
entered service January 1, 2008.

Kinder
Morgan Interstate Gas Transmission Pipeline

On
August 6, 2007, KMIGT filed, in FERC Docket CP07-430, for regulatory approval
to construct and operate a 41-mile, $29 million natural gas pipeline from the
Cheyenne Hub to markets in and around Greeley, Colorado. When completed, the
Colorado Lateral will provide firm transportation of up to 55 million cubic
feet per day to a local utility under long-term contract. The FERC issued a
draft environmental assessment on the project on January 11, 2008, and comments
on the project were received February 11, 2008. Public Service Company of
Colorado, a competitor to serving markets off the Colorado Lateral, reported
that it had filed a complaint before the State of Colorado Public Utilities
Commission against Atmos, the anchor shipper on the project. The Colorado
Public Utilities Commission has set a hearing for April 8, 2008 on the
complaint. Public Service Company of Colorado has requested the FERC delay the
issuance of approvals to KMIGT, pending the outcome of the complaint
proceeding.

On
December 21, 2007, KMIGT filed, in Docket CP 08-44, for approval to expand its
system in Nebraska to serve incremental ethanol and industrial load. The
application is pending before the FERC until March 10, 2008, at which time the
project will be approved if no protests are filed.

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Kinder
Morgan Louisiana Pipeline

On
September 8, 2006, in FERC Docket No. CP06-449-000, we filed an application
with the FERC requesting approval to construct and operate our Kinder Morgan
Louisiana Pipeline. The natural gas pipeline will extend approximately 135
miles from Chenieres Sabine Pass liquefied natural gas terminal in Cameron
Parish, Louisiana, to various delivery points in Louisiana and will provide
interconnects with many other natural gas pipelines, including Natural Gas
Pipeline Company of America. The project is supported by fully subscribed
capacity and long-term customer
commitments with Chevron and Total. The entire project cost is approximately
$510 million project and it is expected to be in service by January 1, 2009.

On
March 15, 2007, the FERC issued a preliminary determination that the
authorizations requested, subject to some minor modifications, will be in the
public interest. This order does not consider or evaluate any of the
environmental issues in this proceeding. On April 19, 2007, the FERC issued the
final Environmental Impact Statement, which addressed the potential
environmental effects of the construction and operation of the Kinder Morgan
Louisiana Pipeline. The final EIS was prepared to satisfy the requirements of
the National Environmental Policy Act. It concluded that approval of the Kinder
Morgan Louisiana Pipeline project would have limited adverse environmental
impacts. On June 22, 2007, the FERC issued an order granting construction and
operation of the project. Kinder Morgan Louisiana Pipeline officially accepted
the order on July 10, 2007.

Midcontinent
Express Pipeline

On
October 9, 2007, in Docket No. CP08-6-000, Midcontinent Express Pipeline LLC
filed an application with the FERC requesting a certificate of public
convenience and necessity that would authorize construction and operation of
the approximate 500-mile Midcontinent Express Pipeline natural gas transmission
system. On February 8, 2008, the FERC issued a draft environmental impact
statement which stated that the building and operation of the proposed 504-mile
Midcontinent Express Pipeline would result in limited adverse environmental
impact. A final environmental impact statement must be released before the FERC
can issue a certificate authorizing construction. Subject to the receipt of
regulatory approvals, construction of the pipeline is expected to commence in
August 2008 and be in service during the first quarter of 2009.

The
Midcontinent Express Pipeline will create long-haul, firm transportation
takeaway capacity either directly or indirectly connected to natural gas
producing regions located in Texas, Oklahoma and Arkansas. The pipeline will
originate in southeastern Oklahoma and traverse east through Texas, Louisiana,
Mississippi, and terminate close to the Alabama border, providing capability to
transport natural gas supplies to major pipeline interconnects along the route
up to its terminus at Transcos Station 85. The Midcontinent Express Pipeline
will have an initial capacity of up to 1.4 billion cubic feet and a total
capital cost of approximately $1.3 billion. The pipeline is a 50/50 joint
venture between ourselves and Energy Transfer Partners, L.P.

18. Recent Accounting Pronouncements

SFAS
No. 123R

On
December 16, 2004, the Financial Accounting Standards Board issued SFAS No.
123R (revised 2004), Share-Based Payment. This Statement amends SFAS No. 123,
Accounting for Stock-Based Compensation, and requires companies to expense
the value of employee stock options and similar awards. Significant provisions
of SFAS No. 123R include the following: (i) share-based payment awards result
in a cost that will be measured at fair value on the awards grant date, based
on the estimated number of awards that are expected to vest (compensation cost
for awards that vest would not be reversed if the awards expire without being
exercised); (ii) when measuring fair value, companies can choose an
option-pricing model that appropriately reflects their specific circumstances
and the economics of their transactions; and (iii) companies will recognize
compensation cost for share-based payment awards as they vest, including the
related tax effects. Upon settlement of share-based payment awards, the tax
effects will be recognized in the income statement or additional paid-in
capital.

For
us, this Statement became effective January 1, 2006. However, we have not
granted common unit options or made any other share-based payment awards since
May 2000, and as of December 31, 2005, all outstanding options

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to purchase
our common units were fully vested. Therefore, the adoption of this Statement did
not have an effect on our consolidated financial statements due to the fact
that we have reached the end of the requisite service period for any
compensation cost resulting from share-based payments made under our common
unit option plan.

SFAS
No. 154

On
June 1, 2005, the FASB issued SFAS No. 154, Accounting Changes and Error
Corrections. This Statement replaces Accounting Principles Board Opinion No.
20, Accounting Changes and SFAS No. 3, Reporting Accounting Changes in Interim
Financial Statements. SFAS No. 154 applies to all voluntary changes in
accounting principle, and changes the requirements for accounting for and
reporting of a change in accounting principle. SFAS No. 154 requires
retrospective application to prior periods financial statements of a voluntary
change in accounting principle unless it is impracticable. In contrast, APB No.
20 previously required that most voluntary changes in accounting principle be
recognized by including in net income of the period of the change the
cumulative effect of changing to the new accounting principle.

The
provisions of this Statement are effective for accounting changes and
corrections of errors made in fiscal years beginning after December 15, 2005
(January 1, 2006 for us). The Statement does not change the transition
provisions of any existing accounting pronouncements, including those that are
in a transition phase as of the effective date of this Statement. Adoption of
this Statement did not have any immediate effect on our consolidated financial
statements, and we will apply this guidance prospectively.

EITF
04-5

In
June 2005, the Emerging Issues Task Force reached a consensus on Issue No.
04-5, or EITF 04-5, Determining Whether a General Partner, or the General
Partners as a Group, Controls a Limited Partnership or Similar Entity When the
Limited Partners Have Certain Rights. EITF 04-5 provides guidance for purposes
of assessing whether certain limited partners rights might preclude a general
partner from controlling a limited partnership.

For
general partners of all new limited partnerships formed, and for existing
limited partnerships for which the partnership agreements are modified, the
guidance in EITF 04-5 is effective after June 29, 2005. For general partners in
all other limited partnerships, the guidance is effective no later than the
beginning of the first reporting period in fiscal years beginning after
December 15, 2005 (January 1, 2006, for us). The adoption of EITF 04-5 did not
have an effect on our consolidated financial statements.

Nonetheless,
as a result of EITF 04-5, as of January 1, 2006, our financial statements are
consolidated into the consolidated financial statements of Knight.
Notwithstanding the consolidation of our financial statements into the
consolidated financial statements of Knight pursuant to EITF 04-5, Knight 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 Knights financial statements is a legal
determination based on the entity that incurs the liability. The determination
of responsibility for payment among entities in our consolidated group of subsidiaries
was not impacted by the adoption of EITF 04-5.

SFAS
No. 155

On
February 16, 2006, the FASB issued SFAS No. 155, Accounting for Certain Hybrid
Financial Instruments. This Statement amends SFAS No. 133, Accounting for
Derivative Instruments and Hedging Activities and SFAS No. 140, Accounting
for Transfers and Servicing of Financial Assets and Extinguishments of
Liabilities. This Statement allows financial instruments that have embedded
derivatives to be accounted for as a whole (eliminating the need to bifurcate
the derivative from its host) if the holder elects to account for the whole
instrument on a fair value basis. For us, this Statement became effective
January 1, 2007. Adoption of this Statement has had no effect on our
consolidated financial statements.

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SFAS
No. 156

On
March 17, 2006, the FASB issued SFAS No. 156, Accounting for Servicing of
Financial Assets. This Statement amends SFAS No. 140 and addresses the
recognition and measurement of separately recognized servicing assets and
liabilities, such as those common with mortgage securitization activities, and
provides an approach to simplify efforts to obtain hedge-like (offset)
accounting by permitting a servicer that uses derivative financial instruments
to offset risks on servicing to report both the derivative financial instrument
and related servicing asset or liability by using a consistent measurement
attributefair value. For us, this Statement became effective January 1, 2007. Adoption
of this Statement has had no effect on our consolidated financial statements.

EITF
06-3

On
June 28, 2006, the FASB ratified the consensuses reached by the Emerging Issues
Task Force on EITF 06-3, How Taxes Collected from Customers and Remitted to
Governmental Authorities Should Be Presented in the Income Statement (That is,
Gross versus Net Presentation). According to the provisions of EITF 06-3: (i)
taxes assessed by a governmental authority that are directly imposed on a revenue-producing
transaction between a seller and a customer may include, but are not limited
to, sales, use, value added, and some excise taxes; and (ii) the presentation
of such taxes on either a gross (included in revenues and costs) or a net
(excluded from revenues) basis is an accounting policy decision that should be
disclosed pursuant to Accounting Principles Board Opinion No. 22 (as amended)
Disclosure of Accounting Policies.

In
addition, for any such taxes that are reported on a gross basis, a company
should disclose the amounts of those taxes in interim and annual financial
statements for each period for which an income statement is presented if those
amounts are significant. The disclosure of those taxes can be done on an
aggregate basis. EITF 06-3 applies to financial reports for interim and annual
reporting periods beginning after December 15, 2006 (January 1, 2007 for us).
The adoption of EITF 06-3 had no effect on our consolidated financial
statements.

FIN
48

In
July 2006, the FASB issued Interpretation (FIN) No. 48, Accounting for
Uncertainty in Income Taxesan Interpretation of FASB Statement No. 109, which
became effective January 1, 2007. FIN 48 addressed the determination of how tax
benefits claimed or expected to be claimed on a tax return should be recorded
in the financial statements. Under FIN 48, we must recognize the tax benefit
from an uncertain tax position only if it is more likely than not that the tax
position will be sustained on examination by the taxing authorities, based not
only on the technical merits of the tax position based on tax law, but also the
past administrative practices and precedents of the taxing authority. The tax
benefits recognized in the financial statements from such a position are
measured based on the largest benefit that has a greater than 50% likelihood of
being realized upon ultimate resolution.

Our
adoption of FIN No. 48 on January 1, 2007 did not result in a cumulative effect
adjustment to Partners Capital on our consolidated balance sheet. A
reconciliation of our beginning and ending gross unrecognized tax benefits for
2007 is as follows (in millions):

|                                                      |  |      |      |  
|----------------------------------------------------- |  | ---- | ---- | -
|                                                      |  | 2007 |     
|                                                      |  |      |      |  
|Balance at beginning of
  period                      |  | $    | 3.2  |  
|Additions
based on current year tax positions         |  |      | 4.7  |  
|Additions
based on prior year tax positions           |  |      | 0.1  |  
|Reductions
based on settlements with taxing authority |  |      |     |  
|Reductions due
to lapse in statute of limitations     |  |      | (1.7 | )
|                                                      |  |      |      |  
|Balance at end of period                              |  | $    | 6.3  |  
|                                                      |  |      |      |  

Our
continuing practice is to recognize interest and/or penalties related to income
tax matters in income tax expense, and as of January 1, 2007, we had $1.1
million of accrued interest and no accrued penalties. As of December 31, 2007
(i) we had $0.6 million of accrued interest and no accrued penalties; (ii) we
believe it is reasonably possible that our liability for unrecognized tax
benefits will decrease by approximately $1.2 million during the next twelve
months; and (iii) we believe approximately $5.4 million of the total $6.3
million of unrecognized tax benefits on our consolidated balance sheet as of
December 31, 2007 would affect our effective

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income tax
rate in future periods in the event those unrecognized tax benefits were
recognized. In addition, we have U.S. and state tax years open to examination
for the periods 2003 through 2007.

SAB
108

In
September 2006, the Securities and Exchange Commission issued Staff Accounting
Bulletin No. 108. This Bulletin requires a dual approach for quantifications
of errors using both a method that focuses on the income statement impact,
including the cumulative effect of prior years misstatements, and a method
that focuses on the period-end balance sheet. For us, SAB No. 108 was effective
January 1, 2007. The adoption of this Bulletin did not have a material impact
on our consolidated financial statements, and we will apply this guidance
prospectively.

SFAS
No. 157

On
September 15, 2006, the FASB issued SFAS No. 157, Fair Value Measurements.
This Statement establishes a single definition of fair value and a framework
for measuring fair value in generally accepted accounting principles that
should result in increased consistency and comparability in fair value measurements.
SFAS No. 157 also expands disclosures about fair value measurements, improving
the quality of information provided to users of financial statements. The
provisions of this Statement apply to other accounting pronouncements that
require or permit fair value measurements; the Board having previously
concluded in those accounting pronouncements that fair value is the relevant
measurement attribute. Accordingly, this Statement does not require any new
fair value measurements.

On
February 12, 2008, the FASB issued Financial Staff Position FAS 157-2,
Effective Date of FASB Statement No. 157. This Staff Position delays the
effective date of SFAS No. 157 for all nonfinancial assets and nonfinancial
liabilities, except those that are recognized or disclosed at fair value in the
financial statements on a recurring basis (at least annually). The delay is
intended to allow the Board and constituents additional time to consider the
effect of various implementation issues that have arisen, or that may arise,
from the application of SFAS No. 157.

The
remainder of SFAS No. 157 was adopted by us effective January 1, 2008. The
adoption of this Statement did not have an impact on our balance sheet,
statement of income, or statement of cash flows since we already apply its
basic concepts in measuring fair values.

SFAS
No. 158

On
September 29, 2006, the FASB issued SFAS No. 158, Employers Accounting for
Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statement
Nos. 87, 88, 106 and 132(R). This Statement requires an employer to: (i)
recognize the overfunded or underfunded status of a defined benefit pension
plan or postretirement benefit plan (other than a multiemployer plan) as an
asset or liability in its statement of financial position; (ii) measure a
plans assets and its obligations that determine its funded status as of the
end of the employers fiscal year (with limited exceptions), and to disclose in
the notes to financial statements additional information about certain effects
on net periodic benefit cost for the next fiscal year that arise from delayed
recognition of the gains or losses, prior service costs or credits, and
transition assets or obligations; and (iii) recognize changes in the funded
status of a plan in the year in which the changes occur through comprehensive
income.

Past
accounting standards only required an employer to disclose the complete funded
status of its plans in the notes to the financial statements. Recognizing the
funded status of a companys benefit plans as a net liability or asset on its
balance sheet will require an offsetting adjustment to Accumulated other
comprehensive income/loss in shareholders equity (Partners Capital for
us). SFAS No. 158 does not change how pensions and other postretirement
benefits are accounted for and reported in the income statementcompanies will
continue to follow the existing guidance in previous accounting standards.
Accordingly, the amounts to be recognized in Accumulated other comprehensive
income/loss representing unrecognized gains/losses, prior service
costs/credits, and transition assets/obligations will continue to be amortized
under the existing guidance. Those amortized amounts will continue to be
reported as net periodic benefit cost in the income statement. Prior to SFAS
No. 158, those unrecognized amounts were only disclosed in the notes to the
financial statements.

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According
to the provisions of this Statement, an employer with publicly traded equity
securities is required to initially recognize the funded status of a defined
benefit pension plan or postretirement benefit plan and to provide the required
disclosures as of the end of the fiscal year ending after December 15, 2006
(December 31, 2006 for us). For us, the adoption of this part of SFAS No. 158
did not have a material effect on our statement of financial position as of
December 31, 2006.

In
addition, the requirement to measure plan assets and benefit obligations as of
the date of the employers fiscal year-end statement of financial position is
effective for fiscal years ending after December 15, 2008 (December 31, 2008
for us). In the year that the measurement date provisions of this Statement are
initially applied, a business entity is required to disclose the separate
adjustments of retained earnings (Partners Capital for us) and Accumulated
other comprehensive income/loss from applying this Statement. While earlier
application of the recognition of measurement date provisions is allowed, we
have opted not to adopt this part of the Statement early. For more information
on our pensions and other post-retirement benefit plans, and our disclosures
regarding the provisions of this Statement, please see Note 10.

SFAS
No. 159

On
February 15, 2007, the FASB issued SFAS No. 159, The Fair Value Option for
Financial Assets and Financial Liabilities. This Statement provides companies
with an option to report selected financial assets and liabilities at fair
value. The Statements objective is to reduce both complexity in accounting for
financial instruments and the volatility in earnings caused by measuring
related assets and liabilities differently. The Statement also establishes
presentation and disclosure requirements designed to facilitate comparisons
between companies that choose different measurement attributes for similar
types of assets and liabilities.

SFAS
No. 159 requires companies to provide additional information that will help investors
and other users of financial statements to more easily understand the effect of
the companys choice to use fair value on its earnings. It also requires
entities to display the fair value of those assets and liabilities for which
the company has chosen to use fair value on the face of the balance sheet. The
Statement does not eliminate disclosure requirements included in other
accounting standards, including requirements for disclosures about fair value
measurements included in SFAS No. 157, discussed above, and SFAS No. 107
Disclosures about Fair Value of Financial Instruments.

This
Statement was adopted by us effective January 1, 2008, at which time no
financial assets or liabilities, not previously required to be recorded at fair
value by other authoritative literature, were designated to be recorded at fair
value. As such, the adoption of this Statement did not have any impact on our
financial statements.

SFAS
141(R)

On
December 4, 2007, the FASB issued SFAS No. 141R (revised 2007), Business
Combinations. Although this statement amends and replaces SFAS No. 141, it
retains the fundamental requirements in SFAS No. 141 that (i) the purchase
method of accounting be used for all business combinations; and (ii) an acquirer
be identified for each business combination. SFAS No. 141R defines the acquirer
as the entity that obtains control of one or more businesses in the business
combination and establishes the acquisition date as the date that the acquirer
achieves control. This Statement applies to all transactions or other events in
which an entity (the acquirer) obtains control of one or more businesses (the
acquiree), including combinations achieved without the transfer of
consideration; however, this Statement does not apply to a combination between
entities or businesses under common control.

Significant
provisions of SFAS No. 141R concern principles and requirements for how an
acquirer (i) recognizes and measures in its financial statements the identifiable
assets acquired, the liabilities assumed, and any noncontrolling interest in
the acquiree; (ii) recognizes and measures the goodwill acquired in the
business combination or a gain from a bargain purchase; and (iii) determines
what information to disclose to enable users of the financial statements to
evaluate the nature and financial effects of the business combination.

This
Statement applies prospectively to business combinations for which the
acquisition date is on or after the beginning of the first annual reporting
period beginning on or after December 15, 2008 (January 1, 2009 for us). Early
adoption is not permitted. We are currently reviewing the effects of this
Statement.

205

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SFAS No. 160

On
December 4, 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in
Consolidated Financial Statements  an amendment of ARB No. 51. This Statement
changes the accounting and reporting for noncontrolling interests in consolidated
financial statements. A noncontrolling interest, sometimes referred to as a
minority interest, is the portion of equity in a subsidiary not attributable,
directly or indirectly, to a parent.

Specifically,
SFAS No. 160 establishes accounting and reporting standards that require (i)
the ownership interests in subsidiaries held by parties other than the parent
be clearly identified, labeled, and presented in the consolidated balance sheet
within equity, but separate from the parents equity; (ii) the equity amount of
consolidated net income attributable to the parent and to the noncontrolling
interest be clearly identified and presented on the face of the consolidated
income statement (consolidated net income and comprehensive income will be
determined without deducting minority interest, however, earnings-per-share
information will continue to be calculated on the basis of the net income
attributable to the parents shareholders); and (iii) changes in a parents
ownership interest while the parent retains its controlling financial interest
in its subsidiary be accounted for consistently and similarlyas equity
transactions.

This
Statement is effective for fiscal years, and interim period within those fiscal
years, beginning on or after December 15, 2008 (January 1, 2009 for us). Early
adoption is not permitted. SFAS No. 160 shall be applied prospectively as of
the beginning of the fiscal year in which it is initially applied, except for
its presentation and disclosure requirements, which shall be applied
retrospectively for all periods presented. We are currently reviewing the
effects of this Statement.

19. Quarterly
Financial Data (Unaudited)

|                 |  |                      |   |                    |  |                                       |  |                                         |       |            |  |  |   |        |   |  |  |   |       |  |  |  |   |        |   | 
|---------------- |  | -------------------- | - | ------------------ |  | ------------------------------------- |  | --------------------------------------- | ----- | ---------- |  |  | - | ------ | - |  |  | - | ----- |  |  |  | - | ------ | - | 
|                 |  | Operating
  Revenues |   | Operating
  Income |  | Income from
  Continuing
  Operations |  | Income from
  Discontinued
  Operations |       | Net Income | 
|                 |  |                      |   |                    |  |                                       |  |                                         |       |            | 
|                 |  | (In millions)        |  
|2007             |  |                      |   |                    |  |                                       |  |                                         |       |            |  |  |   |        |   | 
|First
Quarter(a) |  |                      | $ | 2,171.7            |  |                                       |  | $                                       | (75.5 | )          |  |  | $ | (156.6 | ) |  |  | $ | 7.1   |  |  |  | $ | (149.5 | ) | 
|Second
Quarter   |  |                      |   | 2,366.4            |  |                                       |  |                                         | 314.6 |            |  |  |   | 227.3  |   |  |  |   | 5.4   |  |  |  |   | 232.7  |   | 
|Third
Quarter    |  |                      |   | 2,230.8            |  |                                       |  |                                         | 311.4 |            |  |  |   | 205.2  |   |  |  |   | 8.6   |  |  |  |   | 213.8  |   | 
|Fourth
Quarter   |  |                      |   | 2,448.8            |  |                                       |  |                                         | 257.2 |            |  |  |   | 140.5  |   |  |  |   | 152.8 |  |  |  |   | 293.3  |   | 
|2006             |  |                      |   |                    |  |                                       |  |                                         |       |            |  |  |   |        |   |  |  |   |       |  |  |  |   |        |   | 
|First
Quarter    |  |                      | $ | 2,413.3            |  |                                       |  | $                                       | 314.0 |            |  |  | $ | 249.9  |   |  |  | $ | 3.0   |  |  |  | $ | 252.9  |   | 
|Second
Quarter   |  |                      |   | 2,216.1            |  |                                       |  |                                         | 317.7 |            |  |  |   | 251.0  |   |  |  |   | 3.4   |  |  |  |   | 254.4  |   | 
|Third
Quarter    |  |                      |   | 2,296.8            |  |                                       |  |                                         | 311.4 |            |  |  |   | 227.1  |   |  |  |   | 2.4   |  |  |  |   | 229.5  |   | 
|Fourth
Quarter   |  |                      |   | 2,122.5            |  |                                       |  |                                         | 348.5 |            |  |  |   | 261.8  |   |  |  |   | 5.5   |  |  |  |   | 267.3  |   | 

206

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|                                                  |  |                                                |   |                                                  |   |            |  |   |      |  |  |  |   |       |   | 
|------------------------------------------------- |  | ---------------------------------------------- | - | ------------------------------------------------ | - | ---------- |  | - | ---- |  |  |  | - | ----- | - | 
|                                                  |  | Income
  (loss) from
  Continuing
  Operations |   | Income (loss)
  from
  Discontinued
  Operations |   | Net Income | 
|                                                  |  |                                                |   |                                                  |   |            | 
|Basic Limited Partners
income (loss) per Unit:   |  |                                                |   |                                                  |   |            |  |   |      | 
|2007                                              |  |                                                |   |                                                  |   |            |  |   |      | 
|First
Quarter(a)                                  |  |                                                | $ | (1.27                                            | ) |            |  | $ | 0.03 |  |  |  | $ | (1.24 | ) | 
|Second
Quarter                                    |  |                                                |   | 0.34                                             |   |            |  |   | 0.02 |  |  |  |   | 0.36  |   | 
|Third
Quarter                                     |  |                                                |   | 0.21                                             |   |            |  |   | 0.03 |  |  |  |   | 0.24  |   | 
|Fourth
Quarter                                    |  |                                                |   | (0.12                                            | ) |            |  |   | 0.62 |  |  |  |   | 0.50  |   | 
|2006                                              |  |                                                |   |                                                  |   |            |  |   |      |  |  |  |   |       |   | 
|First
Quarter                                     |  |                                                | $ | 0.54                                             |   |            |  | $ | 0.02 |  |  |  | $ | 0.56  |   | 
|Second
Quarter                                    |  |                                                |   | 0.55                                             |   |            |  |   | 0.01 |  |  |  |   | 0.56  |   | 
|Third
Quarter                                     |  |                                                |   | 0.41                                             |   |            |  |   | 0.01 |  |  |  |   | 0.42  |   | 
|Fourth
Quarter                                    |  |                                                |   | 0.62                                             |   |            |  |   | 0.02 |  |  |  |   | 0.64  |   | 
|Diluted Limited
Partners income (loss) per Unit: |  |                                                |   |                                                  |   |            |  |   |      |  |  |  |   |       |   | 
|2007                                              |  |                                                |   |                                                  |   |            |  |   |      |  |  |  |   |       |   | 
|First
Quarter(a)                                  |  |                                                | $ | (1.27                                            | ) |            |  | $ | 0.04 |  |  |  | $ | (1.23 | ) | 
|Second
Quarter                                    |  |                                                |   | 0.34                                             |   |            |  |   | 0.02 |  |  |  |   | 0.36  |   | 
|Third
Quarter                                     |  |                                                |   | 0.21                                             |   |            |  |   | 0.03 |  |  |  |   | 0.24  |   | 
|Fourth
Quarter                                    |  |                                                |   | (0.12                                            | ) |            |  |   | 0.62 |  |  |  |   | 0.50  |   | 
|2006                                              |  |                                                |   |                                                  |   |            |  |   |      |  |  |  |   |       |   | 
|First
Quarter                                     |  |                                                | $ | 0.54                                             |   |            |  | $ | 0.02 |  |  |  | $ | 0.56  |   | 
|Second
Quarter                                    |  |                                                |   | 0.54                                             |   |            |  |   | 0.02 |  |  |  |   | 0.56  |   | 
|Third
Quarter                                     |  |                                                |   | 0.41                                             |   |            |  |   | 0.01 |  |  |  |   | 0.42  |   | 
|Fourth
Quarter                                    |  |                                                |   | 0.62                                             |   |            |  |   | 0.02 |  |  |  |   | 0.64  |   | 

|    |                                                                                                                                                               
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------
|(a) | 2007 first quarter includes
  an expense of $377.1 million attributable to a goodwill impairment charge
  recognized by Knight, as discussed in Notes 3 and 8.

20. Supplemental Information on Oil and Gas
Producing Activities (Unaudited)

The
Supplementary Information on Oil and Gas Producing Activities is presented as
required by SFAS No. 69, Disclosures about Oil and Gas Producing Activities.
The supplemental information includes capitalized costs related to oil and gas
producing activities; costs incurred for the acquisition of oil and gas
producing activities, exploration and development activities; and the results
of operations from oil and gas producing activities.

Supplemental
information is also provided for per unit production costs; oil and gas
production and average sales prices; the estimated quantities of proved oil and
gas reserves; the standardized measure of discounted future net cash flows
associated with proved oil and gas reserves; and a summary of the changes in
the standardized measure of discounted future net cash flows associated with
proved oil and gas reserves.

Our
capitalized costs consisted of the following (in millions):

|                                                                |  |              |         |      |   |         |   |   |         |  
|--------------------------------------------------------------- |  | ------------ | ------- | ---- | - | ------- | - | - | ------- | -
|Capitalized Costs Related to Oil and Gas Producing
  Activities
|                                                                |  | December 31,
|                                                                |  |             
|                                                                |  | 2007         |         | 2006 |   | 2005    |  
|                                                                |  |              |         |      |   |         |  
|Consolidated Companies(a)                                       |  |             
|Wells and equipment,
  facilities and other                     |  | $            | 1,612.5 |      | $ | 1,369.5 |   | $ | 1,097.9 |  
|Leasehold                                                       |  |              | 348.1   |      |   | 347.4   |   |   | 320.7   |  
|                                                                |  |              |         |      |   |         |   |   |         |  
|Total proved oil and gas
  properties                           |  |              | 1,960.6 |      |   | 1,716.9 |   |   | 1,418.6 |  
|Accumulated depreciation
  and depletion                        |  |              | (725.5  | )    |   | (470.2  | ) |   | (303.3  | )
|                                                                |  |              |         |      |   |         |   |   |         |  
|Net capitalized costs                                           |  | $            | 1,235.1 |      | $ | 1,246.7 |   | $ | 1,115.3 |  
|                                                                |  |              |         |      |   |         |   |   |         |  

|    |                                                                                                                                                                                                                                                                                          
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(a) | Amounts relate to Kinder
  Morgan CO2 Company, L.P. and its consolidated subsidaries.
  Includes capitalized asset retirement costs and associated accumulated
  depreciation. There are no capitalized costs associated with unproved oil and
  gas properties for the periods reported.

Our
costs incurred for property acquisition, exploration and development were as
follows (in millions):

|                                                                       |  |                         |       |      |   |       |  |   |       | 
|---------------------------------------------------------------------- |  | ----------------------- | ----- | ---- | - | ----- |  | - | ----- | 
|Costs Incurred in Exploration, Property Acquisitions and
  Development
|                                                                       |  | Year Ended December 31,
|                                                                       |  |                        
|                                                                       |  | 2007                    |       | 2006 |   | 2005  | 
|                                                                       |  |                         |       |      |   |       | 
|Consolidated
  Companies(a)                                            |  |                        
|Property Acquisition                                                   |  |                         |       |      |   |       |  |   |       | 
|Proved oil and gas
  properties                                        |  | $                       |      |      | $ | 36.6  |  | $ | 6.4   | 
|Development                                                            |  |                         | 244.4 |      |   | 261.8 |  |   | 281.7 | 

|    |                                                                                                                                                                                                                                                                                                                                                        
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(a) | Amounts relate to Kinder
  Morgan CO2 Company, L.P. and its consolidated
  subsidaries. There are no capitalized costs associated with unproved oil and
  gas properties for the periods reported. All capital expenditures were made
  to develop our proved oil and gas properties and no exploration costs were
  incurred for the periods reported.

207

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Our
results of operations from oil and gas producing activities for each of the
years 2007, 2006 and 2005 are shown in the following table (in millions):

|                                                           |  |                         |       |      |   |       |  |   |       | 
|---------------------------------------------------------- |  | ----------------------- | ----- | ---- | - | ----- |  | - | ----- | 
|Results of Operations for Oil and Gas Producing
Activities | 
|                                                          
|                                                           |  | Year Ended December 31, |      
|                                                           |  |                         |      
|                                                           |  | 2007                    |       | 2006 |   | 2005  | 
|                                                           |  |                         |       |      |   |       | 
|Consolidated
  Companies(a)                                |  |                         |       |      |   |       | 
|Revenues(b)                                                |  | $                       | 589.7 |      | $ | 524.7 |  | $ | 469.1 | 
|Expenses:                                                  |  |                         |       |      |   |       |  |   |       | 
|Production costs                                           |  |                         | 243.9 |      |   | 208.9 |  |   | 159.6 | 
|Other operating expenses(c)                                |  |                         | 56.9  |      |   | 66.4  |  |   | 59.0  | 
|Depreciation, depletion and amortization expenses          |  |                         | 258.5 |      |   | 169.4 |  |   | 130.5 | 
|                                                           |  |                         |       |      |   |       |  |   |       | 
|Total
expenses                                             |  |                         | 559.3 |      |   | 444.7 |  |   | 349.1 | 
|                                                           |  |                         |       |      |   |       |  |   |       | 
|Results of operations for oil and gas producing activities |  | $                       | 30.4  |      | $ | 80.0  |  | $ | 120.0 | 
|                                                           |  |                         |       |      |   |       |  |   |       | 

|    |                                                                                                                                                                                             
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(a) | Amounts
  relate to Kinder Morgan CO2 Company, L.P. and its consolidated subsidaries.                                                                                                       
|    |                                                                                                                                                                                             
|(b) | Revenues
  include losses attributable to our hedging contracts of $434.2 million,
  $441.7 million and $374.3 million for the years ended December 31, 2007, 2006
  and 2005, respectively.
|    |                                                                                                                                                                                             
|(c) | Consists
  primarily of carbon dioxide expense.                                                                                                                                             

The
table below represents estimates, as of December 31, 2007, of proved crude oil,
natural gas liquids and natural gas reserves prepared by Netherland, Sewell and
Associates, Inc. (independent oil and gas consultants) of Kinder Morgan CO2
Company, L.P. and its consolidated subsidiaries interests in oil and gas
properties, all of which are located in the state of Texas. This data has been
prepared using constant prices and costs, as discussed in subsequent paragraphs
of this document. The estimates of reserves and future revenue in this document
conforms to the guidelines of the United States Securities and Exchange
Commission.

We
believe the geologic and engineering data examined provides reasonable
assurance that the proved reserves are recoverable in future years from known
reservoirs under existing economic and operating conditions. Estimates of
proved reserves are subject to change, either positively or negatively, as
additional information becomes available and contractual and economic
conditions change.

Proved
oil and gas reserves are the estimated quantities of crude oil, natural gas and
natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions, that is, prices and costs as
of the date the estimate is made. Prices include consideration of changes in
existing prices provided only by contractual arrangements, but not on escalations
or declines based upon future conditions. Proved developed reserves are the
quantities of crude oil, natural gas liquids and natural gas expected to be
recovered through existing investments in wells and field infrastructure under
current operating conditions. Proved undeveloped reserves require additional
investments in wells and related infrastructure in order to recover the
production.

During
2007, we filed estimates of our oil and gas reserves for the year 2006 with the
Energy Information Administration of the U. S. Department of Energy on Form
EIA-23. The data on Form EIA-23 was presented on a different basis, and
included 100% of the oil and gas volumes from our operated properties only,
regardless of our net interest. The difference between the oil reserves
reported on Form EIA-23 and those reported in this report exceeds 5%.

208

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|                                             |  |                           |         |                |  |                      |   |  |        |  
|-------------------------------------------- |  | ------------------------- | ------- | -------------- |  | -------------------- | - |  | ------ | -
|Reserve Quantity Information                 | 
|                                            
|                                             |  | Consolidated Companies(a) |        
|                                             |  |                           |        
|                                             |  | Crude Oil
  (MBbls)       |         | NGLs
  (MBbls) |  | Nat. Gas
  (MMcf)(b) |  
|                                             |  |                           |         |                |  |                      |  
|Proved developed
  and undeveloped reserves: |  |                           |         |                |  |                      |   |  |        |  
|As of December 31, 2004                      |  |                           | 123,731 |                |  | 20,245               |   |  | 1,590  |  
|Revisions of
previous estimates(c)           |  |                           | 9,807   |                |  | (4,278               | ) |  | 1,608  |  
|Improved
Recovery(d)                         |  |                           | 21,715  |                |  | 4,847                |   |  | 242    |  
|Production                                   |  |                           | (13,815 | )              |  | (1,920               | ) |  | (1,335 | )
|Purchases of
reserves in place               |  |                           | 513     |                |  | 89                   |   |  | 48     |  
|                                             |  |                           |         |                |  |                      |   |  |        |  
|As of December 31, 2005                      |  |                           | 141,951 |                |  | 18,983               |   |  | 2,153  |  
|Revisions of
previous estimates(e)           |  |                           | (4,615  | )              |  | (6,858               | ) |  | (1,408 | )
|Production                                   |  |                           | (13,811 | )              |  | (1,817               | ) |  | (461   | )
|Purchases of
reserves in place               |  |                           | 453     |                |  | 25                   |   |  | 7      |  
|                                             |  |                           |         |                |  |                      |   |  |        |  
|As of December 31, 2006                      |  |                           | 123,978 |                |  | 10,333               |   |  | 291    |  
|Revisions of
previous estimates(f)           |  |                           | 10,361  |                |  | 2,784                |   |  | 1,077  |  
|Production                                   |  |                           | (12,984 | )              |  | (2,005               | ) |  | (290   | )
|                                             |  |                           |         |                |  |                      |   |  |        |  
|As of December 31, 2007                      |  |                           | 121,355 |                |  | 11,112               |   |  | 1,078  |  
|                                             |  |                           |         |                |  |                      |   |  |        |  
|                                             |  |                           |         |                |  |                      |   |  |        |  
|Proved developed
  reserves:                 |  |                           |         |                |  |                      |   |  |        |  
|As of December 31, 2004                      |  |                           | 71,307  |                |  | 8,873                |   |  | 1,357  |  
|As of December 31, 2005                      |  |                           | 78,755  |                |  | 9,918                |   |  | 1,650  |  
|As of December 31, 2006                      |  |                           | 69,073  |                |  | 5,877                |   |  | 291    |  
|As of December 31, 2007                      |  |                           | 70,868  |                |  | 5,517                |   |  | 1,078  |  

(a)
        Amounts relate to Kinder Morgan CO2 Company, L.P. and its consolidated subsidaries.


(b)
        Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees fahrenheit.


(c)
        Crude oil revisions are based on better than expected recoveries on the SACROC unit carbon dioxide flood project.  Natural gas liquids revisions are based on a lower than expected natural gas liquid yield at the SACROC unit carbon dioxide flood project.


(d)
        Improved recovery is due to significant additional areas of the SACROC unit being added to the future carbon dioxide flood project.


(e)
        Based on lower than expected recoveries of a section of the SACROC unit carbon dioxide flood project.


(f)
        Associated with an expansion of the carbon dioxide flood project area of the SACROC unit.


The
standardized measure of discounted cash flows and summary of the changes in the
standardized measure computation from year-to-year are prepared in accordance
with SFAS No. 69. The assumptions that underly the computation of the
standardized measure of discounted cash flows may be summarized as follows:

| |   |                                                                                                                                                                                                        
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | the
  standardized measure includes our estimate of proved crude oil, natural gas
  liquids and natural gas reserves and projected future production volumes
  based upon year-end economic conditions;
| |   |                                                                                                                                                                                                        
| |  | pricing is
  applied based upon year-end market prices adjusted for fixed or determinable
  contracts that are in existence at year-end;                                                               
| |   |                                                                                                                                                                                                        
| |  | future
  development and production costs are determined based upon actual cost at
  year-end;                                                                                                         
| |   |                                                                                                                                                                                                        
| |  | the
  standardized measure includes projections of future abandonment costs based
  upon actual costs at year-end; and                                                                                 
| |   |                                                                                                                                                                                                        
| |  | a discount
  factor of 10% per year is applied annually to the future net cash flows.                                                                                                                  

209

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Our
standardized measure of discounted future net cash flows from proved reserves
were as follows (in millions):

Standardized
Measure of Discounted Future Net Cash Flows From
Proved Oil and Gas Reserves

|                                                           |  |                    |          |      |   |          |   |   |          |  
|---------------------------------------------------------- |  | ------------------ | -------- | ---- | - | -------- | - | - | -------- | -
|                                                           |  | As of December 31, |         
|                                                           |  |                    |         
|                                                           |  | 2007               |          | 2006 |   | 2005     |  
|                                                           |  |                    |          |      |   |          |  
|Consolidated
  Companies(a)                                |  |                    |          |      |   |          |   |   |          |  
|Future cash inflows from production                        |  | $                  | 12,099.5 |      | $ | 7,534.7  |   | $ | 9,150.6  |  
|Future production costs                                    |  |                    | (3,536.2 | )    |   | (2,617.9 | ) |   | (2,756.6 | )
|Future development costs(b)                                |  |                    | (1,919.2 | )    |   | (1,256.8 | ) |   | (869.0   | )
|                                                           |  |                    |          |      |   |          |   |   |          |  
|Undiscounted
future net cash
  flows                       |  |                    | 6,644.1  |      |   | 3,660.0  |   |   | 5,525.0  |  
|10% annual discount                                        |  |                    | (2,565.7 | )    |   | (1,452.2 | ) |   | (2,450.0 | )
|                                                           |  |                    |          |      |   |          |   |   |          |  
|Standardized
measure of
  discounted future net cash flows |  | $                  | 4,078.4  |      | $ | 2,207.8  |   | $ | 3,075.0  |  
|                                                           |  |                    |          |      |   |          |   |   |          |  

|    |                                                                                        
|--- | ---------------------------------------------------------------------------------------
|(a) | Amounts
  relate to Kinder Morgan CO2 Company, L.P. and its consolidated
  subsidaries.

|    |                             
|--- | ----------------------------
|(b) | Includes
 abandonment costs.

The
following table represents our estimate of changes in the standardized measure
of discounted future net cash flows from proved reserves (in millions):

Changes in the Standardized Measure of
Discounted Future Net Cash Flows From 
Proved Oil and Gas Reserves

|                                                      |  |      |         |      |   |         |   |   |         |  
|----------------------------------------------------- |  | ---- | ------- | ---- | - | ------- | - | - | ------- | -
|                                                      |  | 2007 |         | 2006 |   | 2005    |  
|                                                      |  |      |         |      |   |         |  
|Consolidated Companies(a)                             |  |      |         |      |   |         |  
|Present
 value as of January 1                        |  | $    | 2,207.8 |      | $ | 3,075.0 |   | $ | 2,045.0 |  
|Changes during the year:                              |  |      |         |      |   |         |   |   |         |  
|Revenues less production and other costs(b)           |  |      | (722.1  | )    |   | (690.0  | ) |   | (624.4  | )
|Net changes in prices, production and other
 costs(b) |  |      | 2,153.2 |      |   | (123.0  | ) |   | 1,013.4 |  
|Development costs incurred                            |  |      | 244.5   |      |   | 261.8   |   |   | 281.7   |  
|Net changes in future development costs               |  |      | (547.8  | )    |   | (446.0  | ) |   | (492.3  | )
|Purchases of reserves in place                        |  |      |        |      |   | 3.2     |   |   | 9.4     |  
|Revisions of previous quantity estimates(c)           |  |      | 510.8   |      |   | (179.5  | ) |   | 51.1    |  
|Improved Recovery(d)                                  |  |      |        |      |   |        |   |   | 587.5   |  
|Accretion of discount                                 |  |      | 198.1   |      |   | 307.4   |   |   | 204.4   |  
|Timing differences and other                          |  |      | 33.9    |      |   | (1.1    | ) |   | (0.8    | )
|                                                      |  |      |         |      |   |         |   |   |         |  
|Net change for the year                               |  |      | 1,870.6 |      |   | (867.2  | ) |   | 1,030.0 |  
|                                                      |  |      |         |      |   |         |   |   |         |  
|Present
 value as of December 31                      |  | $    | 4,078.4 |      | $ | 2,207.8 |   | $ | 3,075.0 |  
|                                                      |  |      |         |      |   |         |   |   |         |  

(a)
        Amounts relate to Kinder Morgan CO2 Company, L.P. and its consolidated subsidaries.


(b)
        Excludes the effect of losses attributable to our hedging contracts of $434.2 million, $441.7 million and $374.3 million for the years ended December 31, 2007, 2006 and 2005, respectively.


(c)
        2007 revisions are associated with an expansion of the carbon dioxide flood project area for the SACROC unit.  2006 revisions are based on lower than expected recoveries from a section of the SACROC unit carbon dioxide flood project.  2005 revisions are based on better than expected crude oil recoveries on the SACROC unit carbon dioxide flood project, partially offset by a lower than expected natural gas liquids yield at the SACROC unit carbon dioxide flood project.


(d)
        Improved recovery is due to significant additional areas of the SACROC unit being added to the future carbon dioxide flood project.


210

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SIGNATURES

Pursuant to
the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.

| |                                                                           
| | --------------------------------------------------------------------------
| | KINDER MORGAN ENERGY PARTNERS, L.P.(A Delaware
 Limited Partnership)      
| |                                                                           
| | By: KINDER MORGAN G.P., INC.,its sole General Partner                     
| |                                                                           
| | By: KINDER MORGAN MANAGEMENT, LLC,the Delegate of Kinder Morgan G.P., Inc.
| |                                                                           
| | By: /s/ KIMBERLY A. DANG                                                  
| |                                                                           
| |                                                                           
| | Kimberly A. Dang,Vice President and Chief Financial Officer               

Date: February 25, 2008

Pursuant to
the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons in the capacities and on the dates
indicated.

|                      |  |                                      |  |                  
|--------------------- |  | ------------------------------------ |  | -----------------
|Signature             |  | Title                                |  | Date             
|                      |  |                                      |  |                  
|/s/ KIMBERLY A. DANG  |  | Vice President and Chief Financial   |  | February 25, 2008
|                      |  | Officer of Kinder Morgan             |  |                  
|Kimberly A. Dang      |  | Management, LLC, Delegate of         |  |                  
|                      |  | Kinder Morgan G.P., Inc. (principal  |  |                  
|                      |  | financial officer and principal      |  |                  
|                      |  | accounting officer)                  |  |                  
|                      |  |                                      |  |                  
|/s/ RICHARD D. KINDER |  | Chairman of the Board and Chief      |  | February 25, 2008
|                      |  | Executive Officer of Kinder Morgan   |  |                  
|Richard D. Kinder     |  | Management, LLC, Delegate of         |  |                  
|                      |  | Kinder Morgan G.P., Inc. (principal  |  |                  
|                      |  | executive officer)                   |  |                  
|                      |  |                                      |  |                  
|/s/ EDWARD O. GAYLORD |  | Director of Kinder Morgan            |  | February 25, 2008
|                      |  | Management, LLC, Delegate of         |  |                  
|Edward O. Gaylord     |  | Kinder Morgan G.P., Inc.             |  |                  
|                      |  |                                      |  |                  
|/s/ GARY L. HULTQUIST |  | Director of Kinder Morgan            |  | February 25, 2008
|                      |  | Management, LLC, Delegate of         |  |                  
|Gary L. Hultquist     |  | Kinder Morgan G.P., Inc.             |  |                  
|                      |  |                                      |  |                  
|/s/ PERRY M. WAUGHTAL |  | Director of Kinder Morgan            |  | February 25, 2008
|                      |  | Management, LLC, Delegate of         |  |                  
|Perry M. Waughtal     |  | Kinder Morgan G.P., Inc.             |  |                  
|                      |  |                                      |  |                  
|/s/ C. PARK SHAPER    |  | Director and President of            |  | February 25, 2008
|                      |  | Kinder Morgan Management, LLC,       |  |                  
|C. Park Shaper        |  | Delegate of Kinder Morgan G.P., Inc. |  |                  

211

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