Kinder Morgan Management, LLC 2003 Form 10-K

Table of Contents


UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, DC 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, 2003
or

[  ]

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

For the transition period from _____to_____

Commission File Number 1-16459

kmmgt.gif (40501 bytes)
Kinder Morgan Management, LLC
(Exact name of registrant as specified in its charter)

Delaware

  

76-0669886

(State or other jurisdiction of incorporation or organization)

  

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

  

500 Dallas Street, Suite 1000, Houston, Texas 77002

(Address of principal executive offices, including 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

Shares Representing Limited Liability Company Interests

  

New York Stock Exchange

Securities registered pursuant to section 12(g) of the Act:

None

(Title of class)

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 an accelerated filer (as defined in Exchange Act Rule 12b-2):
  Yes
x  No o

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant was $1,245,392,013 as of June 30, 2003.

The number of shares outstanding for each of the registrant's classes of common equity, as of February 12, 2004 was approximately two voting shares and 48,996,463 listed shares.


  
KINDER MORGAN MANAGEMENT, LLC AND SUBSIDIARY

CONTENTS

Page
Number

PART I

  
Items 1 and 2. Business and Properties

3-5

Item 3. Legal Proceedings

5

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

5

  

PART II

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

6

Item 6. Selected Financial Data

7

Item 7. Management's Discussion and Analysis Of Financial Condition and Results of Operations

7-16

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

16

Item 8. Financial Statements and Supplementary Data

17-29

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

29

Item 9A. Controls and Procedures

29

  

PART III

  
Item 10. Directors and Executive Officers of the Registrant

30-34

Item 11. Executive Compensation

35-40

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

40-42

Item 13. Certain Relationships and Related Transactions

42-46

Item 14. Principal Accounting Fees and Services

46

  

PART IV

  
Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K

47-48

  
Signatures

49

  
Kinder Morgan Energy Partners, L.P. Annual Report on Form 10-K for the year ended December 31, 2003

Annex A

  

Note:  Individual financial statements of the parent company are omitted pursuant to the provisions of Accounting Series Release No. 302.

2


PART I

Items 1 and 2.  Business and Properties.

In this report, unless the context requires otherwise, references to "we," "us," "our," or the "Company" are intended to mean Kinder Morgan Management, LLC and its consolidated subsidiary. Our shares representing limited liability company interests are traded on the New York Stock Exchange under the symbol "KMR". Our executive offices are located at 500 Dallas Street, Suite 1000, Houston, Texas 77002 and our telephone number is (713) 369-9000.

We are a publicly traded Delaware limited liability company that was formed on February 14, 2001. We are a limited partner in Kinder Morgan Energy Partners, L.P., and manage and control its business and affairs pursuant to a delegation of control agreement. Pursuant to this delegation of control agreement among Kinder Morgan G.P., Inc., Kinder Morgan Energy Partners, L.P., Kinder Morgan Energy Partners, L.P.'s operating partnerships and us:

Kinder Morgan G.P., Inc., as general partner of Kinder Morgan Energy Partners, L.P., delegated to us, to the fullest extent permitted under Delaware law and the Kinder Morgan Energy Partners, L.P. partnership agreement, and we assumed, all of Kinder Morgan G.P., Inc.'s power and authority to manage and control the business and affairs of Kinder Morgan Energy Partners, L.P. and Kinder Morgan Energy Partners, L.P.'s operating partnerships; and

  

We have agreed that we will not take any of the following actions without the approval of Kinder Morgan G.P., Inc.:

  

-

amend or propose an amendment to the Kinder Morgan Energy Partners, L.P. partnership agreement,

  

-

change the amount of the distribution made on the Kinder Morgan Energy Partners, L.P. common units,

     

-

allow a merger or consolidation involving Kinder Morgan Energy Partners, L.P.,

  

-

allow a sale or exchange of all or substantially all of the assets of Kinder Morgan Energy Partners, L.P.,

  

-

dissolve or liquidate Kinder Morgan Energy Partners, L.P.,

  

-

take any action requiring unitholder approval,

  

-

call any meetings of the Kinder Morgan Energy Partners, L.P. common unitholders,

  

-

take any action that, under the terms of the partnership agreement of Kinder Morgan Energy Partners, L.P., must or should receive a special approval of the conflicts and audit committee of Kinder Morgan G.P., Inc.,

  

-

take any action that, under the terms of the partnership agreement of Kinder Morgan Energy Partners, L.P., cannot be taken by the general partner without the approval of all outstanding units,

3


  

-

settle or compromise any claim or action directly against or otherwise relating to indemnification of our or the general partner's (and respective affiliates) officers, directors, managers or members or relating to our structure or securities,

     

-

settle or compromise any claim or action relating to the i-units, which are a separate class of Kinder Morgan Energy Partners, L.P.'s limited partnership interests, our shares or any offering of our shares,

     

-

settle or compromise any claim or action involving tax matters,

  
-

allow Kinder Morgan Energy Partners, L.P. to incur indebtedness if the aggregate amount of its indebtedness then exceeds 50% of the market value of the then outstanding units of Kinder Morgan Energy Partners, L.P., or

  
-

allow Kinder Morgan Energy Partners, L.P. to issue units in one transaction, or in a series of related transactions, having a market value in excess of 20% of the market value of then outstanding units of Kinder Morgan Energy Partners, L.P.

  

Kinder Morgan G.P., Inc.:

    

-

is not relieved of any responsibilities or obligations to Kinder Morgan Energy Partners, L.P. or its unitholders as a result of such delegation,
    

-

owns, or one of its affiliates owns, all of our voting shares, and
    

-

will not withdraw as general partner of Kinder Morgan Energy Partners, L.P. or transfer to a non-affiliate all of its interest as general partner, unless approved by both the holders of a majority of each of the i-units and the holders of a majority of all units voting as a single class, excluding common units and Class B units held by Kinder Morgan G.P., Inc. and its affiliates and excluding the number of i-units corresponding to the number of our shares owned by Kinder Morgan G.P., Inc. and its affiliates.

   

Kinder Morgan Energy Partners, L.P. has agreed to:

    

-

recognize the delegation of rights and powers to us,
    

-

indemnify and protect us and our officers and directors to the same extent as it does with respect to Kinder Morgan G.P., Inc. as general partner, and

    

-

reimburse our expenses to the same extent as it does with respect to Kinder Morgan G.P., Inc. as general partner.

These agreements will continue until either Kinder Morgan G.P., Inc. has withdrawn or been removed as the general partner of Kinder Morgan Energy Partners, L.P. or all of our shares are owned by Kinder Morgan, Inc. and its affiliates. The partnership agreement of Kinder Morgan Energy Partners, L.P. reflects these agreements. These agreements also apply to the operating partnerships of Kinder Morgan Energy Partners, L.P. and their partnership agreements.

Kinder Morgan G.P., Inc. remains the only general partner of Kinder Morgan Energy Partners, L.P. and all of its operating partnerships. Kinder Morgan G.P., Inc. will retain all of its general partner interests and shares in the profits, losses and distributions from all of these partnerships.

4


The withdrawal or removal of Kinder Morgan G.P., Inc. as general partner of Kinder Morgan Energy Partners, L.P. will simultaneously result in the termination of our power and authority to manage and control the business and affairs of Kinder Morgan Energy Partners, L.P. Similarly, if Kinder Morgan G.P., Inc.'s power and authority as general partner are modified in the partnership agreement of Kinder Morgan Energy Partners, L.P., then the power and authority delegated to us will be modified on the same basis. The delegation of control agreement can be amended by all parties to the agreement, but on any amendment that would reduce the time for any notice to which owners of our shares are entitled or would have a material adverse effect on our shares, as determined by our board of directors in its discretion, the approval of the owners of a majority of the shares, excluding shares owned by Kinder Morgan, Inc. and its affiliates, is required.

Through our ownership of i-units, we are a limited partner in Kinder Morgan Energy Partners, L.P. We do not expect to have any cash flow attributable to our ownership of the i-units, but we expect that we will receive quarterly distributions of additional i-units from Kinder Morgan Energy Partners, L.P. The number of additional i-units we receive will be based on the amount of cash to be distributed by Kinder Morgan Energy Partners, L.P. to an owner of a common unit. The amount of cash distributed by Kinder Morgan Energy Partners, L.P. to its owners of common units is dependent on the operations of Kinder Morgan Energy Partners, L.P. and its operating limited partnerships and subsidiaries, and will be determined in accordance with its partnership agreement.

We have elected to be treated as a corporation for federal income tax purposes. Because we are treated as a corporation for federal income tax purposes, an owner of our shares will not report on its federal income tax return any of our items of income, gain, loss and deduction relating to an investment in us.

We are subject to federal income tax on our taxable income; however, the i-units owned by us generally are not entitled to allocations of income, gain, loss or deduction of Kinder Morgan Energy Partners, L.P. until such time as there is a liquidation of Kinder Morgan Energy Partners, L.P. Therefore, we do not anticipate that we will have material amounts of taxable income resulting from our ownership of the i-units unless we enter into a sale or exchange of the i-units or Kinder Morgan Energy Partners, L.P. is liquidated.

We have no properties. Our assets consist of a small amount of working capital and the i-units that we own.

We have no employees. For more information, see Note 4 of the accompanying Notes to Consolidated Financial Statements.

We make available free of charge on or through our Internet website, at http://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.

Item 3.  Legal Proceedings.

We are not a party to any litigation.

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

There were no matters submitted to a vote of our shareholders during the fourth quarter of 2003.

5


PART II

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

Our shares are listed for trading on the New York Stock Exchange under the symbol "KMR." The per share price ranges of our shares by quarter for the last two years are provided below.

Market Price Per Share

2003

2002

Low

High

Low

High

Quarter Ended:
   March 31

$30.00

$34.09

$25.90

$39.10

   June 30

$32.01

$37.55

$30.40

$36.71

   September 30

$36.26

$38.57

$26.88

$34.40

   December 31

$37.45

$43.65

$27.44

$32.30

There were approximately 9,600 holders of our listed shares as of February 12, 2004, which includes individual participants in security position listings.

Under the terms of our limited liability company agreement, except in connection with our liquidation, we do not pay distributions on our shares in cash but we make distributions on our shares in additional shares or fractions of shares. At the same time Kinder Morgan Energy Partners, L.P. makes a distribution on its common units and i-units, we distribute on each of our shares that fraction of a share determined by dividing the amount of the cash distribution to be made by Kinder Morgan Energy Partners, L.P. on each common unit by the average market price of a share determined for the ten-trading day period ending on the trading day immediately prior to the ex-dividend date for our shares.

Share Distributions

Shares Distributed Per Outstanding Share

Equivalent Distribution Value Per Share1

Total Number of Additional Shares Distributed

Quarter Ended:

2003

2002

2003

2002

2003

2002

   March 31

0.018488

0.016969

$ 0.640

$ 0.590

859,933

527,572

   June 30

0.017138

0.019596

$ 0.650

$ 0.610

811,878

619,585

   September 30

0.016844

0.020969

$ 0.660

$ 0.610

811,625

937,658

   December 31

0.015885

0.018815

$ 0.680

$ 0.625

778,309

858,981

  

  

  

1

This is the cash distribution paid or payable to each common unit of Kinder Morgan Energy Partners, L.P. for the quarter indicated and is used to calculate our distribution of shares as discussed above. Because of this calculation, the market value of the shares distributed on the date of distribution may be less or more than the cash distribution per common unit of Kinder Morgan Energy Partners, L.P.

There were no sales of unregistered equity securities during the periods covered by this report. We did not repurchase any shares during the fourth quarter of 2003.

 

6


Item 6.  Selected Financial Data.

KINDER MORGAN MANAGEMENT, LLC AND SUBSIDIARY

Year Ended December 31,

February 14, 2001 (Inception) Through
December 31,

2003

2002

2001

(In thousands except per share amounts)

Equity in Earnings of Kinder Morgan Energy Partners, L.P.

$   94,775

$   72,199

$   28,354

Provision for Income Taxes

    36,014

    26,865

    11,342

Net Income

$   58,761

$   45,334

$   17,012

==========

==========

==========

Earnings Per Share, Basic and Diluted

$     1.24

$     1.23

$     0.78

==========

==========

==========

Number of Shares Used in Computing
  Basic and Diluted Earnings Per Share

    47,372

    36,790

    21,756

==========

==========

==========

Equivalent Distribution Value Per Share1

$    2.630

$    2.435

$    1.625

==========

==========

==========

Total Number of Additional Shares Distributed

     3,262

     2,944

     1,340

==========

==========

==========

Total Assets at End of Period

$1,506,286

$1,439,190

$1,034,824

==========

==========

==========

  

  

  

1

This is the amount of cash distributions payable to each common unit of Kinder Morgan Energy Partners, L.P. for each period shown. Under the terms of our limited liability company agreement, except in connection with our liquidation, we do not pay distributions on our shares in cash but we make distributions on our shares in additional shares or fractions of shares. At the same time Kinder Morgan Energy Partners, L.P. makes a distribution on its common units and i-units, we distribute on each of our shares that fraction of a share determined by dividing the amount of the cash distribution to be made by Kinder Morgan Energy Partners, L.P. on each common unit by the average market price of a share determined for a ten-trading day period ending on the trading day immediately prior to the ex-dividend date for our shares. Because of this calculation, the market value of the shares distributed on the date of distribution may be less or more than the cash distribution per common unit of Kinder Morgan Energy Partners, L.P.

Item 7.  Management's Discussion and Analysis of Financial Condition and Results of Operations.

General

We are a publicly traded Delaware limited liability company, formed on February 14, 2001, that has elected to be treated as a corporation for federal income tax purposes. Our voting shares are owned by Kinder Morgan, G.P., Inc., an indirect wholly owned subsidiary of Kinder Morgan, Inc. and the general partner of Kinder Morgan Energy Partners, L.P. Kinder Morgan, Inc. is one of the largest energy storage and transportation companies in the United States, operating, either for themselves or on behalf of Kinder Morgan Energy Partners, L.P., over 35,000 miles of natural gas and refined petroleum products pipelines and approximately 80 terminals. Kinder Morgan Energy Partners, L.P. is the largest publicly traded pipeline limited partnership in the United States in terms of market capitalization and the owner and operator of the largest independent refined petroleum products pipeline system in the United States in terms of volumes delivered. Kinder Morgan Energy Partners, L.P. owns and/or operates a diverse group of assets used in the transportation, storage and processing of energy products, including refined petroleum products pipeline systems with more than 10,000 miles of products pipeline and 39 associated terminals. Kinder Morgan Energy Partners, L.P. owns over 15,000 miles of natural gas transportation pipelines, plus natural gas gathering and storage facilities. Kinder Morgan Energy Partners, L.P. also owns or operates approximately 52 liquid and bulk terminal facilities and approximately 57 rail transloading facilities located throughout the United States, handling nearly 60 million tons of coal, petroleum coke and other dry-bulk materials annually and having a liquids storage capacity of approximately 55 million barrels for refined petroleum products, chemicals and other liquid products. In addition, Kinder Morgan Energy Partners, L.P. owns Kinder Morgan CO2 Company, L.P., which has

7


over 1,100 miles of pipelines and transports, markets and produces carbon dioxide for use in enhanced oil recovery operations and owns interests in and/or operates six oil fields in West Texas, all of which are using or have used carbon dioxide injection operations.

We are a limited partner in Kinder Morgan Energy Partners, L.P., and manage and control its business and affairs pursuant to a delegation of control agreement. Our success is dependent upon our operation and management of Kinder Morgan Energy Partners, L.P. and its resulting performance. Therefore, we have attached as Annex A hereto Kinder Morgan Energy Partners, L.P.'s 2003 Annual Report on Form 10-K. The following discussion should be read in conjunction with the accompanying financial statements and related notes.

Business

Kinder Morgan G.P., Inc. has delegated to us, to the fullest extent permitted under Delaware law and Kinder Morgan Energy Partners, L.P.'s limited partnership agreement, all of its rights and powers to manage and control the business and affairs of Kinder Morgan Energy Partners, L.P. subject to Kinder Morgan G.P., Inc.'s right to approve specified actions.

Results of Operations

Our results of operations consist of the offsetting expenses and revenues associated with our managing and controlling the business and affairs of Kinder Morgan Energy Partners, L.P. and our equity in the earnings of Kinder Morgan Energy Partners, L.P. attributable to the i-units we own. At December 31, 2003, through our ownership of i-units, we owned approximately 25.9% of all of Kinder Morgan Energy Partners, L.P.'s outstanding limited partner interests. We use the equity method of accounting for our investment in Kinder Morgan Energy Partners, L.P. and, therefore, we record earnings equal to approximately 25.9% of Kinder Morgan Energy Partners, L.P.'s limited partners' net income. Our percentage ownership in Kinder Morgan Energy Partners, L.P. will change over time upon the distribution of additional i-units to us or upon issuances of additional common units or other equity securities by Kinder Morgan Energy Partners, L.P.

For the years ended December 31, 2003, 2002 and 2001, Kinder Morgan Energy Partners, L.P. reported limited partners' net income of $370.8 million, $337.6 million and $240.2 million, respectively. The reported segment earnings contribution by business segment for Kinder Morgan Energy Partners, L.P. is set forth below. This information should be read in conjunction with Kinder Morgan Energy Partners, L.P.'s 2003 Annual Report on Form 10-K, which is attached hereto as Annex A.

Kinder Morgan Energy Partners, L.P.

Year Ended December 31,

2003

2002

2001

(In thousands)

Segment Earnings Contribution:
   Product Pipelines

$  370,974 

$ 343,935 

$ 312,464 

   Natural Gas Pipelines

   319,288 

  276,766 

  193,804 

   CO2

   140,755 

  100,983 

   92,087 

   Terminals

   203,701 

  194,917 

  140,425 

     Total Segment Earnings

 1,034,718 

  916,601 

  738,780 

Interest and Corporate Administrative Expenses1

  (337,381)

 (308,224)

 (296,437)

Net Income

$  697,337 

$ 608,377 

$ 442,343 

========== 

========= 

========= 

  
1

Includes interest and debt expense, general and administrative expenses, minority interest expense and other insignificant items.

8


Our earnings, as reported in the accompanying Consolidated Statements of Income, represent equity in earnings attributable to the i-units that we own, reduced by a deferred income tax provision. The deferred income tax provision is calculated based on the book/tax basis difference created by our recognition, under accounting principles generally accepted in the United States of America, of our share of the earnings of Kinder Morgan Energy Partners, L.P. Our earnings per share (both basic and diluted) is our net income divided by our weighted-average number of outstanding shares during the periods presented. There are no securities outstanding that may be converted into or exercised for shares.

Income Taxes

We are a limited liability company that has elected to be treated as a corporation for federal income tax purposes. Deferred income tax assets and liabilities are recognized for temporary differences between the basis of our 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. Currently, our only such temporary difference results from recognition of the increased investment associated with recording our equity in the earnings of Kinder Morgan Energy Partners, L.P. The effective tax rate used in computing our income tax provision is 38 percent for 2003 and 2002 (before the impact of the reduction in the tax rate on the cumulative deferred tax liability) and 40 percent for 2001, in each case composed of the 35 percent federal statutory rate and a provision for state income taxes.

We are a party to a tax indemnification agreement with Kinder Morgan, Inc. Pursuant to this tax indemnification agreement, Kinder Morgan, Inc. agreed to indemnify us for any tax liability attributable to our formation or our management and control of the business and affairs of Kinder Morgan Energy Partners, L.P., and for any taxes arising out of a transaction involving the i-units we own to the extent the transaction does not generate sufficient cash to pay our taxes with respect to such transaction.

Liquidity and Capital Resources

Our authorized capital structure consists of two classes of interests: (1) our listed shares and (2) our voting shares, collectively referred to in this document as our "shares." Additional classes of interests may be approved by our board and holders of a majority of our shares, excluding shares held by Kinder Morgan, Inc. and its affiliates. Our only off-balance sheet arrangement is our equity investment in Kinder Morgan Energy Partners, L.P.

The number of our shares outstanding will at all times equal the number of i-units of Kinder Morgan Energy Partners, L.P. we own. Under the terms of our limited liability company agreement, except in connection with our liquidation, we do not pay distributions on our shares in cash but we make distributions on our shares in additional shares or fractions of shares. At the same time Kinder Morgan Energy Partners, L.P. makes a distribution on its common units and i-units, we distribute on each of our shares that fraction of a share determined by dividing the amount of the cash distribution to be made by Kinder Morgan Energy Partners, L.P. on each common unit by the average market price of a share determined for a ten-trading day period ending on the trading day immediately prior to the ex-dividend date for our shares.

On July 18, 2001, Kinder Morgan Energy Partners, L.P. announced that we, as the delegate of Kinder Morgan Energy Partners, L.P.'s general partner, had approved a two-for-one split of its common units. The common unit split, in the form of a distribution of one common unit for each common unit outstanding, occurred on August 31, 2001. This split resulted in our receiving one additional i-unit for each i-unit we owned on the record date, August 17, 2001. Also on July 18, 2001, we announced a two-for-one split of our shares. This share split, in the form of a one-share distribution for each share outstanding, occurred on August 31, 2001.

9


Prior to July 23, 2002, pursuant to the Kinder Morgan, Inc. exchange provisions which constituted part of our limited liability company agreement, holders of our shares had the right, at their option, to exchange any or all of their whole shares for common units of Kinder Morgan Energy Partners, L.P. held by Kinder Morgan, Inc. at an exchange rate of one common unit per share or, at Kinder Morgan, Inc.'s election, cash. By approval of our shareholders other than Kinder Morgan, Inc., effective at the close of business on July 23, 2002, Kinder Morgan, Inc. no longer has an obligation to exchange, upon presentation by the holder, our listed shares for either Kinder Morgan Energy Partners, L.P.'s common units that it owns or, at Kinder Morgan, Inc.'s election, cash. Approximately 6.8 million of our listed shares were exchanged in 2002 prior to the elimination of the exchange feature and a total of approximately 9.7 million of our listed shares were exchanged for Kinder Morgan Energy Partners, L.P.'s common units or cash during all periods prior to the elimination of the exchange feature. In conjunction with the elimination of the exchange feature, on July 29, 2002, Kinder Morgan, Inc. issued to each of our shareholders (i) .09853 shares of Kinder Morgan, Inc. common stock for each 100 of our listed shares held of record by such shareholder at the close of business on July 23, 2002, and (ii) cash in lieu of fractional shares. As a result of its initial acquisition of our shares, these exchanges and quarterly share distributions, at December 31, 2003, Kinder Morgan, Inc. owned approximately 14.5 million, or approximately 29.7 percent, of our outstanding shares.

On January 21, 2004, we announced that our board of directors had declared a share distribution payable on February 13, 2004 to shareholders of record as of January 30, 2004, based on the $0.68 per common unit distribution declared by Kinder Morgan Energy Partners, L.P. This distribution, which is paid in the form of additional shares or fractions thereof, as appropriate, based on the average market price of a share determined for a ten-trading day period ending on the trading day immediately prior to the ex-dividend date for our shares, was 0.015885 shares per outstanding share.

We expect that our expenditures associated with managing and controlling the business and affairs of Kinder Morgan Energy Partners, L.P. and the reimbursement for these expenditures received by us from Kinder Morgan Energy Partners, L.P. will continue to be equal. As stated above, the distributions we expect to receive on the i-units we own will be in the form of additional i-units. Therefore, we expect neither to generate nor to require significant amounts of cash in ongoing operations. We currently have no debt and have no plans to incur any debt. Any cash received from the sale of additional shares will immediately be used to purchase additional i-units. Accordingly, we do not anticipate any other sources or needs for additional liquidity.

Related Party Transactions

Odessa Lateral

As previously reported in our Annual Report on Form 10-K for the year ended December 31, 2002, Kinder Morgan Energy Partners, L.P., through Kinder Morgan CO2 Company, L.P., has purchased a certain 13-mile, 6-inch diameter carbon dioxide pipeline lateral, referred to herein as the Odessa Lateral, from Morgan Associates Proprietary, L.P. for $0.7 million. The Odessa Lateral connects to Kinder Morgan CO2 Company, L.P.'s Central Basin carbon dioxide pipeline and serves, solely, the Emmons and South Cowden carbon dioxide flooding projects located in the Permian Basin and operated by ConocoPhillips. Morgan Associates is a limited partnership owned and controlled by Mr. William V. Morgan and his wife, Sara. Mr. and Mrs. Morgan are the parents of Michael C. Morgan, the President of Kinder Morgan G.P., Inc. and us. Mr. William V. Morgan was Director and Vice Chairman of Kinder Morgan G.P., Inc. and us prior to his retirement in January 2003.

Mr. William V. Morgan, through Morgan Associates and otherwise, has been an active investor in carbon dioxide pipeline infrastructure since the mid-1980s. In 1996, prior to Kinder Morgan Energy

10


Partners, L.P.'s current management's acquisition of Kinder Morgan G.P., Inc. in February 1997, Morgan Associates constructed the Odessa Lateral for approximately $1.3 million, entered into a long-term transportation agreement with Kinder Morgan CO2 Company, L.P.'s ultimate predecessor in interest to transport carbon dioxide via the Odessa Lateral and entered into an operating agreement with Kinder Morgan CO2 Company, L.P.'s ultimate predecessor in interest. Subsidiaries of Shell Oil Company and Mobil Corporation initially provided the carbon dioxide that was ultimately sold to the South Cowden and Emmons projects. During 2002, Kinder Morgan CO2 Company, L.P. was selling carbon dioxide to ConocoPhillips for use in the Emmons and South Cowden carbon dioxide flooding projects.

In 1998, Kinder Morgan Energy Partners, L.P. contributed its Central Basin Pipeline, its operator's interest under the operating agreement and its rights and obligations under the transportation agreement to Shell CO2 Company, Ltd., a joint venture owned 80% by Shell Oil Company and 20% by Kinder Morgan Energy Partners, L.P. In April 2000, Shell Oil Company elected to sell its 80% interest in Shell CO2 Company, Ltd. and Kinder Morgan Energy Partners, L.P. successfully won the bid and acquired such interest. Kinder Morgan Energy Partners, L.P. renamed Shell CO2 Company, Ltd. as Kinder Morgan CO2 Company, L.P., and Kinder Morgan Energy Partners, L.P. owns a 98.9899% limited partner interest in Kinder Morgan CO2 Company, L.P. and Kinder Morgan G.P., Inc. owns a direct 1.0101% general partner interest. Kinder Morgan CO2 Company, L.P. operates and transports carbon dioxide via the Odessa Lateral, and following Kinder Morgan Energy Partners, L.P.'s acquisition of Shell's joint-venture interest, Kinder Morgan Energy Partners, L.P.'s relationship with Morgan Associates in respect of the Odessa Lateral has returned to the 1998 pre-joint venture level.

In late 2002, ConocoPhillips approached Kinder Morgan CO2 Company, L.P. to discuss transferring some volumes that it was obligated to take or pay for from Kinder Morgan CO2 Company, L.P. at Emmons to another carbon dioxide flooding project it had in the Permian Basin. Kinder Morgan CO2 Company, L.P. was receptive to the proposal. However, any such transfer of volumes required the approval of Morgan Associates. In the first quarter of 2003, following Mr. Morgan's retirement, Kinder Morgan CO2 Company, L.P. approached Morgan Associates regarding such consent and the need to compensate Morgan Associates for any volumes transferred off of the Odessa Lateral. The two parties agreed to pursue compensating Morgan Associates by having Kinder Morgan CO2 Company, L.P. acquire the Odessa Lateral from Morgan Associates.

The purchase price was arrived at as follows: Pursuant to the transportation agreement, Kinder Morgan CO2 Company, L.P. was obligated to pay to Morgan Associates a demand fee, plus a fee on volumes transported (or a minimum transport or pay amount in the event the fee to be received for transported volumes did not exceed such minimum amount) through the Odessa Lateral to the Emmons and South Cowden carbon dioxide flooding projects. Accordingly, the estimated purchase price was arrived at by discounting back, using a commercially reasonable discount rate, the remaining demand fees, plus the remaining minimum transport or pay amounts under Morgan Associates' transportation contracts with Kinder Morgan CO2 Company, L.P. on the Odessa Lateral.

Mr. Michael C. Morgan abstained from all negotiations related to the Odessa Lateral. The transaction was approved by the Boards of Directors of Kinder Morgan G.P., Inc. and us. The transaction closed by the end of March 2003.

Recent Accounting Pronouncements

Refer to Note 6 of the accompanying Consolidated Financial Statements for information regarding recent accounting pronouncements.

11


Risk Factors of our Business

Our success is dependent upon our operation and management of Kinder Morgan Energy Partners, L.P. and its resulting performance. We are a limited partner in Kinder Morgan Energy Partners, L.P. In the event that Kinder Morgan Energy Partners, L.P. decreases its cash distributions to its common unitholders, distributions of i-units on the i-units that we own will decrease correspondingly, and distributions of additional shares to owners of our shares will decrease as well. The risk factors that affect Kinder Morgan Energy Partners, L.P. also affect us; see "Risk Factors" for Kinder Morgan Energy Partners, L.P. included in Annex A.

The value of the quarterly per-share distribution of an additional fractional share may be less than the cash distribution on a common unit of Kinder Morgan Energy Partners, L.P. The fraction of a Kinder Morgan Management, LLC share to be issued in distributions per share outstanding will be based on the average closing price of the shares for the ten consecutive trading days preceding the ex-dividend date. Because the market price of our shares may vary substantially over time, the market value of our shares on the date a shareholder receives a distribution of additional shares may vary substantially from the cash the shareholder would have received had the shareholder owned common units instead of shares.

Kinder Morgan Energy Partners, L.P. could be treated as a corporation for United States federal income tax purposes. The treatment of Kinder Morgan Energy Partners, L.P. as a corporation would substantially reduce the cash distributions on the common units and the value of i-units that Kinder Morgan Energy Partners, L.P. will distribute quarterly to us and the value of our shares that we will distribute quarterly to our shareholders. The anticipated benefit of an investment in our shares depends largely on the treatment of Kinder Morgan Energy Partners, L.P. as a partnership for United States federal income tax purposes. Kinder Morgan Energy Partners, L.P. has not requested, and does not plan to request, a ruling from the Internal Revenue Service on this or any other matter affecting Kinder Morgan Energy Partners, L.P. Current law requires Kinder Morgan Energy Partners, L.P. to derive at least 90% of its annual gross income from specific activities to continue to be treated as a partnership for United States federal income tax purposes. Kinder Morgan Energy Partners, L.P. may not find it possible, regardless of its efforts, to meet this income requirement or may inadvertently fail to meet this income requirement. Current law may change so as to cause Kinder Morgan Energy Partners, L.P. to be treated as a corporation for United States federal income tax purposes without regard to its sources of income or otherwise subject Kinder Morgan Energy Partners, L.P. to entity-level taxation.

If Kinder Morgan Energy Partners, L.P. were to be treated as a corporation for United States federal income tax purposes, it would pay United States federal income tax on its income at the corporate tax rate, which is currently a maximum of 35%, and would pay state income taxes at varying rates. Distributions to us of additional i-units would generally be taxed as a corporate distribution. Because a tax would be imposed upon Kinder Morgan Energy Partners, L.P. as a corporation, the cash available for distribution to a common unitholder would be substantially reduced, which would reduce the values of i-units distributed quarterly to us and our shares distributed quarterly to our shareholders. Treatment of Kinder Morgan Energy Partners, L.P. as a corporation would cause a substantial reduction in the value of our shares.

As an owner of i-units, we may not receive value equivalent to the common unit value for our i-unit interest in Kinder Morgan Energy Partners, L.P. if Kinder Morgan Energy Partners, L.P. is liquidated. As a result, a shareholder may receive less per share in our liquidation than is received by an owner of a common unit in a liquidation of Kinder Morgan Energy Partners, L.P. If Kinder Morgan Energy Partners, L.P. is liquidated and Kinder Morgan, Inc. does not satisfy its obligation to purchase your shares, which is triggered by a liquidation, then the value of your shares will depend on

12


the after-tax amount of the liquidating distribution received by us as the owner of i-units. The terms of the i-units provide that no allocations of income, gain, loss or deduction will be made in respect of the i-units until such time as there is a liquidation of Kinder Morgan Energy Partners, L.P. If there is a liquidation of Kinder Morgan Energy Partners, L.P., it is intended that we will receive allocations of income and gain in an amount necessary for the capital account attributable to each i-unit to be equal to that of a common unit. As a result, we will likely realize taxable income upon the liquidation of Kinder Morgan Energy Partners, L.P. However, there may not be sufficient amounts of income and gain to cause the capital account attributable to each i-unit to be equal to that of a common unit. If they are not equal, we, and therefore our shareholders, will receive less value than would be received by an owner of common units.

Further, the tax indemnity provided to us by Kinder Morgan, Inc. only indemnifies us for our tax liabilities to the extent we have not received sufficient cash in the transaction generating the tax liability to pay the associated tax. Prior to any liquidation of Kinder Morgan Energy Partners, L.P., we do not expect to receive cash in a taxable transaction. If a liquidation of Kinder Morgan Energy Partners, L.P. occurs, however, we likely would receive cash which would need to be used at least in part to pay taxes. As a result, our residual value and the value of our shares likely will be less than the value of the common units upon the liquidation of Kinder Morgan Energy Partners, L.P.

Our management and control of the business and affairs of Kinder Morgan Energy Partners, L.P. and its operating partnerships could result in our being liable for obligations to third parties who transact business with Kinder Morgan Energy Partners, L.P. and its operating partnerships and to whom we held ourselves out as a general partner. We could also be responsible for environmental costs and liabilities associated with Kinder Morgan Energy Partners, L.P.'s assets in the event that it is not able to perform all of its obligations under environmental laws. Kinder Morgan Energy Partners, L.P. may not be able to reimburse or indemnify us as a result of its insolvency or bankruptcy. The primary adverse impact of that insolvency or bankruptcy on us would be the decline in or elimination of the value of our i-units, which are our only significant assets. Assuming under these circumstances that we have some residual value in our i-units, a direct claim by creditors of Kinder Morgan Energy Partners, L.P. against us could further reduce our net asset value and cause us also to declare bankruptcy. Another risk with respect to third party claims will occur, however, under the circumstances when Kinder Morgan Energy Partners, L.P. is financially able to pay us, but for some other reason does not reimburse or indemnify us. For example, to the extent that Kinder Morgan Energy Partners, L.P. fails to satisfy any environmental liabilities for which it is responsible, we could be held liable under environmental laws. For additional information, see the following risk factor.

If we are not fully indemnified by Kinder Morgan Energy Partners, L.P. for all the liabilities we incur in performing our obligations under the delegation of control agreement, we could face material difficulties in paying those liabilities, and the net value of our assets could be adversely affected. Under the delegation of control agreement, we have been delegated management and control of the business and affairs of Kinder Morgan Energy Partners, L.P. and its operating partnerships. There are circumstances under which we may not be indemnified by Kinder Morgan Energy Partners, L.P. or Kinder Morgan G.P., Inc. for liabilities we incur in managing and controlling the business and affairs of Kinder Morgan Energy Partners, L.P. These circumstances include:

if we act in bad faith; and

  

if we breach laws like the federal securities laws, where indemnification may not be allowed.

If in the future we cease to manage and control the business and affairs of Kinder Morgan Energy Partners, L.P., we may be deemed to be an investment company for purposes of the Investment

13


Company Act of 1940. In that event, we would either have to register as an investment company under the Investment Company Act, obtain exemptive relief from the Securities and Exchange Commission, or modify our organizational structure or our contract rights to fall outside the definition of an investment company. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with our affiliates, including the purchase and sale of certain securities or other property to or from our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage, and require us to add directors who are independent of us or our affiliates.

The interests of Kinder Morgan, Inc. may differ from our interests, the interests of our shareholders and the interests of unitholders of Kinder Morgan Energy Partners, L.P. Kinder Morgan, Inc. owns all of the stock of the general partner of Kinder Morgan Energy Partners, L.P. and elects all of its directors. The general partner of Kinder Morgan Energy Partners, L.P. owns all of our voting shares and elects all of our directors. Furthermore, some of our directors and officers are also directors and officers of Kinder Morgan, Inc. and the general partner of Kinder Morgan Energy Partners, L.P. and have fiduciary duties to manage the businesses of Kinder Morgan, Inc. and Kinder Morgan Energy Partners, L.P. in a manner that may not be in the best interest of our shareholders. Kinder Morgan, Inc. has a number of interests that differ from the interests of our shareholders and the interests of the unitholders. As a result, there is a risk that important business decisions will not be made in the best interest of our shareholders.

Our limited liability company agreement restricts or eliminates a number of the fiduciary duties that would otherwise be owed by our board of directors to our shareholders, and the partnership agreement of Kinder Morgan Energy Partners, L.P. restricts or eliminates a number of the fiduciary duties that would otherwise be owed by the general partner to the unitholders. Modifications of state law standards of fiduciary duties may significantly limit the ability of our shareholders and the unitholders to successfully challenge the actions of our board of directors and the general partner, respectively, in the event of a breach of their 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 liability company agreement or the limited partnership agreement to the contrary, would generally prohibit our board of directors or the general partner from taking any action or engaging in any transaction as to which it has a conflict of interest. Our limited liability company and the limited partnership agreement of Kinder Morgan Energy Partners, L.P. contain provisions that prohibit our shareholders and the limited partners, respectively, from advancing claims that otherwise might raise issues as to compliance with fiduciary duties or applicable law. For example, the limited partnership agreement of Kinder Morgan Energy Partners, L.P. provides that the general partner may take into account the interests of parties other than Kinder Morgan Energy Partners, L.P. in resolving conflicts of interest. Further, it 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 us as its delegate. Our limited liability company agreement provides that none of our directors or officers will be liable to us or any other person for any acts or omissions if they acted in good faith.

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," "will," or the negative of those terms or other variations of them or by comparable terminology. In particular, statements, express or implied, concerning future actions, conditions, events or 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 our operations and those of Kinder Morgan Energy Partners, L.P. may differ materially from those

14


expressed in these forward-looking statements. Please see "Information Regarding Forward-Looking Statements" for Kinder Morgan Energy Partners, L.P. included in Annex A. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from those in the forward-looking statements include but are not limited to the following:

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 the United States;

  

economic activity, weather, alternative energy sources, conservation and technological advances that may affect price trends and demand;

  

changes in Kinder Morgan Energy Partners, L.P.'s tariff rates implemented by the Federal Energy Regulatory Commission or the California Public Utilities Commission;

  

Kinder Morgan Energy Partners, L.P.'s ability to acquire new businesses and assets and integrate those operations into its existing operations, as well as its ability to make expansions to its facilities;

  

difficulties or delays experienced by railroads, barges, trucks, ships or pipelines in delivering products to or from Kinder Morgan Energy Partners, L.P.'s terminals or pipelines;

  

Kinder Morgan Energy Partners, L.P.'s 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 Kinder Morgan Energy Partners, L.P.'s services or provide services or products to Kinder Morgan Energy Partners, L.P.;

  


 

changes in laws or regulations, third-party relations and approvals, decisions of courts, regulators and governmental bodies that may adversely affect Kinder Morgan Energy Partners, L.P.'s business or its ability to compete;

  

our ability to offer and sell equity securities and Kinder Morgan Energy Partners, L.P.'s ability to offer and sell equity securities and debt securities or obtain debt financing in sufficient amounts to implement that portion of Kinder Morgan Energy Partners, L.P.'s business plan that contemplates growth through acquisitions of operating businesses and assets and expansions of its facilities;

  

Kinder Morgan Energy Partners, L.P.'s indebtedness could make it vulnerable to general adverse economic and industry conditions, limit its ability to borrow additional funds and/or place it at competitive disadvantages compared to its competitors that have less debt or have other adverse consequences;

  

interruptions of electric power supply to Kinder Morgan Energy Partners, L.P.'s facilities due to natural disasters, power shortages, strikes, riots, terrorism, war or other causes;

  

acts of nature, sabotage, terrorism or other similar acts causing damage greater than Kinder Morgan Energy Partners, L.P.'s insurance coverage limits;

  

capital market conditions;

  

the political and economic stability of the oil producing nations of the world;

15


    

national, international, regional and local economic, competitive and regulatory conditions and developments;

  

the ability of Kinder Morgan Energy Partners, L.P. 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; and

  

the timing and success of Kinder Morgan Energy Partners, L.P.'s business development efforts.

You should not put undue reliance on any forward-looking statements.

See Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations - Risk Factors of our Business" 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 of our Business" above. The risk factors could cause our actual results to differ materially from those contained in any forward-looking statement. We disclaim any obligation 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.

The nature of our business and operations is such that no activities or transactions of the type requiring discussion under this item are conducted or entered into.

16


Item 8.  Financial Statements and Supplementary Data.

INDEX

    

Page 

  
Report of Independent Auditors

18

Consolidated Statements of Income

19

Consolidated Statements of Comprehensive Income

19

Consolidated Balance Sheets

20

Consolidated Statements of Shareholders' Equity

21

Consolidated Statements of Cash Flows

22

Notes to Consolidated Financial Statements

23-28

Selected Quarterly Financial Data (unaudited)

29

       





17



Report of Independent Auditors

To the Board of Directors
and Shareholders of Kinder Morgan Management, LLC:

In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Kinder Morgan Management, LLC and its subsidiary at December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2003 and the period from February 14, 2001 (inception) through December 31, 2001 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes 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. We believe that our audits provide a reasonable basis for our opinion.







PricewaterhouseCoopers LLP

Houston, Texas
March 3, 2004

18




CONSOLIDATED STATEMENTS OF INCOME
Kinder Morgan Management, LLC and Subsidiary

Year Ended December 31,

February 14, 2001
(Inception) Through
December 31,

2003

2002

2001

(In thousands except per share amounts)

Equity in Earnings of Kinder Morgan Energy Partners, L.P.

$   94,775 

$   72,199 

$   28,354 

Provision for Income Taxes

    36,014 

    26,865 

    11,342 

  
Net Income

$   58,761 

$   45,334 

$   17,012 

========== 

========== 

========== 

  
Earnings Per Share, Basic and Diluted

$     1.24 

$     1.23 

$     0.78 

========== 

========== 

========== 

  
Number of Shares Used in Computing
  Basic and Diluted Earnings Per Share

    47,372 

    36,790 

    21,756 

========== 

========== 

========== 

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Year Ended December 31,

February 14, 2001
(Inception) Through
December 31,

2003

2002

2001

(In thousands except per share amounts)

Net Income

$   58,761 

$   45,334 

$   17,012 

  
Equity in Other Comprehensive Loss of Equity
Method Investee (Net of Tax Benefits of $11,828 and $3,179)

   (19,297)

    (5,187)

         - 

  
Total Comprehensive Income

$   39,464 

$   40,147 

$   17,012 

========== 

========== 

========== 

The accompanying notes are an integral part of these statements.

 

19




CONSOLIDATED BALANCE SHEETS

Kinder Morgan Management, LLC and Subsidiary

December 31,

2003

2002

(In thousands)

ASSETS

  
Current Assets:
Accounts Receivable - Related Party

$   14,661 

$   14,401 

Prepayments and Other

     1,657 

     4,975 

    16,318 

    19,376 

  
Investment in Kinder Morgan Energy Partners, L.P.

 1,489,968 

 1,419,814 

  
Total Assets

$1,506,286 

$1,439,190 

========== 

========== 

  

LIABILITIES AND SHAREHOLDERS' EQUITY

  
Current Liabilities:
Accounts Payable

$    2,742 

$    3,419 

Accrued Expenses and Other

    13,500 

    15,881 

  

    16,242 

    19,300 

  
Deferred Income Taxes

    64,459 

    35,027 

  
Shareholders' Equity:
Voting Shares - Unlimited Authorized; 2 Voting Shares Issued and Outstanding

       100 

       100 

Listed Shares - Unlimited Authorized; 48,996,463 and 45,654,046 Listed Shares
  Issued and Outstanding, Respectively

 1,559,485 

 1,440,255 

Retained Deficit

  (109,516)

   (50,305)

Accumulated Other Comprehensive Loss

   (24,484)

    (5,187)

Total Shareholders' Equity

 1,425,585 

 1,384,863 

Total Liabilities and Shareholders' Equity

$1,506,286 

$1,439,190 

========== 

========== 

  

The accompanying notes are an integral part of these statements.

 

20





CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
Kinder Morgan Management, LLC and Subsidiary

Year Ended December 31,

February 14, 2001 (Inception)
Through December 31,

2003

2002

2001

Shares

Amount

Shares

Amount

Shares

Amount

(Dollars in thousands)

Voting Shares:
    Beginning Balance

         2

$      100 

         2

$      100 

         -

$        - 

    Issuance of Voting Shares to Kinder
      Morgan G.P., Inc.

         -

         - 

         -

         - 

         2

       100 

    Ending Balance

         2

       100 

         2

       100 

         2

       100 

  
Listed Shares:
    Beginning Balance

45,654,046

 1,440,255 

30,636,361

 1,024,317 

         -

         - 

    Initial Public Offering of Listed Shares

         -

         - 

         -

         - 

29,750,000

 1,047,349 

    Secondary Public Offering of Listed Shares

         -

         - 

12,478,900

   343,170 

         -

         - 

    Share Dividends

 3,342,417

   117,972 

 2,538,785

    80,133 

   886,361

    32,518 

    Underwriting Discount and Offering Expenses

         -

         - 

         -

   (14,611)

         -

   (55,480)

    Other Issuance and Share Split Costs

         -

         - 

         -

       (44)

         -

       (70)

    Revaluation of Kinder Morgan Energy
       Partners, L.P. Investment (Note 3)

         -

     1,258 

         -

     7,290 

         -

         - 

    Ending Balance

48,996,463

 1,559,485 

45,654,046

 1,440,255 

30,636,361

 1,024,317 

  
Retained Deficit:
    Beginning Balance

   (50,305)

   (15,506)

         - 

    Net Income

    58,761 

    45,334 

    17,012 

    Share Dividends

  (117,972)

   (80,133)

   (32,518)

    Ending Balance

  (109,516)

   (50,305)

   (15,506)

  
Accumulated Other Comprehensive
   Loss (Net of Tax Benefits):
    Beginning Balance

    (5,187)

         - 

         - 

    Equity in Other Comprehensive Loss
       of Equity Method Investees (Net of Tax
       Benefits of $11,828 and $3,179)

   (19,297)

    (5,187)

         - 

    Ending Balance

          

   (24,484)

          

    (5,187)

          

         - 

  
Total Shareholders' Equity

48,996,465

$1,425,585 

45,654,048

$1,384,863 

30,636,363

$1,008,911 

==========

========== 

==========

========== 

==========

========== 

  

The accompanying notes are an integral part of these statements.

21




CONSOLIDATED STATEMENTS OF CASH FLOWS
Kinder Morgan Management, LLC and Subsidiary

Increase (Decrease) in Cash and Cash Equivalents

Year Ended December 31,

February 14, 2001
(Inception) Through December 31,

2003

2002

2001

(In thousands)

Cash Flows From Operating Activities:
Net Income

$  58,761 

$  45,334 

$   17,012 

Adjustments to Reconcile Net Income to Net Cash Flows from
   Operating Activities:
    Deferred Income Taxes

   36,014 

   26,865 

    11,342 

    Equity in Earnings of Kinder Morgan Energy Partners, L.P.

  (94,775)

  (72,199)

   (28,354)

    Increase in Accounts Receivable

     (260)

   (8,250)

    (6,083)

    Decrease (Increase) in Other Current Assets

    3,318 

    3,513 

    (8,488)

    (Decrease) Increase in Accounts Payable

     (677)

    3,259 

       160 

    (Decrease) Increase in Other Current Liabilities

   (2,381)

    1,478 

    14,411 

Net Cash Flows Provided by Operating Activities

        - 

        - 

         - 

  
Cash Flows From Investing Activities:
Purchase of i-units of Kinder Morgan Energy Partners, L.P.

        - 

 (328,559)

  (991,869)

Net Cash Flows Used in Investing Activities

        - 

 (328,559)

  (991,869)

  
Cash Flows From Financing Activities:
Shares Issued

        - 

  343,170 

 1,047,349 

Share Issuance Costs

        - 

  (14,611)

   (55,480)

Net Cash Flows Provided by Financing Activities

        - 

  328,559 

   991,869 

  
Net Increase in Cash and Cash Equivalents

        - 

        - 

         - 

Cash and Cash Equivalents at Beginning of Period

        - 

        - 

         - 

Cash and Cash Equivalents at End of Period

$       - 

$       - 

$        - 

========= 

========= 

========== 

  

The accompanying notes are an integral part of these statements.

22


KINDER MORGAN MANAGEMENT, LLC AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.  General

Kinder Morgan Management, LLC is a publicly traded Delaware limited liability company that was formed on February 14, 2001. Kinder Morgan G.P., Inc., an indirect wholly owned subsidiary of Kinder Morgan, Inc., (a midstream energy company traded on the New York Stock Exchange under the symbol "KMI"), owns all of our voting shares. References to "we," "our" or "the Company" are intended to mean Kinder Morgan Management, LLC and its consolidated subsidiary.

2.  Significant Accounting Policies

(A) Basis of Presentation

Our consolidated financial statements include the accounts of Kinder Morgan Management, LLC and its wholly owned subsidiary, Kinder Morgan Services LLC. All material intercompany transactions and balances have been eliminated.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities, and the reported amounts of revenues and expenses. Actual results could differ from these estimates.

(B) Accounting for Investment in Kinder Morgan Energy Partners, L.P.

We use the equity method of accounting for our investment in Kinder Morgan Energy Partners, L.P., which is further described in Notes 3 and 4. Kinder Morgan Energy Partners, L.P. is a publicly traded limited partnership and is traded on the New York Stock Exchange under the symbol "KMP." We record, in the period in which it is earned, our share of the earnings of Kinder Morgan Energy Partners, L.P. attributable to the i-units we own. We receive distributions from Kinder Morgan Energy Partners, L.P. in the form of additional i-units, which increase the number of i-units we own. We issue additional shares (or fractions thereof) of the Company to our existing shareholders in an amount equal to the additional i-units received from Kinder Morgan Energy Partners, L.P. At December 31, 2003, through our ownership of i-units, we owned approximately 25.9% of all of Kinder Morgan Energy Partners, L.P.'s outstanding limited partner interests.

We adjust the carrying value of our investment when an equity method investee or a consolidated subsidiary issues additional equity (or reacquires equity shares) in any manner that alters our ownership percentage. Differences between the per unit sales proceeds from these equity issuances (or costs for reacquisitions) and our underlying book basis are recorded directly to paid-in capital rather than being recognized as gains or losses. Two such transactions are described in Note 3.

(C) Accounting for Share Distributions

Our board of directors declares and we make additional share distributions at the same times that Kinder Morgan Energy Partners, L.P. declares and makes distributions on the i-units to us, so that the number of i-units we own and the number of our shares outstanding remain equal. We account for the share distributions we make by charging retained earnings and crediting outstanding shares with amounts that equal the number of shares distributed multiplied by the closing price of the shares on the date the distribution is payable. As a result, we expect that our retained earnings will always be in a deficit

23


position because (i) distributions per unit for Kinder Morgan Energy Partners, L.P. (which serve to reduce our retained earnings) are based on earnings plus depreciation, depletion and amortization minus sustaining capital expenditures, which amount generally exceeds the earnings per unit (which serve to increase our retained earnings) and (ii) the impact on our retained earnings attributable to our equity in the earnings of Kinder Morgan Energy Partners, L.P. is recorded after a provision for income taxes.

(D) Earnings Per Share

Both basic and diluted earnings per share are computed based on the weighted-average number of shares outstanding during each period, adjusted for share splits. There are no securities outstanding that may be converted into or exercised for shares.

(E) Income Taxes

We are a limited liability company that has elected to be treated as a corporation for federal income tax purposes. Deferred income tax assets and liabilities are recognized for temporary differences between the basis of our assets and liabilities for financial reporting and tax purposes. We include changes in tax legislation in the relevant computations in the period in which such changes are effective.

Our long-term deferred income tax liability of $64.5 million and $35.0 million at December 31, 2003 and 2002, respectively, results from recognition of the increased investment associated with recording our equity in the earnings of Kinder Morgan Energy Partners, L.P. The effective tax rate utilized in computing our income tax provision was 40 percent for 2001 and 38 percent for 2002 and 2003, composed of the 35 percent federal statutory rate and a provision for state income taxes. As a result of the decrease in the effective tax rate from 2001 to 2002, there was a decrease in the cumulative deferred tax liability in 2002. This resulted in a 0.8 percent decrease in the 2002 income tax provision.

We entered into a tax indemnification agreement with Kinder Morgan, Inc. Pursuant to this tax indemnification agreement, Kinder Morgan, Inc. agreed to indemnify us for any tax liability attributable to our formation or our management and control of the business and affairs of Kinder Morgan Energy Partners, L.P. and for any taxes arising out of a transaction involving the i-units we own to the extent the transaction does not generate sufficient cash to pay our taxes with respect to such transaction.

(F) Cash Flow Information

We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. No cash payments for interest or income taxes were made during the periods presented.

3.  Capitalization

Our authorized capital structure consists of two classes of interests: (1) our listed shares and (2) our voting shares, collectively referred to in this document as our "shares." Prior to the May 2001 initial public offering of our shares, our issued capitalization consisted of $100,000 contributed by Kinder Morgan, G.P., Inc. for two voting shares. At December 31, 2003, Kinder Morgan, Inc. owned approximately 14.5 million, or approximately 29.7% of our outstanding shares.

In June 2003, Kinder Morgan Energy Partners, L.P. issued 4.6 million common units in a public offering at a price of $39.35 per common unit, receiving total net proceeds (after underwriting discount) of $173.3 million. We did not acquire any of these common units. This issuance of common units by Kinder Morgan Energy Partners, L.P. changed our percentage ownership of Kinder Morgan Energy Partners, L.P. and had the associated effects of (i) increasing our investment in the net assets of Kinder

24


Morgan Energy Partners by $6.4 million, (ii) associated accumulated deferred income taxes by $2.4 million and (iii) paid-in capital by $4.0 million. See Note 1(B).

On August 6, 2002, we closed the issuance and sale of 12,478,900 listed shares in an underwritten public offering. None of the shares from our offering were purchased by Kinder Morgan, Inc. The net proceeds of approximately $328.6 million from the offering were used to buy additional i-units from Kinder Morgan Energy Partners, L.P. This issuance of i-units by Kinder Morgan Energy Partners, L.P. changed our percentage ownership of Kinder Morgan Energy Partners, L.P. and had the associated effects of increasing (i) our investment in the net assets of Kinder Morgan Energy Partners, L.P. by $7.3 million, (ii) our deferred income taxes by $2.8 million and (iii) paid-in capital by $4.5 million. See Note 1(B).

By approval of our shareholders other than Kinder Morgan, Inc., effective at the close of business on July 23, 2002, Kinder Morgan, Inc. no longer has an obligation to exchange, upon presentation by the holder, our listed shares for either Kinder Morgan Energy Partners, L.P.'s common units that it owns or, at Kinder Morgan, Inc.'s election, cash. Approximately 6.8 million of our listed shares were exchanged in 2002 prior to the elimination of the exchange feature and a total of approximately 9.7 million of our listed shares were exchanged for Kinder Morgan Energy Partners, L.P.'s common units or cash during all periods prior to the elimination of the exchange feature. In conjunction with the elimination of the exchange feature, on July 29, 2002, Kinder Morgan, Inc. issued to each of our shareholders (i) .09853 shares of Kinder Morgan, Inc. common stock for each 100 of our listed shares held of record by such shareholder at the close of business on July 23, 2002, and (ii) cash in lieu of fractional shares.

On July 18, 2001, Kinder Morgan Energy Partners, L.P. announced that we, as delegate of its general partner, had approved a two-for-one split of its common units. The common unit split, in the form of a distribution of one common unit for each common unit outstanding, occurred on August 31, 2001. This split resulted in our receiving one additional i-unit for each i-unit that we owned on the record date, August 17, 2001. Also on July 18, 2001, we announced a two-for-one split of our shares. This share split, in the form of a one-share distribution for each share outstanding, occurred on August 31, 2001.

In May 2001, in each case after adjustment for the August 31, 2001 two-for-one share split, we issued 26,775,000 shares for cash to the public and 2,975,000 shares to Kinder Morgan, Inc., using all of the approximately $991.9 million net proceeds of the offering to purchase 29,750,002 i-units from Kinder Morgan Energy Partners, L.P. Quarterly distributions on these i-units from Kinder Morgan Energy Partners, L.P.'s operations and interim capital transactions are received in additional i-units rather than cash. Each time Kinder Morgan Energy Partners, L.P. issues i-units to us, we distribute an equal number of shares to holders of our shares. Pursuant to our limited liability company agreement, the number of i-units and shares will remain equal.

On February 13, 2004, we paid a share distribution to shareholders of record as of January 30, 2004, based on the $0.68 per common unit distribution declared by Kinder Morgan Energy Partners, L.P. This distribution, which is paid in the form of additional shares or fractions thereof based on the average market price of a share determined for a ten-trading day period ending on the trading day immediately prior to the ex-dividend date for our shares, was 0.015885 shares per outstanding share.

4.  Business Activities and Related Party Transactions

At no time after our formation and prior to our initial public offering did we have any operations or own any interest in Kinder Morgan Energy Partners, L.P. Upon the closing of our initial public offering, we became a limited partner in Kinder Morgan Energy Partners, L.P. and, pursuant to a delegation of control agreement, we assumed the management and control of its business and affairs. Under the delegation of control agreement, Kinder Morgan G.P., Inc. delegated to us, to the fullest extent

25


permitted under Delaware law and the Kinder Morgan Energy Partners, L.P. partnership agreement, all of Kinder Morgan G.P., Inc.'s power and authority to manage and control the business and affairs of Kinder Morgan Energy Partners, L.P., subject to Kinder Morgan G.P., Inc.'s right to approve certain transactions. Kinder Morgan Energy Partners, L.P. will either pay directly or reimburse us for all expenses we incur in performing under the delegation of control agreement and will be obligated to indemnify us against claims and liabilities provided that we have acted in good faith and in a manner we believed to be in, or not opposed to, the best interests of Kinder Morgan Energy Partners, L.P. and the indemnity is not prohibited by law. Kinder Morgan Energy Partners, L.P. consented to the terms of the delegation of control agreement including Kinder Morgan Energy Partners, L.P.'s indemnity and reimbursement obligations. We do not receive a fee for our service under the delegation of control agreement, nor do we receive any margin or profit on the expense reimbursement. We incurred approximately $111.4 million and $106.9 million of expenses during the years ended December 31, 2003 and 2002, respectively, and $48.5 million during the period from February 14, 2001 (inception) through December 31, 2001 on behalf of Kinder Morgan Energy Partners, L.P. The expense reimbursements received from Kinder Morgan Energy Partners, L.P. are accounted for as a reduction to the expense incurred. The net monthly balance payable or receivable from these activities is settled in cash in the following month.

Kinder Morgan Services LLC is our wholly owned subsidiary and provides centralized payroll and employee benefits services to us, Kinder Morgan G.P., Inc., Kinder Morgan Energy Partners, L.P. and Kinder Morgan Energy Partners, L.P.'s operating partnerships and subsidiaries (collectively, the "Group"). Employees of KMGP Services Company, Inc., a subsidiary of Kinder Morgan G.P., Inc., are assigned to work for one or more members of the Group. When they do so, they remain under our ultimate management and control. 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 Kinder Morgan, Inc., and the related administrative costs are allocated to members of the Group in accordance with 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 its limited partnership agreement, Kinder Morgan Energy Partners, L.P. reimburses Kinder Morgan Services LLC for its share of these administrative costs, and such reimbursements are accounted for as described above.

26


5.  Summarized Financial Information for Kinder Morgan Energy Partners, L.P.

Following is summarized financial information for Kinder Morgan Energy Partners, L.P., a publicly traded limited partnership in which we own a significant interest. Additional information on Kinder Morgan Energy Partners, L.P.'s results of operations and financial position are contained in its 2003 Annual Report on Form 10-K, which is attached to this report as Annex A.

Summarized Income Statement Information

Year Ended December 31,

2003

2002

2001

(In thousands)

Operating Revenues

$ 6,624,322

$ 4,237,057

$ 2,946,676

Operating Expenses

  5,817,633

  3,512,759

  2,382,848

Operating Income

$   806,689

$   724,298

$   563,828

===========

===========

===========

  
Income Before Cumulative Effect of a
   Change in Accounting Principle

$   693,872

$   608,377

$   442,343

===========

===========

===========

  
Net Income

$   697,337

$   608,377

$   442,343

===========

===========

===========

Summarized Balance Sheet Information

As of December 31,

2003

2002

(In thousands)

Current Assets

$    705,522

$    669,390

============

============

Noncurrent Assets

$  8,433,660

$  7,684,186

============

============

  
Current Liabilities

$    804,379

$    813,327

============

============

Noncurrent Liabilities

$  4,783,812

$  4,082,287

============

============

Minority Interest

$     40,064

$     42,033

============

============

6.  Recent Accounting Pronouncements

In January 2004, the Financial Accounting Standards Board ("FASB") issued FASB Staff Position ("FSP") FAS 106-1, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the "Act"). This FSP permits a sponsor of a postretirement health care plan that provides a prescription drug benefit to make a one-time election to defer accounting for the effects of the Act. Regardless of whether a company elects that deferral, the FSP requires certain disclosures pending further consideration of the underlying accounting issues. We have no employees.

In December 2003, the FASB issued Interpretation (FIN) No. 46 (revised December 2003), Consolidation of Variable Interest Entities. This interpretation of Accounting Research Bulletin No. 51, Consolidated Financial Statements, addresses consolidation by business enterprises of certain variable interest entities. This interpretation explains how to identify variable interest entities and how an enterprise assesses its interests in a variable interest entity to decide whether to consolidate that entity. It requires existing unconsolidated variable interest entities to be consolidated by their primary beneficiaries if the entities do not effectively disperse risks among parties involved. Variable interest entities that effectively disperse risks will not be consolidated unless a single party holds an interest or combination of interests that effectively recombines risks that were previously dispersed. Application of this interpretation is required in financial statements of public entities that have interests in variable interest entities or potential variable interest entities commonly referred to as special-purpose entities for periods ending after December 15, 2003. Application by public entities (other than small business

27


issuers) for all other types of entities is required in financial statements for periods ending after March 15, 2004. We currently have no interests in variable interest entities.

In December 2002, the FASB issued Statement of Financial Accounting Standards ("SFAS") No. 148, Accounting for Stock-Based Compensation - Transition and Disclosure. This amendment to FASB Statement No. 123 provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, this statement amends the disclosure requirements of FASB Statement No. 123 to require disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. The provisions of this statement are effective for financial statements of interim or annual periods after December 15, 2002. Early application of the disclosure provisions is encouraged, and earlier application of the transition provisions is permitted, provided that financial statements for the 2002 fiscal year have not been issued as of the date the statement was issued. We have no employees.

In November 2002, the FASB issued Interpretation No. 45, Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others. This interpretation of FASB Statements No. 5, 57 and 107 and rescission of FASB Interpretation No. 34 elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. This interpretation incorporates, without change, the guidance in FASB Interpretation No. 34, Disclosure of Indirect Guarantees of Indebtedness of Others, which is being superceded. The initial recognition and initial measurement provisions of this interpretation are applicable on a prospective basis to guarantees issued or modified after December 31, 2002. The disclosure requirements in this interpretation are effective for financial statements of interim or annual periods after December 15, 2002. The interpretive guidance incorporated from Interpretation No. 34 continues to be required for financial statements for fiscal years ending after June 15, 1981.

In April 2002, the FASB issued SFAS No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections. The provisions of this statement related to the rescission of FASB Statement No. 4 are effective for fiscal years beginning after May 15, 2002, the provisions related to FASB Statement No. 13 are effective for transactions occurring after May 15, 2002, and all other provisions of this statement are effective for financial statements issued on or after May 15, 2002.

We do not expect these pronouncements to have a significant impact on our financial statements, except for any impacts that may result from changes in our equity in earnings of Kinder Morgan Energy Partners, L.P. as a result of its adoption of these pronouncements.

28


KINDER MORGAN MANAGEMENT, LLC AND SUBSIDIARY

SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
Quarterly Operating Results for 2003 and 2002

2003-Three Months Ended

March 31

June 30

September 30

December 31

(In thousands except per share amounts)

Equity in Earnings of Kinder Morgan
  Energy Partners, L.P.

$  23,817 

$  22,686 

$  23,263 

$  25,009 

Provision for Income Taxes

    9,050 

    8,621 

    8,840 

    9,503 

Net Income

$  14,767 

$  14,065 

$  14,423 

$  15,506 

========= 

========= 

========= 

========= 

  
Earnings Per Share, Basic and Diluted

$    0.32 

$    0.30 

$    0.30 

$    0.32 

========= 

========= 

========= 

========= 

  
Number of Shares Used in Computing
  Basic and Diluted Earnings Per Share

   46,093 

   46,957 

   47,797 

   48,608 

========= 

========= 

========= 

========= 

  

2002-Three Months Ended

March 31

June 30

September 30

December 31

(In thousands except per share amounts)

Equity in Earnings of Kinder Morgan
  Energy Partners, L.P.

$  14,794 

$  14,872 

$  19,709 

$  22,824 

Provision for Income Taxes

    5,918 

    5,797 

    7,785 

    7,365 

Net Income

$   8,876 

$   9,075 

$  11,924 

$  15,459 

========= 

========= 

========= 

========= 

  
Earnings Per Share, Basic and Diluted

$    0.29 

$    0.29 

$    0.30 

$    0.34 

========= 

========= 

========= 

========= 

  
Number of Shares Used in Computing
  Basic and Diluted Earnings Per Share

   30,868 

   31,363 

   39,537 

   45,206 

========= 

========= 

========= 

========= 

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

None.

Item 9A. Controls and Procedures.

As of December 31, 2003, 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 in accordance with 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 in all material respects 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. There has been no change in our internal control over financial reporting during the three months ended December 31, 2003 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

29


PART III

Item 10.  Directors and Executive Officers of the Registrant.

Set forth below is certain information concerning our directors and executive officers. All directors are elected annually by, and may be removed by, Kinder Morgan G.P., Inc. as the sole holder of our voting shares. All officers serve at the discretion of our board of directors. In addition to the individuals named below, Kinder Morgan, Inc. was one of our directors until its resignation in January 2003.

Name

Age

Position

Richard D. Kinder

59

Director, Chairman and Chief Executive Officer
Michael C. Morgan

35

President
C. Park Shaper

35

Director, Vice President and Chief Financial Officer
Edward O. Gaylord

72

Director
Gary L. Hultquist

60

Director
Perry M. Waughtal

68

Director
Thomas A. Bannigan

50

President, Products Pipelines
R. Tim Bradley

48

President, CO2
David D. Kinder

29

Vice President, Corporate Development
Joseph Listengart

35

Vice President, General Counsel and Secretary
Deborah A. Macdonald

52

President, Natural Gas Pipelines
Jeffrey R. Armstrong

35

President, Terminals
James E. Street

47

Vice President, Human Resources and Administration

Richard D. Kinder is Director, Chairman and Chief Executive Officer of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. Mr. Kinder has served as Director, Chairman and Chief Executive Officer of Kinder Morgan Management, LLC since its formation in February 2001. He was elected Director, Chairman and Chief Executive Officer of Kinder Morgan, Inc. in October 1999. He was elected Director, Chairman and Chief Executive Officer of Kinder Morgan G.P., Inc. in February 1997. Mr. Kinder is also a director of Baker Hughes Incorporated. Mr. Kinder is the uncle of David Kinder, Vice President, Corporate Development of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc.

Michael C. Morgan is President of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. Mr. Morgan was elected to each of these positions in July 2001. He was also elected Director of Kinder Morgan, Inc. in January 2003. Mr. Morgan served as Vice President - Strategy and Investor Relations of Kinder Morgan Management, LLC from February 2001 to July 2001. He served as Vice President - Strategy and Investor Relations of Kinder Morgan, Inc. and Kinder Morgan G.P., Inc. from January 2000 to July 2001. He served as Vice President, Corporate Development of Kinder Morgan G.P., Inc. from February 1997 to January 2000. Mr. Morgan was the Vice President, Corporate Development of Kinder Morgan, Inc. from October 1999 to January 2000. From August 1995 until February 1997, Mr. Morgan was an associate with McKinsey & Company, an international management consulting firm. In 1995, Mr. Morgan received a Masters in Business Administration from the Harvard Business School. From March 1991 to June 1993, Mr. Morgan held various positions, including Assistant to the Chairman, at PSI Energy, Inc. Mr. Morgan received a Bachelor of Arts in Economics and a Masters of Arts in Sociology from Stanford University in 1990.

C. Park Shaper is Director, Vice President and Chief Financial Officer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. and Vice President and Chief Financial Officer of Kinder Morgan, Inc. Mr. Shaper was elected Director of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. in January 2003. He was elected Vice President, Treasurer and Chief Financial Officer of Kinder Morgan Management, LLC upon its formation in February 2001, and served as Treasurer of Kinder Morgan Management, LLC from February 2001 to January 2004. He has served as Treasurer of Kinder Morgan, Inc. from April 2000 to January 2004 and Vice President and Chief Financial Officer of Kinder

30


Morgan, Inc. since January 2000. Mr. Shaper was elected Vice President, Treasurer and Chief Financial Officer of Kinder Morgan G.P., Inc. in January 2000, and served as Treasurer of Kinder Morgan G.P., Inc. from January 2000 to January 2004. From June 1999 to December 1999, Mr. Shaper was President and Director of Altair Corporation, an enterprise focused on the distribution of web-based investment research for the financial services industry. He served as Vice President and Chief Financial Officer of First Data Analytics, a wholly owned subsidiary of First Data Corporation, from 1997 to June 1999. From 1995 to 1997, he was a consultant with The Boston Consulting Group. He received a Masters in 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.

Edward O. Gaylord is a Director of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. Mr. Gaylord was elected Director of Kinder Morgan Management, LLC 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. Mr. Gaylord serves on the Board of Directors of Seneca Foods Corporation. Mr. Gaylord currently serves as the chairman of the compensation and audit committees of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc.

Gary L. Hultquist is a Director of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. Mr. Hultquist was elected Director of Kinder Morgan Management, LLC 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. Mr. Hultquist is a member of the Board of Directors of netMercury, Inc., a supplier of automated supply chain services, critical spare parts and consumables used in semiconductor manufacturing. Previously, Mr. Hultquist practiced law in two San Francisco area firms for over 15 years, specializing in business, intellectual property, securities and venture capital litigation.

Perry M. Waughtal is a Director of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. Mr. Waughtal was elected Director of Kinder Morgan Management, LLC upon its formation in February 2001. Mr. Waughtal was elected Director of Kinder Morgan G.P., Inc. in April 2000. Mr. Waughtal is the Chairman, a limited partner and a 40% owner of Songy Partners Limited, an Atlanta, Georgia based real estate investment company. Mr. Waughtal advises Songy's management on real estate investments and has overall responsibility for strategic planning, management and operations. He is also a director of Prime Medical Services, Inc. Previously, Mr. Waughtal served for over 30 years as Vice Chairman of Development and Operations and as Chief Financial Officer for Hines Interests Limited Partnership, a real estate and development entity based in Houston, Texas.

Thomas A. Bannigan is President, Product Pipelines of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. and President and Chief Executive Officer of Plantation Pipe Line Company. Mr. Bannigan was elected President, Products Pipelines of Kinder Morgan Management, LLC upon its formation in February 2001. He was elected 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. From 1985 to May 1998, Mr. Bannigan was Vice President, General Counsel and Secretary of Plantation Pipe Line Company. 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.

R. Tim Bradley is President, CO2 of Kinder Morgan Management, LLC and of Kinder Morgan G.P., Inc. and President of Kinder Morgan CO2 Company, L.P. Mr. Bradley was elected President, CO2 of Kinder Morgan Management, LLC and Vice President (President, CO2) of Kinder Morgan G.P., Inc. in April 2001. Mr. Bradley has been President of Kinder Morgan CO2 Company, L.P. (which name changed

31


from Shell CO2 Company, Ltd. in April 2000) since March 1998. From May 1996 to March 1998, Mr. Bradley was Manager of CO2 Marketing for Shell Western E&P, Inc. 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 of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. Mr. Kinder was elected Vice President, Corporate Development of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. in October 2002. He served as manager of corporate development for Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. from January 2000 to October 2002. He served as an associate in the corporate development group of Kinder Morgan, Inc. and Kinder Morgan G.P., Inc. from February 1999 to January 2000. From June 1996 to February 1999, Mr. Kinder was in the analyst and associate program at Enron Corp. 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 Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. Mr. Listengart was elected Vice President, General Counsel and Secretary of Kinder Morgan Management, LLC 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 Kinder Morgan, Inc. in October 1999. Mr. Listengart was elected Kinder Morgan G.P., Inc.'s Secretary in November 1998 and became an employee of Kinder Morgan G.P., Inc. in March 1998. 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.

Deborah A. Macdonald is President, Natural Gas Pipelines of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. She was elected as President, Natural Gas Pipelines in June 2002. Ms. Macdonald served as President of Natural Gas Pipeline Company of America from October 1999 to March 2003. Prior to joining Kinder Morgan, Ms. Macdonald worked as Senior Vice President of legal affairs for Aquila Energy Company from January 1999 to October 1999, and was engaged in a private energy consulting practice from June 1996 to December 1999. Ms. Macdonald received her Juris Doctor, summa cum laude, from Creighton University in May 1980 and received a Bachelors degree, magna cum laude, from Creighton University in December 1972.

Jeffrey R. Armstrong is President, Terminals of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. Mr. Armstrong became President of our Terminals Segment in July 2003. Prior to that, he served as President, Kinder Morgan Liquids Terminals LLC from March 1, 2001, when the company was formed via the acquisition of GATX Terminals, until 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 a Masters of Business Administration degree from the University of Notre Dame.

James E. Street is Vice President, Human Resources and Administration of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. Mr. Street was elected Vice President, Human Resources and Administration of Kinder Morgan Management, LLC upon its formation in February 2001. He was elected Vice President, Human Resources and Administration of Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. in August 1999. From October 1996 to August 1999, Mr. Street was Senior Vice President, Human Resources and Administration for Coral Energy, a subsidiary of Shell Oil Company. 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.

32


Corporate Governance

Pursuant to a delegation of control agreement among Kinder Morgan Energy Partners, L.P., its general partner, us and others, we manage and control the business and affairs of Kinder Morgan Energy Partners, L.P., except that we cannot take certain specified actions without the approval of Kinder Morgan Energy Partners, L.P.'s general partner. The limited partnership agreement of Kinder Morgan Energy Partners, L.P. provides for a general partner of the Partnership rather than a board of directors. Through the operation of Kinder Morgan Energy Partners, L.P.'s limited partnership agreement and the delegation of control agreement, our board of directors performs the functions of and is the equivalent of a board of directors of Kinder Morgan Energy Partners, L.P. Similarly, the standing committees of our board function as committees of the board of Kinder Morgan Energy Partners, L.P. Our board of directors is comprised of the same persons who comprise Kinder Morgan Energy Partners, L.P.'s general partner's board of directors. References in this report to the board mean our board acting as the delegate of and as the board of directors of Kinder Morgan Energy Partners, L.P.'s general partner, and references to committees mean committees of the board acting as the delegate of and as the committees of the board of directors of Kinder Morgan Energy Partners, L.P.'s general partner.

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 and rules respectively. 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 us or any of 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 or interim chief executive officer, such employment relationship ended by the date of determination);

  

If within the period of three years prior to the determination the director received no more than, and has no immediate family member that received more than, $100,000 per year 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 or interim chief executive officer, and (iii) compensation received by an immediate family member for service as a non-executive employee;

  

If the director is at the date of determination an executive officer or an employee, or has an immediate family member that is at the date of determination an executive officer, of another company that, within the last three full fiscal years prior to the date of determination made payments to, or received payments from, us and our affiliates for property or services in an amount which, in any single fiscal year, was less than the greater of $1 million or 2% of such other company's annual consolidated gross revenues. Charitable organizations are not considered "companies" for purposes of this determination;

  

If the director is also a director, but is not an employee or executive officer, of Kinder Morgan Energy Partners, L.P.'s general partner or another affiliate or affiliates of us, Kinder Morgan Energy Partners or its general partner, 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, Kinder Morgan, Inc., and Kinder Morgan Energy Partners, L.P. or its general partner.

33


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 regular board meetings, these three non-management directors also meet in executive session without members of management. Mr. Waughtal has been elected for a one year term expiring in October 2004 to serve as lead director to develop the agendas for and moderate these executive sessions of independent directors.

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 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.

We have not made, nor has Kinder Morgan Energy Partners, L.P. nor its general partner made, within the preceding three years, contributions to any charitable organization in which any of our directors serves as an executive officer in any single fiscal year that exceeded the greater of $1 million or 2% of such charitable organization's consolidated gross revenues.

We make available free of charge within the "Investors" information section of our internet website, at www.kindermorgan.com, and in print to any shareholder 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 officers and the chief executive officer, among others). Requests for copies may be directed to Investor Relations, Kinder Morgan Management, L.L.C., 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, and any waiver from a provision of that code granted to our executive officers or directors, on our internet website within five 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 Securities and Exchange Commission.

You may contact our lead director or our independent directors as a group by mail to Kinder Morgan Management, LLC, 500 Dallas Street, Suite 1000, Houston, Texas 77002, Attention: General Counsel, or by e-mail (go to www.kindermorgan.com and click "Contact Us"). Your 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 Securities and Exchange Commission 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 2003.

34


Item 11.  Executive Compensation.

All of our individual executive officers and directors serve in the same capacities for Kinder Morgan G.P., Inc. Certain of those executive officers, including all of the named officers below, also serve as executive officers of Kinder Morgan, Inc. All information in this report with respect to compensation of executive officers describes the total compensation received by those persons in all capacities for Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc., Kinder Morgan, Inc. and their respective affiliates.

Summary Compensation Table

Annual Compensation

Long-term
Compensation Awards

Name and Principal Position

Year

Salary

Bonus1

Restricted
Stock
Awards
2

Kinder Morgan, Inc. Shares Underlying
Options

All Other
Compensation
3

Richard D. Kinder

2003

$      1 

$      - 

$        -

        -    

$     - 

  Director, Chairman and
    CEO

2002

       1 

       - 

         -

        -    

      - 

2001

       1 

       - 

         -

        -    

      - 

  

Michael C. Morgan

2003

 200,000 

 875,000 

 5,380,000

        -    

  9,815 

  President

2002

 200,000 

 950,000 

         -

        -    

  9,584 

2001

 200,000 

 350,000 

   569,900

        -    

  7,835 

  

C. Park Shaper

2003

 200,000 

 875,000 

 5,918,000

        -    

  8,378 

  Director, Vice President

2002

 200,000 

 950,000 

         -

  100,0004   

  8,336 

    and CFO

2001

 200,000 

 350,000 

   569,900

        -    

  7,186 

  

Deborah A. Macdonald

2003

 200,000 

 875,000 

 5,380,000

        -    

  8,966 

  President, Natural Gas

2002

 200,000 

 950,000 

         -

   50,0005   

  8,966 

    Pipelines

2001

 200,000 

 350,000 

   569,900

        -    

 32,816 

  

Joseph Listengart

2003

 200,000 

 825,000 

 3,766,000

        -    

  8,378 

  Vice President, General

2002

 200,000 

 950,000 

         -

        -    

  8,336 

    Counsel and Secretary

2001

 200,000 

 350,000 

   569,900

        -    

  7,186 

  

  
1 Amounts earned in year shown and paid the following year.
 
2

Represent shares of restricted Kinder Morgan, Inc. stock awarded in 2003 and 2001. The 2003 and 2001 awards were issued under a shareholder approved plan. For the 2003 awards, value computed as the number of shares awarded times the closing price on date of grant ($53.80 at July 16, 2003). 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. To vest, Kinder Morgan Energy Partners, L.P. and/or Kinder Morgan, Inc. must also achieve one of the following performance hurdles during the vesting period: (i) Kinder Morgan, Inc. must earn $3.70 per share in any fiscal year; (ii) Kinder Morgan Energy Partners, L.P. must distribute $2.72 over four consecutive quarters; (iii) fund at least one year's annual incentive program; or (iv) Kinder Morgan, Inc.'s stock price must average over $60.00 per share during any consecutive 30-day period. One of these performance hurdles has already been met. The 2003 awards were long-term equity compensation for our senior management through July 2008, and neither Kinder Morgan Energy Partners, L.P. nor Kinder Morgan, Inc. intend to make further restricted stock awards to senior management before that date. The 2001 awards were granted in 2002 and relate to performance in 2001. Value for 2001 grants computed as the number of shares awarded (10,000) times the closing price on date of grant ($56.99 at January 16, 2002). Twenty-five percent of the shares in each grant vest on each of the first four anniversaries after the date of grant. The holders of the restricted stock awards are eligible to vote and to receive dividends declared on such shares.
  

3

For 2003 and 2002, amounts represent contributions to the Kinder Morgan Savings Plan (a 401(k) plan), value of group-term life insurance exceeding $50,000 and taxable parking subsidy. For 2001, amounts represent contributions to the Kinder Morgan Savings Plan, value of group-term life insurance exceeding $50,000, parking subsidy and a $50 cash payment. Ms. Macdonald's amounts include additions in 2001 resulting from relocation expenses.
  

4 The 100,000 options to purchase Kinder Morgan, Inc. shares were granted on January 16, 2002 with an exercise price of $56.99 per share and vest at the rate of twenty-five percent on each of the first four anniversaries after the date of grant.
  
5 The 50,000 options to purchase Kinder Morgan, Inc. shares were granted on January 16, 2002 with an exercise price of $56.99 per share and vest at the rate of twenty-five percent on each of the first four anniversaries after the date of grant.

35


Kinder Morgan Savings Plan. Effective July 1, 1997, Kinder Morgan G.P., Inc. established the Kinder Morgan Retirement Savings Plan, a defined contribution 401(k) plan. This plan was subsequently amended and merged to form the Kinder Morgan Savings Plan. The plan now permits all full-time employees of Kinder Morgan, Inc. and KMGP Services Company, Inc. to contribute between one percent and fifty percent of base compensation, on a pre-tax basis, into participant accounts. In addition to a mandatory contribution equal to four percent of base compensation per year for most plan participants, Kinder Morgan G.P., Inc. may make discretionary contributions in years when specific performance objectives are met. Certain employees' contributions are based on collective bargaining agreements. The mandatory contributions are made each pay period on behalf of each eligible employee. Any discretionary contributions are made during the first quarter following the performance year. All employer contributions, including discretionary contributions, are in the form of Kinder Morgan, Inc. stock that is immediately convertible into other available investment vehicles at the employee's discretion. During the first quarter of 2004, we will not make any discretionary contributions to individual accounts for 2003. All contributions, together with earnings thereon, are immediately vested and not subject to forfeiture. Participants may direct the investment of their contributions into a variety of investments. Plan assets are held and distributed pursuant to a trust agreement. Because levels of future compensation, participant contributions and investment yields cannot be reliably predicted over the span of time contemplated by a plan of this nature, it is impractical to estimate the annual benefits payable at retirement to the individuals listed in the Summary Compensation Table above.

Common Unit Option Plan. Pursuant to Kinder Morgan Energy Partners, L.P.'s 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. Either the board of directors of Kinder Morgan G.P., Inc. or a committee of the board of directors of Kinder Morgan G.P., Inc. administers the option plan. The option plan terminates on March 5, 2008.

No individual employee may be granted options for more than 20,000 common units in any year. Kinder Morgan G.P., Inc.'s board of directors or the committee referred to in the prior paragraph will determine the duration and vesting of the options to employees at the time of grant. As of December 31, 2003, outstanding options to purchase 129,050 common units had been granted to 43 former Kinder Morgan G.P., Inc. employees who are now employees of Kinder Morgan, Inc. or KMGP Services Company, Inc. Forty percent of such options will vest on the first anniversary of the date of grant and twenty percent on each of the next three anniversaries. The options expire seven years from the date of grant.

The option plan also granted to each of Kinder Morgan G.P., Inc.'s then non-employee directors as of April 1, 1998, an option to purchase 10,000 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. In addition, each new non-employee director is granted options to acquire 10,000 common units on the first day of the month following his or her election. Under this provision, as of December 31, 2003, outstanding options to purchase 20,000 common units had been granted to two of Kinder Morgan G.P., Inc.'s three non-employee directors. Forty percent of all such options will vest on the first anniversary of the date of grant and twenty percent on each of the next three anniversaries. The non-employee director options will expire seven years from the date of grant.

No options to purchase common units were granted during 2003 to any of the individuals named in the Summary Compensation Table above. The following table sets forth certain information as of

36


December 31, 2003 with respect to common unit options previously granted to the individuals named in the Summary Compensation Table above. Mr. Listengart was the only person named in the Summary Compensation Table who was granted common unit options. No common unit options were granted at an option price below the fair market value on the date of grant.

Aggregated Common Unit Option Exercises in 2003
and 2003 Year-End Common Unit Option Values

Name Units Acquired
on Exercise
Value
Realized
Number of Units
Underlying Unexercised
Options at 2003 Year-End
Value of Unexercised
In-the-Money Options
at 2003 Year-End
1

Exercisable

Unexercisable

Exercisable

Unexercisable

Joseph Listengart

   -

   -

 10,000

     -

$ 319,888

$      -

  

  

  

1

Calculated on the basis of the fair market value of the underlying common units at year-end 2003, minus the exercise price.

Kinder Morgan, Inc. Option Plan.  Under Kinder Morgan, Inc.'s stock option plan, employees of Kinder Morgan, Inc. and its affiliates, including employees of Kinder Morgan, Inc.'s direct and indirect subsidiaries, like KMGP Services Company, Inc., are eligible to receive grants of options to acquire shares of common stock of Kinder Morgan, Inc. Kinder Morgan, Inc.'s board of directors administers this option plan. The primary purpose for granting stock options under this plan to employees of Kinder Morgan, Inc. and KMGP Services Company, Inc. is to provide them with an incentive to increase the value of common stock of Kinder Morgan, Inc. A secondary purpose of the grants is to provide compensation to those employees for services rendered to Kinder Morgan Energy Partners, L.P., its operating partnerships and subsidiaries. During 2003, none of the persons named in the Summary Compensation Table above were granted Kinder Morgan, Inc. stock options.

Aggregated Kinder Morgan, Inc. Stock Option Exercises in 2003
and 2003 Year-End Kinder Morgan, Inc. Stock Option Values

  

Number of Shares
Underlying Unexercised
Options at 2003 Year-End 

Value of Unexercised
In-the-Money Options
at 2003 Year-End
1

Name

Shares
Acquired
on Exercise

Value
Realized

Exercisable

Unexercisable

Exercisable

Unexercisable

Michael C. Morgan

140,000 

$4,242,350

197,500 

      - 

$5,572,406

$        -

C. Park Shaper

 30,000 

$  814,500

113,750 

106,250 

$2,473,188

$1,231,687

Deborah A. Macdonald

 50,000 

$1,194,249

62,500 

 37,500 

$1,790,750

$   79,125

Joseph Listengart

 26,250 

$  691,264

106,300 

      - 

$3,586,868

$        -

  

  

  

1

 Calculated on the basis of the fair market value of the underlying shares at year-end, minus the exercise price.

Cash Balance Retirement Plan.  Employees of KMGP Services Company, Inc. and Kinder Morgan, Inc. are eligible to participate in a Cash Balance Retirement Plan that was put into effect on January 1, 2001. 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 will accrue benefits through a personal retirement account in the Cash Balance Retirement Plan. Employees with prior service and not grandfathered converted to the Cash Balance Retirement Plan and were credited with the current fair value of any benefits they had previously accrued through the defined benefit plan. Under the plan, we make contributions on behalf of participating employees equal to three percent of eligible compensation every pay period. In addition, discretionary contributions are made to the plan based on the performance of Kinder Morgan, Inc. and Kinder Morgan Energy Partners, L.P. No additional contributions were made for 2003 performance.

37


Interest will be credited to the personal retirement accounts at the 30-year U.S. Treasury bond rate in effect each year. Employees will be 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 annual benefits payable as of December 31, 2003, under normal retirement at age sixty-five, assuming current remuneration levels without any salary projection, and participation until normal retirement at age sixty-five, with respect to the named executive officers under the provisions of the Kinder Morgan Cash Balance Retirement Plan. 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.

Name

Current Credited
Years
of Service

Estimated Credited Years of Service at Age 65

Age as of Jan. 1, 2004

Current Compensation Covered by
Plans

Estimated
Annual Benefit Payable Upon
Retirement
1

Richard D. Kinder

3

 8.8

59.2

$      1

$      -

Michael C. Morgan

3

32.7

35.4

 200,000

  62,537

C. Park Shaper

3

32.7

35.4

 200,000

  62,537

Joseph Listengart

3

32.5

35.6

 200,000

  61,780

Deborah A. Macdonald

3

15.9

52.1

 200,000

  15,823

  

  

  

1

 The estimated annual benefits payable are based on the straight-life annuity form.

Compensation Committee Interlocks and Insider Participation.   Kinder Morgan Management, LLC's compensation committee, comprised of Mr. Edward O. Gaylord, Mr. Gary L. Hultquist and Mr. Perry M. Waughtal, makes compensation decisions regarding our and Kinder Morgan G.P., Inc.'s executive officers. Mr. Richard D. Kinder and Mr. James E. Street, who are executive officers of Kinder Morgan Management, LLC, participate in the deliberations of our compensation committee concerning executive officer compensation. Mr. Kinder receives $1.00 annually in total compensation for services to Kinder Morgan, Inc., Kinder Morgan Energy Partners, L.P. and us.

Directors' fees.  During 2003, each of the three non-employee members of our and Kinder Morgan G.P., Inc.'s boards of directors received $10,000 in cash compensation with respect to board service for the first quarter of 2003. In addition, the director who served as chairman of our audit committee was paid an additional $2,500 for each quarter in 2003. In addition, directors are reimbursed for reasonable expenses in connection with board meetings. In April 2003, we implemented the Directors' Unit Appreciation Rights Plan, as discussed below, to serve as the sole compensation for non-employee directors for the remainder of 2003. In October 2003, we appointed Mr. Perry M. Waughtal as Lead Director, whose compensation is an additional $20,000 per year, paid $5000 per quarter, effective October 1, 2003.

Directors' Unit Appreciation Rights Plan.  On April 1, 2003, our compensation committee established the Directors' Unit Appreciation Rights Plan. Pursuant to this plan, each of our three non-employee directors is eligible to receive common unit appreciation rights. The primary purpose of this plan is to promote the interests of Kinder Morgan Energy Partners, L.P.'s unitholders by aligning the compensation of the non-employee members of our board of directors with unitholders' interests. Secondly, since our success is dependent on our operation and management of Kinder Morgan Energy Partners, L.P.'s business and resulting performance, the plan is expected to align the compensation of the non-employee members of the board with the interests of our shareholders.

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

38


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. Each unit appreciation right granted under the plan will be exercisable only for cash 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 expires without being exercised in the ten year period following the date of grant, the unit appreciation right will expire and not be exercisable at 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. The plan is administered by our compensation committee. The total number of unit appreciation rights authorized under the plan is 500,000. Our board has sole discretion to terminate the plan at any time with respect to unit appreciation rights which have not previously been granted to participants.

On April 1, 2003, the date of adoption of the plan, each of our three non-employee directors were granted 7,500 unit appreciation rights. In addition, 10,000 unit appreciation rights shall be granted to each of our three non-employee directors during the first meeting of the board each January. Accordingly, each non-employee director received an additional 10,000 unit appreciation rights on January 21, 2004. As of December 13, 2003, 52,500 unit appreciation rights had been granted. No unit appreciation rights were exercised during 2003.

Employment Agreement.  In April 2000, Mr. Michael C. Morgan entered into a four-year employment agreement with Kinder Morgan, Inc. and Kinder Morgan G.P., Inc. Under the employment agreement, Mr. Morgan receives an annual base salary of $200,000 and bonuses at the discretion of our compensation committee. Mr. Morgan is prevented from competing with Kinder Morgan, Inc. and Kinder Morgan Energy Partners, L.P. for a period of four years from the date of the agreement, provided Mr. Richard D. Kinder continues to serve as chief executive officer of Kinder Morgan, Inc. or its successor.

Retention Agreement.  Effective January 17, 2002, Kinder Morgan, Inc. entered into a retention agreement with Mr. C. Park Shaper, an officer of Kinder Morgan, Inc., Kinder Morgan G.P., Inc. and us. Pursuant to the terms of the agreement, Mr. Shaper obtained a $5 million personal loan guaranteed by Kinder Morgan, Inc. and Kinder Morgan Energy Partners, L.P. Mr. Shaper was required to purchase and did purchase Kinder Morgan, Inc. common stock and Kinder Morgan Energy Partners, L.P. common units in the open market with the loan proceeds. The Sarbanes-Oxley Act of 2002 does not allow companies to issue or guarantee new loans to executives, but it "grandfathers" loans that were in existence prior to the act. Regardless, Mr. Shaper and Kinder Morgan, Inc. agreed that in today's business environment it would be prudent for him to repay the loan. In conjunction with this decision, Mr. Shaper sold 37,000 Kinder Morgan, Inc. shares and 82,000 Kinder Morgan Energy Partners, L.P. common units. He used the proceeds to repay the $5 million personal loan guaranteed by Kinder Morgan, Inc. and Kinder Morgan Energy Partners, L.P., thereby eliminating Kinder Morgan, Inc.'s and Kinder Morgan Energy Partners, L.P.'s guarantee of this loan. Mr. Shaper instead participates in Kinder Morgan, Inc.'s restricted stock plan with other senior executives. The retention agreement was terminated accordingly.

Lines of Credit.  As of December 31, 2002, Kinder Morgan Energy Partners, L.P. had agreed to guarantee potential borrowings under lines of credit available from Wachovia Bank, National Association, formerly known as First Union National Bank, to Messrs. Thomas Bannigan, C. Park Shaper and James Street and Ms. Deborah Macdonald. Each of these officers was primarily liable for

39


any borrowing on his or her line of credit, and if Kinder Morgan Energy Partners, L.P. made any payment with respect to an outstanding loan, the officer on behalf of whom payment was made was required to surrender a percentage of his or her options to purchase Kinder Morgan, Inc. common stock. Kinder Morgan Energy Partners, L.P.'s obligations under the guaranties, on an individual basis, generally did not exceed $1.0 million and such obligations, in the aggregate, did not exceed $1.9 million. As of October 31, 2003, Kinder Morgan Energy Partners, L.P. had made no payments with respect to these lines of credit and each line of credit was either terminated or refinanced without a guarantee from Kinder Morgan Energy Partners, L.P. Kinder Morgan Energy Partners, L.P. has no further guaranteed obligations with respect to any borrowings by Kinder Morgan Energy Partners, L.P.'s officers.

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

The following table sets forth information as of January 31, 2004, regarding (a) the beneficial ownership of (i) Kinder Morgan Energy Partners, L.P.'s common and Class B units, (ii) our shares and (iii) the common stock of Kinder Morgan, Inc., the parent company of Kinder Morgan G.P., Inc., by all our directors and those of Kinder Morgan G.P., Inc., each of the named executive officers and all our directors and executive officers as a group and (b) the beneficial ownership of Kinder Morgan Energy Partners, L.P.'s common and Class B units or our shares by all persons known by us to own beneficially more than five percent of Kinder Morgan Energy Partners, L.P.'s common and Class B units or our shares. 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 Ownership1

   Kinder Morgan Energy Partners, L.P. Kinder Morgan
Management,
LLC Shares
Kinder Morgan, Inc.
Voting Stock
   Common Units Class B Units
      Number
     of Units
2
Percent
of Class
 Number
   of Units
3
Percent
of Class
 Number
   of Shares
4
Percent
of Class
  Number
    of Shares
5
Percent
of Class
Richard D. Kinder6

316,079

-

34,901  

*   

23,995,415

19.40%

Michael C. Morgan7

6,000

-

4,053  

*   

427,503

C. Park Shaper8

 4,000

-

2,368  

*   

301,002

Edward O. Gaylord

33,000

-

-  

-   

2,000

Gary L. Hultquist9

12,000

-

-  

-   

-

Perry M. Waughtal10

35,300

-

35,103  

*   

40,000

Joseph Listengart11

14,198

-

-  

-   

189,300

Deborah A. Macdonald12

-

-

-  

-   

195,568

Directors and Executive Officers
   as a group (13 persons)13

437,236

-

79,096  

*   

25,629,120

20.72%

Kinder Morgan, Inc.14

12,955,735

 9.62%

 5,313,400

100.00%

12,702,852  

25.93%  

-

Capital Group International,
   Inc.15

-

-

6,751,430  

13.78%  

-

OppenheimerFunds, Inc.16

-

-

4,433,727  

 9.05%  

-

  

*Less than 1%.

Except as noted otherwise, all units and Kinder Morgan, Inc. shares involve sole voting power and sole investment power. For Kinder Morgan Management, LLC, see note (4).
 

As of January 31, 2004, Kinder Morgan Energy Partners, L.P. had 134,735,758 common units issued and outstanding.
 

As of January 31, 2004, Kinder Morgan Energy Partners, L.P. had 5,313,400 Class B units issued and outstanding.
  

Represent the limited liability company shares of Kinder Morgan Management, LLC. As of January 31, 2004, there were 48,996,465 issued and outstanding Kinder Morgan Management, LLC shares. In all cases, Kinder Morgan Energy Partners, L.P.'s i-units will be voted in proportion to the affirmative and negative votes, abstentions and non-votes of owners of Kinder Morgan Management, LLC shares. Through the provisions in Kinder Morgan Energy Partners, L.P.'s partnership agreement and Kinder Morgan Management, LLC's limited liability company

40


  
agreement, the number of outstanding Kinder Morgan Management, LLC shares, including voting shares owned by Kinder Morgan G.P., Inc., and the number of Kinder Morgan Energy Partners, L.P.'s i-units will at all times be equal.
  

As of January 31, 2004, Kinder Morgan, Inc. had a total of 123,711,341 shares of issued and outstanding voting common stock, which excludes 8,892,884 shares held in treasury.
  

Includes (a) 7,979 common units owned by Mr. Kinder's spouse, (b) 5,173 Kinder Morgan, Inc. shares held by Mr. Kinder's spouse and (c) 250 Kinder Morgan, Inc. shares held by Mr. Kinder in a custodial account for his nephew. Mr. Kinder disclaims any and all beneficial or pecuniary interest in these units and shares.
  
Includes options to purchase 197,500 Kinder Morgan, Inc. shares exercisable within 60 days of January 31, 2004, and includes 107,500 shares of restricted Kinder Morgan, Inc. stock.
  
Includes options to purchase 170,000 Kinder Morgan, Inc. shares exercisable within 60 days of January 31, 2004, and includes 117,500 shares of restricted Kinder Morgan, Inc. stock.
  
Includes options to purchase 10,000 common units exercisable within 60 days of January 31, 2004.
  
10  Includes options to purchase 8,000 common units exercisable within 60 days of January 31, 2004.
  
11  Includes options to purchase 10,000 common units and 106,300 Kinder Morgan, Inc. shares exercisable within 60 days of January 31, 2004, and includes 77,500 shares of restricted Kinder Morgan, Inc. stock.
  
12  Includes options to purchase 75,000 Kinder Morgan, Inc. shares exercisable within 60 days of January 31, 2004, and includes 107,500 shares of restricted Kinder Morgan, Inc. stock.
  
13  Includes options to purchase 32,000 common units and 815,425 Kinder Morgan, Inc. shares exercisable within 60 days of January 31, 2004, and includes 597,800 shares of restricted Kinder Morgan, Inc. stock.
  
14  Includes common units owned by Kinder Morgan, Inc. and its consolidated subsidiaries, including 1,724,000 common units owned by Kinder Morgan G.P., Inc.
  
15  As reported on the Schedule 13G/A filed February 13, 2004 by Capital Group International, Inc. and Capital Guardian Trust Company. Capital Group International, Inc. and Capital Guardian Trust Company report that in regard to Kinder Morgan Management, LLC shares, they have sole voting power over 5,144,620 shares, shared voting power over 0 shares, sole disposition power over 6,751,430 shares and shared disposition power over 0 shares. Capital Group International, Inc.'s and Capital Guardian Trust Company's address is 11100 Santa Monica Blvd., Los Angeles, California 90025.
  
16  As reported on the Schedule 13G filed February 11, 2004 by OppenheimerFunds, Inc. and Oppenheimer Capital Income Fund. OppenheimerFunds, Inc. reports that in regard to Kinder Morgan Management, LLC shares, it has sole voting power over 0 shares, shared voting power over 0 shares, sole disposition power over 0 shares and shared disposition power over 4,433,727 shares. Of these 4,433,727 Kinder Morgan Management, LLC shares, Oppenheimer Capital Income Fund has sole voting power over 2,742,501 shares, shared voting power over 0 shares, sole disposition power over 0 shares and shared disposition power over 2,742,501 shares. OppenheimerFunds, Inc.'s address is 225 Liberty Street, 11th Floor, New York, New York 10281, and Oppenheimer Capital Income Fund's address is 6803 Tucson Way, Centennial, Colorado 80112.

 

41


Equity Compensation Plan Information

The following table sets forth information regarding Kinder Morgan Energy Partners, L.P.'s equity compensation plans as of January 31, 2004. Specifically, the table refers to information regarding Kinder Morgan Energy Partners, L.P.'s Common Unit Option Plan described in Item 11 "Executive Compensation" as of January 31, 2004.

Plan category

Number of securities to be issued upon exercise
of outstanding options, warrants and rights

Weighted average exercise price
of outstanding options, warrants and rights

Number of securities
remaining available for
future issuance under equity compensation plans
(excluding securities reflected in column (a))

(a)

(b)

(c)

Equity compensation plans
  approved by security holders

      -

      -

     -

  
Equity compensation plans not
  approved by security holders

149,050

$ 17.88

 55,400

  
Total

149,050

 55,400

=======

=======

For information about Kinder Morgan Energy Partners, L.P.'s Common Unit Option Plan, see Item 11 "Executive Compensation - Common Unit Option Plan."

Item 13.  Certain Relationships and Related Transactions.

General and Administrative Expenses

KMGP Services Company, Inc., a subsidiary of Kinder Morgan G.P., Inc., provides employees and Kinder Morgan Services LLC, our wholly owned subsidiary, provides centralized payroll and employee benefits services to us, Kinder Morgan G.P., Inc., Kinder Morgan Energy Partners, L.P. and Kinder Morgan Energy Partners, L.P.'s operating partnerships and subsidiaries (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 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 Kinder Morgan, Inc., 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 its limited partnership agreement, Kinder Morgan Energy Partners, L.P. provides reimbursement for its share of these administrative costs and such reimbursements will be accounted for as described above. Additionally, Kinder Morgan Energy Partners, L.P. reimburses us with respect to costs incurred or allocated to us in accordance with Kinder Morgan Energy Partners, L.P.'s limited partnership agreement, the delegation of control agreement among Kinder Morgan G.P., Inc., Kinder Morgan Energy Partners, L.P., us and others, and our limited liability company agreement.

Our named executive officers and other employees that provide management or services to both Kinder Morgan, Inc. and the Group are employed by Kinder Morgan, Inc. Additionally, other Kinder Morgan,

42


Inc. employees assist in the operation of Kinder Morgan Energy Partners, L.P.'s Natural Gas Pipeline assets. These Kinder Morgan, Inc. employees' expenses are allocated without a profit component between Kinder Morgan, Inc. and the appropriate members of the Group.

Kinder Morgan Energy Partners, L.P. Distributions

Kinder Morgan G.P., Inc.

Kinder Morgan G.P., Inc. serves as the sole general partner of Kinder Morgan Energy Partners, L.P. Pursuant to their partnership agreements, Kinder Morgan G.P., Inc.'s general partner interests represent a 1% ownership interest in Kinder Morgan Energy Partners, L.P., and a direct 1.0101% ownership interest in each of Kinder Morgan Energy Partners, L.P.'s five operating partnerships. Collectively, Kinder Morgan G.P., Inc. owns an effective 2% interest in the operating partnerships, without reference to incentive distributions paid under Kinder Morgan Energy Partners, L.P.'s partnership agreement:

its 1.0101% direct general partner ownership interest (accounted for as minority interest in the consolidated financial statements of Kinder Morgan Energy Partners, L.P.); and

  

its 0.9899% ownership interest indirectly owned via its 1% ownership interest in Kinder Morgan Energy Partners, L.P.

In addition, at December 31, 2003, Kinder Morgan G.P., Inc. owned 1,724,000 common units, representing approximately 0.91% of Kinder Morgan Energy Partners, L.P.'s outstanding limited partner units. Kinder Morgan Energy Partners, L.P.'s agreement requires that it distribute 100% of "Available Cash" (as defined in the partnership agreement) to its 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 Kinder Morgan Energy Partners, L.P.'s cash receipts less cash disbursements and net additions to or reductions in reserves (including any reserves required under debt instruments for future principal and interest payments) and amounts payable to the former general partner of SFPP, L.P. in respect of its remaining 0.5% special limited partner interest in SFPP, L.P.

Kinder Morgan G.P., Inc. is granted discretion by Kinder Morgan Energy Partners, L.P.'s partnership agreement, which discretion has been delegated to us, subject to the approval of Kinder Morgan G.P., Inc. 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 we determine Kinder Morgan Energy Partners, L.P.'s quarterly distributions, we consider current and expected reserve needs along with current and expected cash flows to identify the appropriate sustainable distribution level.

Typically, Kinder Morgan G.P., Inc. and owners of Kinder Morgan Energy Partners, L.P.'s common units and Class B units receive distributions in cash, while we, the sole owner of Kinder Morgan Energy Partners, L.P.'s i-units, receive distributions in additional i-units or fractions of i-units. For each outstanding i-unit, a fraction of an i-unit will be issued. The fraction is calculated by dividing the amount of cash being distributed per common unit by the average market price of our shares over the ten consecutive trading days preceding the date on which the shares begin to trade ex-dividend under the rules of the New York Stock Exchange. The cash equivalent of distributions of i-units will be treated as if it had actually been distributed, including for purposes of determining the distributions to Kinder Morgan G.P., Inc. and calculating Available Cash for future periods. Kinder Morgan Energy Partners, L.P. will not distribute the related cash but will retain the cash and use the cash in its business.

43


Available Cash is initially distributed 98% to Kinder Morgan Energy Partners, L.P.'s limited partners and 2% to Kinder Morgan G.P., Inc. These distribution percentages are modified to provide for incentive distributions to be paid to Kinder Morgan G.P., Inc. in the event that quarterly distributions to unitholders exceed certain specified targets.

Available Cash for each quarter is distributed as follows;

first, 98% to the owners of all classes of units pro rata and 2% to Kinder Morgan G.P., Inc. 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 Kinder Morgan G.P., Inc. 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 Kinder Morgan G.P., Inc. 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 us, as the owner of i-units, in the equivalent number of i-units, and 50% to Kinder Morgan G.P., Inc. in cash.

Incentive distributions are generally defined as all cash distributions paid to Kinder Morgan G.P., Inc. that are in excess of 2% of the aggregate amount of cash being distributed. Kinder Morgan G.P., Inc.'s declared incentive distributions for the years ended December 31, 2003 and 2002 were $322.8 million and $267.4 million, respectively.

Kinder Morgan, Inc.

Kinder Morgan, Inc., through its subsidiary Kinder Morgan (Delaware), Inc., remains the sole stockholder of Kinder Morgan G.P., Inc. At December 31, 2003, Kinder Morgan, Inc. directly owned 8,838,095 common units and 5,313,400 Class B units, indirectly owned 4,117,640 common units owned by its consolidated affiliates, including Kinder Morgan G.P., Inc., and owned 14,531,495 of our shares, representing an indirect ownership interest of 14,531,495 Kinder Morgan Energy Partners, L.P.'s i-units. These units represent approximately 17.4% of Kinder Morgan Energy Partners, L.P.'s outstanding limited partner units.

Kinder Morgan Management, LLC

We, as Kinder Morgan G.P., Inc.'s delegate, are the sole owner of Kinder Morgan Energy Partners, L.P.'s 48,996,465 i-units.

Operations

Kinder Morgan, Inc. or its subsidiaries operate and maintain for Kinder Morgan Energy Partners, L.P. the assets comprising Kinder Morgan Energy Partners, L.P.'s Natural Gas Pipelines business segment. Natural Gas Pipeline Company of America, a subsidiary of Kinder Morgan, Inc., operates Trailblazer Pipeline Company's assets under a long-term contract pursuant to which Trailblazer Pipeline Company incurs the costs and expenses related to Natural Gas Pipeline Company of America's operating and maintaining the assets. Trailblazer Pipeline Company provides the funds for capital expenditures.

44


Natural Gas Pipeline Company of America does not profit from or suffer loss related to its operation of Trailblazer Pipeline Company's assets.

The remaining assets comprising Kinder Morgan Energy Partners, L.P.'s Natural Gas Pipelines business segment are operated under agreements between Kinder Morgan, Inc. and Kinder Morgan Energy Partners, L.P. The agreements have five-year terms and contain automatic five-year extensions. Pursuant to the applicable underlying agreements, Kinder Morgan Energy Partners, L.P. pays Kinder Morgan, Inc. 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 Kinder Morgan, Inc. for corporate general and administrative costs, including amounts related to Trailblazer Pipeline Company, were $8.7 million of fixed costs and $10.8 million of actual costs incurred for 2003, and $13.3 million of fixed costs and $2.8 million of actual costs incurred for 2002. Commencing in 2003, Kinder Morgan, Inc. operated additional pipeline assets, including Kinder Morgan Energy Partners, L.P.'s North System and Cypress Pipeline, which are part of Kinder Morgan Energy Partners, L.P.'s Products Pipelines business segment, as well as Kinder Morgan Energy Partners, L.P.'s Monterrey Pipeline, which is part of Kinder Morgan Energy Partners, L.P.'s Natural Gas Pipelines business segment. Kinder Morgan Energy Partners, L.P. estimates the total reimbursement to be paid to Kinder Morgan, Inc. in respect of all pipeline assets operated by Kinder Morgan, Inc. and its subsidiaries for Kinder Morgan Energy Partners, L.P. for 2004 will be approximately $19.8 million, which includes $8.7 million of fixed costs (adjusted for inflation) and $11.1 million of actual costs. Kinder Morgan Energy Partners, L.P. believes the amounts paid to Kinder Morgan, Inc. 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 have exactly matched the actual time and overhead spent. Kinder Morgan Energy Partners, L.P. believes the agreed-upon amounts were, at the time the contracts were entered into, a reasonable estimate of the corporate general and administrative expenses to be incurred by Kinder Morgan, Inc. and its subsidiaries in performing such services. Kinder Morgan Energy Partners, L.P. also reimburses Kinder Morgan, Inc. and its subsidiaries for operating and maintenance costs and capital expenditures incurred with respect to these assets.

Other

We make all decisions relating to the management and control of Kinder Morgan Energy Partners, L.P.'s business and activities, subject to Kinder Morgan G.P., Inc.'s right to approve certain matters. Kinder Morgan G.P., Inc. owns all of our voting securities. Kinder Morgan, Inc., through its wholly owned and controlled subsidiary Kinder Morgan (Delaware), Inc., owns all the common stock of Kinder Morgan G.P., Inc. Certain conflicts of interest could arise as a result of the relationships among Kinder Morgan Energy Partners, L.P., Kinder Morgan G.P., Inc., Kinder Morgan, Inc. and us. The directors and officers of Kinder Morgan, Inc. have fiduciary duties to manage Kinder Morgan, Inc., including selection and management of its investments in its subsidiaries and affiliates, in a manner beneficial to the shareholders of Kinder Morgan, Inc. In general, we have a fiduciary duty to manage Kinder Morgan Energy Partners, L.P. in a manner beneficial to the unitholders. The partnership agreements for Kinder Morgan Energy Partners, L.P. and its operating partnerships contain provisions that allow us to take into account the interests of parties in addition to Kinder Morgan Energy Partners, L.P. in resolving conflicts of interest, thereby limiting our fiduciary duty to Kinder Morgan Energy Partners, L.P. unitholders, as well as provisions that may restrict the remedies available to 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 us, the resolution of a conflict by us will not be a breach of any duties. The duty of the directors and officers of Kinder Morgan, Inc. to the shareholders of Kinder Morgan, Inc. may, therefore, come into conflict with our duties and the duties of our directors and officers to Kinder Morgan Energy Partners, L.P. unitholders. The Conflicts and Audit Committee of our board of directors will, at our request, review (and is one of the means for resolving) conflicts of interest that may arise

45


between Kinder Morgan, Inc. or its subsidiaries, on the one hand, and Kinder Morgan Energy Partners, L.P., on the other hand.

Item 14. Principal Accounting Fees and Services.

The following sets forth fees billed for the audit and other services provided by PricewaterhouseCoopers LLP to us for the fiscal years ended December 31, 2003, and December 31, 2002:

Year Ended December 31,

2003

2002

(In dollars)
Audit fees1

$   72,667

$  225,627

Tax fees2

         -

    37,500

  Total

$   72,667

$  263,127

==========

==========

  
1 Includes fees for audit of annual financial statements and reviews of the related quarterly financial statements.
2 Includes fees related to professional services for tax compliance, tax advice and tax planning, consisting of tax services relating to the review or preparation of federal, state, local or foreign income or other tax returns.

All services rendered by PricewaterhouseCoopers LLP are permissible under applicable laws and regulations, and are pre-approved by our audit committee. Pursuant to the charter of our audit committee, the committee's primary purposes include the following:

to select, appoint, engage, oversee, retain, evaluate and terminate our external auditors;
  
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
  
to establish the fees and other compensation to be paid to our external auditors.

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):

the auditors' internal quality-control procedures;
  
any material issues raised by the most recent internal quality-control review, or peer review, of the external auditors;
  
the independence of the external auditors; and
  
the aggregate fees billed by our external auditors for each of the previous two fiscal years.

46


PART IV

Item 15.  Exhibits, Financial Statement Schedules and Reports on Form 8-K.

(a) 1.

  Financial Statements

Reference is made to the index of financial statements and supplementary data under Item 8 in Part II.

2.

  Financial Statement Schedules

The financial statements of Kinder Morgan Energy Partners, L.P., an equity method investee of the Registrant, are incorporated herein by reference from pages 91 through 162 of Kinder Morgan Energy Partners, L.P.'s Annual Report on Form 10-K for the year ended December 31, 2003.

KINDER MORGAN MANAGEMENT, LLC AND SUBSIDIARY

SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS

We have no valuation or qualifying accounts subject to disclosure in Schedule II.

3.

  Exhibits
  

Exhibit 
Number

Description

 3.1 Form of Certificate of Formation of the Company (filed as Exhibit 3.1 to the Company's Registration Statement on Form S-1 (Registration No. 333-55868) and incorporated by reference herein).
 3.2 Second Amended and Restated Limited Liability Company Agreement of the Company (filed as Exhibit 4.2 to the Company's Registration Statement on Form 8-A/A filed on July 24, 2002 and incorporated by reference herein).
 4.1 Form of certificate representing shares of the Company (filed as Exhibit 4.3 to the Company's Registration Statement on Form 8-A/A filed on July 24, 2002 and incorporated by reference herein).
 4.2 Form of Purchase Provisions between the Company and Kinder Morgan, Inc. (included as Annex B to the Second Amended and Restated Limited Liability Company Agreement filed as Exhibit 4.2 to the Company's Registration Statement on Form 8-A/A filed on July 24, 2002 and incorporated by reference herein).
 4.3 Registration Rights Agreement dated May 18, 2001 among the Company, Kinder Morgan Energy Partners, L.P. and Kinder Morgan, Inc. (Exhibit 4.3 to the Company's Annual Report on Form 10-K for the year ended December 31, 2002)
10.1 Form of Tax Indemnity Agreement between the Company and Kinder Morgan, Inc. (filed as Exhibit 10.1 to the Company's Registration Statement on Form S-1 (Registration No. 333-55868) and incorporated by reference herein).
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. June 30, 2001 Form 10-Q (Commission File No. 1-11234)).
10.3 Retention Agreement dated January 16, 2002, by and between Kinder Morgan, Inc. and C. Park Shaper (filed as Exhibit 10(l) to Kinder Morgan, Inc.'s 2001 Annual Report on Form 10-K (Commission File No. 1-6446)).

  21.1*

List of Subsidiaries.

  23.1*

Consent of Independent Accountants.

  31.1*

Section 13a-14(a)/15d-14(a) Certification of Chief Executive Officer

  

47


  
  31.2*
    
  32.1*
  32.2*
Section 13a-14(a)/15d-14(a) Certification of Chief 
  Financial Officer
Section 1350 Certification of Chief Executive Officer
Section 1350 Certification of Chief Financial Officer
    
  
* Filed herewith.
  

(b)    

Reports on Form 8-K
  
  

(1)

Current Report on Form 8-K dated October 21, 2003 was furnished on October 21, 2003 pursuant to Item 9 of that form.

  

  

We announced (i) that representatives of us, Kinder Morgan Energy Partners, L.P. and Kinder Morgan, Inc. intended to discuss and answer questions relating to Kinder Morgan Energy Partners, L.P.'s CO2 business in a live webcast on that date and (ii) the ability of interested parties to access the audio webcast, both live and on-demand.

  
  

(2)

Current Report on Form 8-K dated December 8, 2003 was furnished on December 8, 2003 pursuant to Item 9 of that form.

  

  

We announced (i) that representatives of us, Kinder Morgan Energy Partners, L.P. and Kinder Morgan, Inc. intended to make presentations on December 9, 2003, at the Wachovia Securities Pipeline Conference to discuss the financials, business plans and objectives of us, Kinder Morgan Energy Partners, L.P. and Kinder Morgan, Inc. and (ii) the availability of materials to be presented at the conference on our website.

  
  

(3)

Current Report on Form 8-K dated January 22, 2004 was furnished on January 23, 2004 pursuant to Item 9 of that form.

  

  

We announced (i) that representatives of us, Kinder Morgan Energy Partners, L.P. and Kinder Morgan, Inc. intended to make presentations on January 23, 2004, at the Kinder Morgan Analyst Conference to address the fiscal year 2003 results, the fiscal year 2004 outlook and other business information about us, Kinder Morgan Energy Partners, L.P. and Kinder Morgan, Inc., (ii) the availability of materials to be presented at the conference on our website and (iii) the ability of interested parties to access the audio webcast, both live and on-demand.

  

48


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 MANAGEMENT, LLC
(Registrant)
By /s/ C. PARK SHAPER
C. Park Shaper
Vice President and Chief Financial Officer
Date: March 5, 2004

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities set forth below and as of the date set forth above.

/s/ RICHARD D. KINDER    Director, Chairman and Chief Executive Officer
Richard D. Kinder   (Principal Executive Officer)
  
/s/ EDWARD O. GAYLORD Director
Edward O. Gaylord
  
/s/ GARY L. HULTQUIST Director
Gary L. Hultquist
  
/s/ C. PARK SHAPER Director, Vice President and Chief Financial Officer
C. Park Shaper   (Principal Financial and Accounting Officer)
  
/s/ PERRY M. WAUGHTAL Director
Perry M. Waughtal
  

  49



Annex A

                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, 2003

                                       Or

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

                        For the transition period from to

                         Commission file number: 1-11234

                       Kinder Morgan Energy Partners, L.P.
             (Exact name of registrant as specified in its charter)

                          Delaware                     76-0380342
              (State or other jurisdiction of        (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 whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]

   Indicate by check mark 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 an accelerated filer (as
defined by Rule 12b-2 of the Securities Exchange Act of 1934).  Yes [X]    No [ ]

   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 30, 2003 was
approximately $4,577,450,989. This figure assumes that only the general partner
of the registrant, Kinder Morgan, Inc., Kinder Morgan Management, LLC, their
subsidiaries and their officers and directors were affiliates. As of January 31,
2004, the registrant had 134,735,758 Common Units outstanding.


                                       1
<PAGE>


                       KINDER MORGAN ENERGY PARTNERS, L.P.

                                TABLE OF CONTENTS
                              Page
                                                                        Number
                    PART I
    Items  1 and 2. Business and Properties............................    3
                    Overview...........................................     3
                    General Development of Business....................    3
                    Business Strategy..................................    4
                    Recent Developments................................    7
                    Financial Information about Segments...............   11
                    Narrative Description of Business..................   11
                    Products Pipelines.................................   11
                    Natural Gas Pipelines..............................   23
                    CO2................................................    28
                    Terminals..........................................    30
                    Major Customers....................................   34
                    Regulation.........................................    34
                    Environmental Matters..............................   37
                    Risk Factors.......................................   40
                    Other..............................................    44
                    Financial Information about Geographic Areas.......   44
                    Available Information..............................   44
    Item 3.         Legal Proceedings..................................   45
    Item 4.         Submission of Matters to a Vote of Security Holders   45

                    PART II
    Item 5.         Market for   Registrant's  Common Equity and Related   46
                    Stockholder Matters................................
    Item 6.         Selected Financial Data............................   47
    Item 7.         Management's   Discussion  and Analysis of Financial
                    Condition and Results of Operations................   49
                    Critical Accounting Policies and Estimates.........   49
                    Results of Operations..............................   50
                    Liquidity and Capital Resources....................   61
                    New Accounting Pronouncements......................   70
                    Information Regarding Forward-Looking Statements...   70
    Item 7A.        Quantitative   and  Qualitative   Disclosures  About
                    Market Risk........................................   71
                    Energy Financial Instruments.......................   71
                    Interest Rate Risk.................................   73
    Item 8.         Financial Statements and Supplementary Data........   74
    Item 9.         Changes in and   Disagreements  with  Accountants on
                    Accounting and Financial Disclosure................   74
    Item 9A.        Controls and Procedures............................   74

                    PART III
    Item 10.        Directors and Executive Officers of the Registrant.   75
                    Directors   and  Executive  Officers  of our General   75
                    Partner and the Delegate...........................
                    Corporate Governance...............................   77
                    Section   16(a)   Beneficial   Ownership   Reporting    79
                    Compliance.........................................
    Item 11.        Executive Compensation.............................   79
    Item 12.        Security   Ownership  of Certain  Beneficial  Owners
                    and Management.....................................   83
    Item 13.        Certain Relationships and Related Transactions.....   85
    Item 14.        Principal Accounting Fees and Services.............   86

                    PART IV
    Item 15.        Exhibits, Financial Statement Schedules, and
                       Reports on Form 8-K.............................   88
                    Index to Financial Statements......................   91
    Signatures.........................................................   164

                                       2
<PAGE>


                                     PART I

Items 1 and 2.  Business and Properties.

Overview

   Kinder Morgan Energy Partners, L.P., a Delaware limited partnership, is a
publicly traded limited partnership that was formed in August 1992. We are the
largest publicly-traded pipeline limited partnership in the United States in
terms of market capitalization and we own the largest independent refined
petroleum products pipeline system in the United States in terms of volumes
delivered. Unless the context requires otherwise, references to "we," "us,"
"our," "KMP" or the "Partnership" are intended to mean Kinder Morgan Energy
Partners, L.P., our operating limited partnerships and their subsidiaries.

   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. Our common units trade on the New York Stock Exchange under the symbol
"KMP." In addition, you should read the following discussion and analysis in
conjunction with our Consolidated Financial Statements included elsewhere in
this report.

(a) General Development of Business

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

   o transporting, storing and processing refined petroleum products;

   o transporting, storing and selling natural gas;

   o producing, transporting and selling carbon dioxide for use in, and selling
     crude oil produced from, enhanced oil recovery operations; and

   o transloading, storing and delivering a wide variety of bulk, petroleum and
     petrochemical products at terminal facilities located across the United
     States.

   We focus on providing fee-based services to customers, generally avoiding
commodity price risks and taking advantage of the tax benefits of a limited
partnership structure. The portfolio of businesses we own or operate are grouped
into four reportable business segments according to the services we provide and
how our management makes decisions about allocating resources and measuring
financial performance. These segments are as follows:

   o Products Pipelines: Delivers more than two million barrels per day of
     gasoline, diesel fuel, jet fuel and natural gas liquids to various markets
     on over 10,000 miles of products pipelines and 39 associated terminals
     serving customers across the United States;

   o Natural Gas Pipelines: Transports, stores and sells up to 7.8 billion cubic
     feet per day of natural gas and has over 15,000 miles of natural gas
     transmission pipelines, plus natural gas gathering and storage facilities;

   o CO2: Produces, transports and markets carbon dioxide, commonly called CO2,
     has over 1,100 miles of pipelines that transport carbon dioxide to oil
     fields that use carbon dioxide to increase oil production in West Texas,
     including interests in two oil fields we operate and interests in four
     others, all of which are using or have used carbon dioxide injection
     operations; and

   o Terminals: Composed of approximately 52 owned or operated liquid and bulk
     terminal facilities and approximately 57 rail transloading facilities
     located throughout the United States, liquids terminal facilities
     possessing a liquids storage capacity of approximately 55 million barrels
     for refined petroleum products, chemicals and other liquid products, and
     bulk and transloading facilities handling nearly 60 million tons of coal,
     petroleum coke and other dry-bulk materials annually.

                                       3
<PAGE>

   In February 1997, Kinder Morgan (Delaware), Inc., a Delaware corporation,
acquired all of the issued and outstanding stock of our general partner, changed
the name of our general partner to Kinder Morgan, G.P., Inc., and changed our
name to Kinder Morgan Energy Partners, L.P. Since that time, our operations have
experienced significant growth, and our net income has increased from $17.7
million, for the year ended December 31, 1997, to $697.3 million, for the year
ended December 31, 2003.

   In October 1999, K N Energy, Inc., a Kansas corporation that provided
integrated energy services, acquired Kinder Morgan (Delaware), Inc. At the time
of the closing of this transaction, K N Energy, Inc. changed its name to Kinder
Morgan, Inc., referred to herein as KMI. In connection with the acquisition,
Richard D. Kinder, Chairman and Chief Executive Officer of our general partner
and its delegate (see below), became the Chairman and Chief Executive Officer of
KMI. KMI trades on the New York Stock Exchange under the symbol "KMI" and is one
of the largest energy transportation and storage companies in the United States,
operating, either for itself or on our behalf, more than 35,000 miles of natural
gas and products pipelines and approximately 80 terminals. As of December 31,
2003, KMI and its consolidated subsidiaries owned, through its general and
limited partner interests, an approximate 19.0% interest in us.

   In addition to the distributions it receives from its limited and general
partner interests, KMI also indirectly 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 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 2003 distribution level, KMI received approximately 51% of all quarterly
distributions from us, of which approximately 41% was attributable to its
general partner interest and 10% was attributable to its limited partner
interest. The actual level of distributions KMI will receive in the future will
vary with the level of distributions to the limited partners determined in
accordance with our partnership agreement.

   In February 2001, Kinder Morgan Management, LLC, a Delaware limited liability
company referred to herein as KMR, was formed. 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, 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.

   In May 2001, KMR issued 2,975,000 of its shares representing limited
liability company interests to KMI and 26,775,000 of its shares to the public in
an initial public offering. The shares trade on the New York Stock Exchange
under the symbol "KMR." KMR became a limited partner in us by using
substantially all of the net proceeds from that offering 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
i-units are entitled to vote on all matters on which the common units are
entitled to vote. In general, the 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 from interim capital
transactions to KMR in additional i-units rather than in cash. As of December
31, 2003, KMR, through its ownership of our i-units, owned approximately 25.9%
of all of our outstanding limited partner units. KMR shares and all classes of
our limited partner units were split two-for-one on August 31, 2001, and all
dollar and numerical references to such shares and units in this paragraph and
elsewhere in this report have been adjusted to reflect the effect of the split.

Business Strategy

   Our business strategy is substantially the same today as it was when our
current management began managing our business in early 1997. The objective of
our business strategy is to grow our portfolio of businesses by:


                                       4
<PAGE>

   o providing, for a fee, transportation, storage and handling services which
     are core to the energy infrastructure of growing markets;

   o increasing utilization of our assets while controlling costs by:

        o operating classic fixed-cost businesses with little variable costs;
          and

        o improving productivity to drop top-line growth to the bottom line;

   o leveraging economies of scale from incremental acquisitions and expansions
     principally by:

        o reducing needless overhead; and

        o eliminating duplicate costs in core operations; and

   o maximizing the benefits of our financial structure, which allows us to:

        o  minimize the taxation of net income, thereby increasing distributions
           from our high cash flow businesses; and

        o  maintain a strong balance sheet, thereby allowing flexibility when
           raising capital for acquisitions and/or expansions.

   Primarily, our business model consists of a solid asset base designed and
operated to generate stable, fee-based income and distributable cash flow that
together provides overall long-term value to our unitholders. We do not face
significant risks relating directly to movements in commodity prices for two
principal reasons. First, we primarily transport and/or handle products for a
fee and are not engaged in the unmatched purchase and resale of commodity
products. Second, in those areas of our business, primarily oil production in
our CO2 business segment, where we do face exposure to fluctuations in commodity
prices, we engage in a hedging program to mitigate this exposure.

   Generally, as utilization of our pipelines and terminals increases, our
fee-based revenues increase. Increases in utilization are principally driven by
increases in demand for gasoline, jet fuel, natural gas and other energy
products and bulk materials that we transport, store, or handle. Increases in
demand for these products and services are generally driven by demographic
growth in the markets we serve, including the rapidly growing western and
southeastern United States.

   The business strategies of our four business segments are as follows:

   o Products Pipelines. We plan to continue to expand our presence in the
     growing refined petroleum products markets in the western and southeastern
     United States through incremental expansions of pipelines and through
     strategic pipeline and terminal acquisitions that we believe will enhance
     our ability to serve our customers while increasing distributable cash
     flow. On systems serving relatively mature markets, such as our North
     System, we intend to focus on increasing product throughput by continuing
     to increase the range of products transported and services offered while
     remaining a reliable, cost-effective provider of transportation services;

   o Natural Gas Pipelines. We intend to grow our Texas intrastate natural gas
     transportation and storage businesses by identifying and serving
     significant new customers with demand for capacity on our pipeline systems
     and reducing volatility through long-term agreements. On our two Rocky
     Mountain natural gas pipeline systems, Kinder Morgan Interstate Gas
     Transmission LLC and Trailblazer Pipeline Company, our goals are to
     continue to operate our existing operations efficiently, to continue to
     meet our customers' needs and to capitalize on expansion and growth
     opportunities in expanding our role as a key player in moving natural gas
     out of the Rocky Mountain region. Red Cedar Gas Gathering Company, our
     partnership with the Southern Ute Indian Tribe, is pursuing additional
     gathering and processing opportunities on tribal lands. Overall, we will
     continue to explore expansion and storage opportunities to increase
     utilization levels throughout our natural gas pipeline operations;

                                       5
<PAGE>

   o CO2. Our carbon dioxide business has two primary strategies: (a) increase
     the utilization of our carbon dioxide supply and transportation assets by
     providing a full range of supply, transportation and technical support
     services to third party customers and (b) increase, for our own account,
     the economic benefits from our oil production activities by increasing oil
     field carbon dioxide flooding and efficiently managing oil field operating
     expenses. As a service provider, our strategy is to offer customers
     "one-stop shopping" for carbon dioxide supply, transportation and technical
     support service. In our production business, we plan to grow production
     from our interests in oil fields located in the Permian Basin of West Texas
     by increasing our use of carbon dioxide in enhanced oil recovery projects.
     Outside the Permian Basin, we intend to compete aggressively for new supply
     and transportation projects, including the acquisition of attractive carbon
     dioxide injection projects that would further increase the demand for our
     carbon dioxide reserves and utilization of our carbon dioxide supply and
     pipeline assets. Our management believes these projects will arise as other
     oil producing basins mature and make the transition from primary production
     to enhanced recovery methods; and

   o Terminals. We are dedicated to growing our terminals segment through a core
     strategy which includes dedicating capital to expand existing facilities,
     maintaining a strong commitment to operational safety and efficiency and
     growing through strategic acquisitions. The bulk terminals industry in the
     United States is highly fragmented, leading to opportunities for us to make
     selective, accretive acquisitions. In addition to efforts to expand and
     improve our existing terminals, we plan to design, construct and operate
     new facilities for current and prospective customers. Our management
     believes we can use newly acquired or developed facilities to leverage our
     operational expertise and customer relationships. In addition, we believe
     our experience and expertise in managing and operating our liquids and bulk
     terminals businesses in an integrated manner gives us a competitive
     advantage in pursuing acquisitions of terminals that handle both bulk and
     liquid materials.

   To accomplish our strategy, we will continue to rely on the following
three-pronged approach:

   o Cost Reductions. We have reduced the total operating, maintenance, general
     and administrative expenses of those operations that we owned at the time
     Kinder Morgan (Delaware), Inc. acquired our general partner in February
     1997. In addition, we have made similar reductions in the operating,
     maintenance, general and administrative expenses of many of the businesses
     and assets that we acquired or have assumed operations of since February
     1997. Generally, these reductions in expense have been achieved by
     eliminating duplicative functions that we and the acquired businesses each
     maintained prior to their combination. We intend to continue to seek
     further expense reductions throughout our businesses where appropriate;

   o Internal Growth. We intend to grow income from our current assets through
     (a) increased utilization and (b) internal expansion projects. We primarily
     operate classic fixed cost businesses with little variable costs. By
     controlling these variable costs, any increase in utilization of our
     pipelines and terminals generally results in an increase in income.
     Increases in utilization are principally driven by increases in demand for
     gasoline, jet fuel, natural gas and other energy products and bulk
     materials that we transport, store or handle. Increases in demand for these
     products are typically driven by demographic growth in markets we serve,
     including the rapidly growing western and southeastern United States. In
     addition, we have undertaken a number of expansion projects that our
     management believes will increase revenues from existing operations; and

   o Strategic Acquisitions. We regularly seek opportunities to make additional
     strategic acquisitions, to expand existing businesses and to enter into
     related businesses. We periodically consider potential acquisition
     opportunities, including those from KMI or its affiliates, as they are
     identified, but we cannot assure you that we will be able to consummate any
     such acquisition. 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. Our
     management anticipates that we will finance acquisitions by borrowings
     under our bank credit facilities or by issuing commercial paper, and
     subsequently reduce these short-term borrowings by issuing new long-term
     debt securities, common units and/or i-units to KMR. For more information
     on the costs and methods of financing for each of our 2003 acquisitions,
     see "Management's Discussion and Analysis of Financial Condition and
     Results of Operations - Liquidity and Capital Resources - Capital
     Requirements for Recent Transactions" included elsewhere in this report.

                                       6
<PAGE>

   Achieving success in implementing our strategy will partly depend on the
following characteristics of our management's philosophy:

   o Low cost asset operator and attention to detail. An important element of
     our strategy to improve unitholder value is controlling costs whenever
     possible. We believe that our overall cost and expense infrastructure has
     been improved by numerous simplification and transformation efforts. We
     continue to focus on improving employee and process productivity in order
     to create a more efficient expense structure while, at the same time, we
     insist on providing the highest level of expertise and uncompromising
     service to our customers. We have recognized for years the need to have an
     unwavering commitment to safety, and we employ full-time safety
     professionals to provide training and awareness through ongoing programs
     for every employee, especially those working with hazardous materials at
     our pipeline and terminal facilities;

   o Risk Management. We avoid businesses with direct commodity price exposure
     wherever possible, and we hedge incidental commodity price risk. In the
     normal course of business, we are exposed to risks associated with changes
     in the market price of energy products; however, we attempt to limit these
     risks by following established risk management policies and procedures,
     including the use of energy financial instruments, also known as
     derivatives. Our risk management process also includes identifying the
     areas in our operations where assets are at risk of loss and areas where
     exposures exist to third-party liabilities. Our management strives to
     recognize and insure against such risk; and

   o Alignment of incentives. Whenever possible, we align the compensation of
     our management and employees with the interests of our unitholders. Under
     KMI's stock option plan, all employees of KMI and its affiliates, including
     employees of KMI's direct and indirect subsidiaries who operate our
     businesses, are eligible to receive grants of options to acquire shares of
     KMI common stock. The primary purpose for granting stock options under this
     plan is to provide employees with an incentive to increase the value of
     common stock of KMI. The value of KMI's common stock increases primarily
     as a result of increases in distributions to our unitholders.   KMI's ten
     most senior executives (excluding Mr. Kinder, who receives $1 per year in
     salary) have their base salaries capped at $200,000, are not eligible for
     stock options, but instead are eligible to receive grants of KMI restricted
     stock. Additionally, all employees, including the most senior executives,
     are eligible for annual bonuses only when KMI and we meet annual earnings
     per share and distributions per unit targets.

Recent Developments

   During 2003, our assets increased 9% and our net income increased 15% from
2002 levels. In addition, distributions per unit increased 9% from $0.625 for
the fourth quarter of 2002 to $0.68 for the fourth quarter of 2003. The
following is a brief listing of significant developments since December 31,
2002. Additional information regarding most of these items is contained in the
rest of this report.

   o Effective January 1, 2003, we acquired long-term lease contracts from New
     York-based M.J. Rudolph Corporation to operate four bulk terminal
     facilities at major ports along the East Coast and in the southeastern
     United States. The acquisition also included the purchase of certain assets
     that provide stevedoring services at these locations. The aggregate cost of
     this acquisition was approximately $31.3 million. We paid $29.9 million of
     the acquisition cost on December 31, 2002 and the remaining $1.4 million in
     January 2003. The acquired operations serve various terminals located at
     the ports of New York and Baltimore, along the Delaware River in Camden,
     New Jersey, and in Tampa Bay, Florida. Combined, these facilities annually
     transload nearly four million tons of products such as fertilizer, iron ore
     and salt;

   o On March 25, 2003, we announced the start of service on our new $89
     million, 95-mile, 30-inch Mier-Monterrey natural gas pipeline that
     stretches from South Texas to Monterrey, Mexico, one of Mexico's fastest
     growing industrial areas. The new pipeline interconnects with the southern
     end of our Kinder Morgan Texas pipeline system in Starr County, Texas, and
     is designed to initially transport up to 375,000 dekatherms per day of
     natural gas. Additionally, we entered into a 15-year contract with Pemex
     Gas Y Petroquimica Basica, which subscribed for all of the capacity on the
     pipeline. The pipeline connects to a 1,000-megawatt power plant complex
     near Monterrey and to the PEMEX natural gas transportation system;


                                       7
<PAGE>

   o On May 2, 2003, we were notified by the staff of the Securities and
     Exchange Commission that the staff is conducting an informal investigation
     concerning our public disclosures regarding the allocation of purchase
     price between assets and goodwill in connection with our 2002 acquisition
     of the assets of Kinder Morgan Tejas. The staff has not asserted that we
     have acted improperly or illegally. Furthermore, the staff has indicated
     that the Commission has not issued a formal order. We have voluntarily
     agreed to cooperate fully with the staff's informal investigation. Even if
     adjustments were made to the allocation between assets and goodwill, any
     adjustments would not have an effect on cash available for distributions to
     our limited partners. The primary effect of any adjustments would be to
     either increase or decrease depreciation and amortization expense with a
     corresponding increase or decrease in net income. This difference arises
     because, in general, assets are required to be depreciated over time while
     goodwill is not;

   o On May 6, 2003, we completed construction and placed into service our new
     $28.5 million carbon dioxide Centerline pipeline. The Centerline pipeline
     originates near Denver City, Texas and transports carbon dioxide to the
     Snyder, Texas area. The pipeline consists of 113 miles of 16-inch pipe and
     primarily supplies the SACROC oil field unit in the Permian Basin of West
     Texas, but is also available for existing and prospective third-party
     carbon dioxide projects in the Horseshoe Atoll area of the Permian Basin;

   o Effective June 1, 2003, we acquired MKM Partners, L.P.'s 12.75% ownership
     interest in the SACROC oil field unit for $23.3 million and the assumption
     of $1.9 million of liabilities. The SACROC unit is one of the largest and
     oldest oil fields in the United States using carbon dioxide flooding
     technology. This transaction increased our ownership interest in the SACROC
     unit to approximately 97%;

   o On June 10, 2003, we announced that we had entered into a long-term natural
     gas transportation contract with Praxair, Inc. Under the 15-year agreement,
     we have agreed to supply Praxair with up to 90,000 dekatherms of natural
     gas per day from our Texas intrastate natural gas pipeline system. The gas
     will be used to supply Praxair's steam-methane reformers at two new
     hydrogen facilities located in Texas City, Texas, and Port Arthur, Texas.
     These new hydrogen facilities are scheduled to be in production in 2004;

   o On June 23, 2003, we completed a public offering of an additional 4,600,000
     of our common units, including 600,000 units issued upon exercise by the
     underwriters of an over-allotment option, at a price of $39.35 per unit,
     less commissions and underwriting expenses. We received net proceeds of
     $173.3 million for the issuance of these common units and we used the
     proceeds to reduce the borrowings under our commercial paper program;

   o On June 24, 2003, a non-binding, phase one initial decision was issued by
     an administrative law judge hearing a Federal Energy Regulatory Commission
     case on the rates charged by our Pacific operations' interstate portion of
     its pipelines. The Energy Policy Act of 1992 "grandfathered" most of our
     Pacific operations' interstate rates, deeming them lawful. However,
     pursuant to rate challenges made by certain shippers, the administrative
     law judge recommended that the FERC "ungrandfather" our Pacific operations'
     interstate rates. If these rates are "ungrandfathered," they could be
     lowered prospectively and complaining shippers could be entitled to
     reparations for prior periods. Initial decisions have no force or effect
     and must be reviewed by the FERC. Furthermore, the FERC is not obliged to
     follow any of the administrative law judge's findings and can accept or
     reject this initial decision in whole or in part. Ultimate resolution of
     phase one and phase two of this matter by the FERC is not expected before
     early 2005;

   o On July 30, 2003, we experienced a rupture on our Products Pipelines'
     Pacific operations' Tucson to Phoenix line that carries refined petroleum
     products from Tucson to Phoenix. Through a combination of increased
     deliveries on our Los Angeles to Phoenix line and terminal modifications at
     our Tucson terminal that allowed volumes of Phoenix-grade gasoline to be
     trucked into Phoenix, we were able to deliver most of the volumes into the
     Phoenix area which normally would have flowed through the ruptured line.
     The Tucson to Phoenix line resumed service on August 24, 2003. The impact
     of the rupture on our results of operations was not material;

   o On August 1, 2003, we received a favorable final order from the FERC
     approving the rate methodology for shippers on the expansion of our Pacific
     operations' East Line pipeline. In October 2002, we filed a petition


                                       8
<PAGE>

     requesting that the FERC address several issues regarding the determination
     of rates for our proposed $200million East Line expansion project. The East
     Line is comprised of two parallel pipelines originating in El Paso, Texas,
     extending to the west and connecting to our products terminal located in
     Tucson, Arizona. One line continues running northwest and connects to our
     products terminal located in Phoenix, Arizona. When completed, the
     expansion will increase capacity on our El Paso to Tucson pipeline by
     approximately 56% (53,000 barrels per day of refined petroleum products),
     and on our Tucson to Phoenix pipeline by approximately 80% (44,000 barrels
     per day of refined petroleum products). As part of this expansion project,
     replacement of approximately 12 miles of pipeline within the city of Tucson
     is underway and will be completed by mid-March 2004. The projected start-up
     for the remainder of the expansion is sometime in the fourth quarter of
     2005 or the first quarter of 2006;

   o Effective August 1, 2003, we acquired reversionary interests in the Red
     Cedar Gas Gathering Company held by the Southern Ute Indian Tribe. Our
     purchase price was $10.0 million. The 4% reversionary interests were
     scheduled to take effect September 1, 2004 and September 1, 2009. With the
     elimination of these reversions, our ownership interest in Red Cedar will
     remain at 49%;

   o On August 5, 2003, we announced the formation of a joint venture with
     Nicor, Inc. for the purpose of obtaining shipper commitments for the
     proposed Advantage Southern Pipeline project. The 392-mile pipeline would
     originate from the Cheyenne Hub, located in Weld County, Colorado, and
     terminate near Greensburg, Kansas, where it would interconnect with several
     major interstate pipeline systems. The pipeline would offer a competitive
     alternative to shippers at the Cheyenne Hub by providing additional access
     to natural gas produced in the Rocky Mountain region to meet growing demand
     in the Midwest. On August 29, 2003, we concluded an open season on the
     project, which gave interested shippers the opportunity to bid for firm
     capacity on the proposed natural gas pipeline. As of January 31, 2004, we
     were working with a number of shippers to remove contingencies, which would
     then allow this project to go forward;

   o Effective October 1, 2003, we acquired five refined petroleum products
     terminals in the western United States for approximately $20.0 million from
     Shell Oil Products U.S. In addition, as part of the transaction, Shell
     entered into a long-term contract to store refined petroleum products in
     the terminals. We plan to invest an additional $8.0 million in the
     facilities in the near term. The terminals are located in Colton and
     Mission Valley, California; Phoenix and Tucson, Arizona; and Reno, Nevada.
     Combined, the terminals have 28 storage tanks with total capacity of
     approximately 700,000 barrels for gasoline, diesel fuel and jet fuel. The
     terminals also feature automated truck-loading equipment and offer a
     variety of blending services;

   o On October 9, 2003, following approval from the Federal Energy Regulatory
     Commission, we announced the start of construction on our $30 million
     project that involves the construction of pipeline, compression and storage
     facilities to accommodate an additional six billion cubic feet of natural
     gas storage capacity at our Kinder Morgan Interstate Gas Transmission LLC's
     Cheyenne Market Center. This additional capacity has been fully subscribed
     under 10-year contracts. The Cheyenne Market Center offers firm natural gas
     storage capabilities that will allow the receipt, storage and subsequent
     re-delivery of natural gas supplies at applicable points located in the
     vicinity of the Cheyenne Hub in Weld County, Colorado and our Huntsman
     storage facility in Cheyenne County, Nebraska. The Cheyenne Market Center
     is expected to begin service during the summer of 2004;

   o Effective November 1, 2003, we acquired certain assets in the Permian Basin
     of West Texas from a subsidiary of Marathon Oil Corporation for $231.0
     million and the assumption of $28.0 million of liabilities. The assets
     acquired included Marathon's approximate 42.5% interest in the Yates oil
     field unit, Marathon's 100% interest in the crude oil gathering system
     surrounding the Yates field and Marathon's 100% interest in Marathon Carbon
     Dioxide Transportation Company. Marathon Carbon Dioxide Transportation
     Company owns a 65% ownership interest in the Pecos Carbon Dioxide Pipeline
     Company, which owns a 25-mile carbon dioxide pipeline. Adding the acquired
     interest in the Yates field to the 7.5% ownership interest we previously
     owned raised our working interest in the Yates field to nearly 50% and
     allows us to operate the field. One of the largest oil fields ever
     discovered in the United States, Yates originally held more than five
     billion barrels of oil, of which approximately 28% has been produced. This
     field is located approximately 90 miles south of Midland, Texas;

                                       9
<PAGE>

   o Effective November 1, 2003, we acquired the remaining approximate 32%
     ownership interest in MidTex Gas Storage Company, LLP from an affiliate of
     NiSource Inc. for $15.8 million and the assumption of $1.7 million of debt.
     We now own 100% of MidTex Gas Storage Company, LLP, a Texas limited
     liability partnership that owns two salt dome natural gas storage
     facilities located in Matagorda County, Texas;

   o On December 3, 2003, we announced that we had acquired a 172 mile segment
     of a 24-inch diameter Texas crude oil pipeline from Teppco Crude Pipeline,
     L.P. and expect to convert it from carrying crude oil to natural gas. We
     will spend approximately $30.0 million to acquire the intrastate pipeline,
     prepare it for natural gas transportation service and build an additional
     five mile pipeline lateral. Approximately $23.3 million of our total
     spending will be made to convert to natural gas service the 135 mile
     pipeline segment which extends from an intersection with our Kinder Morgan
     Texas Pipeline system just west of Katy, Texas to the west side of Austin,
     Texas. When completed, the pipeline will provide approximately 170
     dekatherms per day of natural gas to the Austin market. In addition, Austin
     Energy, Austin's city-owned electric utility, has entered into a long-term
     contract for firm transportation and storage services, primarily to provide
     gas supply to its Sand Hill power plant. Texas Gas Service, Austin's local
     natural gas distribution company, has also signed a long-term contract to
     support the project. We expect to begin gas service on the pipeline by the
     middle of 2004;

   o Effective December 11, 2003, we acquired seven refined petroleum products
     terminals in the southeastern United States from ConocoPhillips Company and
     Phillips Pipe Line Company. Our purchase price was approximately $15.1
     million, consisting of approximately $14.0 million in cash and $1.1 million
     in assumed liabilities. The terminals are located in Charlotte and Selma,
     North Carolina; Augusta and Spartanburg, South Carolina; Albany and
     Doraville, Georgia; and Birmingham, Alabama. We will fully own and operate
     all of these terminals except for the facility in Doraville, Georgia, where
     our ownership interest will be 30% and the facility will be operated by
     Citgo. Combined, the terminals have 35 storage tanks with total capacity of
     approximately 1.15 million barrels for gasoline, diesel fuel and jet fuel.
     The facilities feature automated truck-loading equipment and offer a
     variety of blending and additive-injection services. In addition, as part
     of the transaction, ConocoPhillips entered into a long-term contract to use
     the terminals;

   o On December 16, 2003, we announced that we expect to declare cash
     distributions of $2.84 per unit for 2004, an 8% increase over our cash
     distributions of $2.63 per unit for 2003. This expectation included
     contributions from assets owned by us as of the announcement data and did
     not include any projected benefits from unidentified acquisitions;

   o In December 2003, we completed the acquisition of two terminals in Tampa,
     Florida for an aggregate consideration of approximately $29.5 million,
     consisting of $26.0 million in cash and $3.5 million in assumed
     liabilities. The principal purchase was a marine terminal acquired from a
     subsidiary of IMC Global, Inc. We also entered into a long-term agreement
     with IMC to enable it to be the primary user of the facility, which we will
     operate and refer to as the Kinder Morgan Tampaplex terminal. We closed on
     this portion of the transaction on December 23, 2003. The terminal sits on
     a 114-acre site, and serves as a storage and receipt point for imported
     ammonia, as well as an export location for dry bulk products, including
     fertilizer and animal feed. The second facility includes assets from the
     former Nitram, Inc. bulk terminal, which we plan to use as an inland bulk
     storage warehouse facility for overflow cargoes from our Port Sutton import
     terminal, also located in Tampa. We closed on the Nitram portion of the
     transaction on December 10, 2003;

   o During 2003, we spent $577.0 million for additions to our property, plant
     and equipment, including both expansion and maintenance projects. Our
     capital expenditures included the following:

     o  $272.2 million in our CO2 segment, mostly related to additional
        infrastructure, including wells, injection and compression facilities,
        to support the expanding carbon dioxide flooding operations at the
        SACROC oil field unit;

     o  $108.4 million in our Terminals segment, mostly related to expansions at
        our liquid terminal facilities located in Carteret and Perth Amboy, New
        Jersey and Pasadena and Galena Park, Texas, as well as other smaller
        projects;

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<PAGE>

     o  $101.7 million in our Natural Gas Pipelines segment, mostly related to
        completing the construction and start up of our Mier-Monterrey Pipeline
        and to the expansion at the Cheyenne Market Center, both described
        above; and

     o  $94.7 million in our Products Pipelines segment, mostly related to
        infrastructure modifications at many of our California terminals so that
        our shippers can blend ethanol, expansions to our North System pipeline
        and a storage expansion project at our combined Carson/Los Angeles
        Harbor terminal system in the state of California;

   o On February 3, 2004, we announced that we had priced a public offering of
     5,300,000 of our common units at a price of $46.80 per unit, less
     commissions and underwriting expenses. We also granted to the underwriters
     an option to purchase up to 795,000 additional common units to cover
     over-allotments. On February 9, 2004, 5,300,000 common units were issued.
     We received net proceeds of $237.8 million for the issuance of these common
     units and we used the proceeds to reduce the borrowings under our
     commercial paper program; and

   o On February 4, 2004, we announced that we had reached an agreement with
     Exxon Mobil Corporation to purchase seven refined petroleum products
     terminals in the southeastern United States. The terminals are located in
     Collins, Mississippi, Knoxville, Tennessee, Charlotte and Greensboro North
     Carolina, and Richmond, Roanoke and Newington, Virginia. Combined, the
     terminals have a total storage capacity of approximately 3.2 million
     barrels for gasoline, diesel fuel and jet fuel. As part of the transaction,
     Exxon Mobil has entered into a long-term contract to store products in the
     terminals. The acquisition enhances our terminal operations in the
     Southeast and complements our December 2003 acquisition of seven products
     terminals from ConocoPhillips Company and Phillips Pipe Line Company. The
     acquired operations will be included as part of our Products Pipelines
     business segment.


(b) Financial Information about Segments

   For financial information on our four reportable business segments, see Note
15 to our Consolidated Financial Statements.

(c) Narrative Description of Business

Products Pipelines

   Our Products Pipelines segment consists of refined petroleum products and
natural gas liquids pipelines, related terminals and transmix processing
facilities, including:

   o our Pacific operations, which include interstate common carrier pipelines
     regulated by the Federal Energy Regulatory Commission, intrastate pipelines
     in California regulated by the California Public Utilities Commission and
     certain non rate-regulated operations and terminal facilities.
     Specifically, our Pacific operations include:

        o  our SFPP, L.P. operations, comprised of approximately 2,800 miles of
           pipelines that transport refined petroleum products to some of the
           fastest growing population centers in the United States, including
           Southern California; the San Francisco Bay Area; Las Vegas, Nevada
           (through our CALNEV pipeline) and Phoenix and Tucson, Arizona, and 13
           truck-loading terminals with an aggregate usable tankage capacity of
           approximately 9.9 million barrels;

        o  our CALNEV pipeline operations, comprised of approximately 550-miles
           of pipelines that transport refined petroleum products from Colton,
           California to the growing Las Vegas, Nevada market, McCarran
           International Airport in Las Vegas, Nevada, and refined petroleum
           products terminals located in Barstow, California and Las Vegas,
           Nevada; and

        o  our West Coast terminals operations, which are comprised of seven
           terminal facilities on the West Coast that transload and store
           refined petroleum products;

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<PAGE>

   o our Central Florida Pipeline, two pipelines that total 195-miles and
     transport refined petroleum products from Tampa to the Orlando, Florida
     market and two refined petroleum products terminals at Tampa and Orlando,
     Florida;

   o our North System, a 1,600-mile pipeline that transports natural gas liquids
     in both directions between south central Kansas and the Chicago area and
     various intermediate points, including eight terminals, and our 50%
     interest in the Heartland Pipeline Company, which ships refined petroleum
     products in the Midwest;

   o our 51% interest in Plantation Pipe Line Company, which owns the 3,100-mile
     Plantation pipeline system that transports refined petroleum products
     throughout the southeastern United States, serving major metropolitan
     areas including Birmingham, Alabama; Atlanta, Georgia; Charlotte, North
     Carolina; and the Washington, D.C. area;

   o our newly-formed Kinder Morgan Southeast Terminals, currently consisting of
     seven refined petroleum products terminals acquired in December 2003 from
     ConocoPhillips and Phillips Pipe Line Company;

   o our 44.8% interest in the Cochin Pipeline system, a 1,900-mile pipeline
     transporting natural gas liquids and traversing Canada and the United
     States from Fort Saskatchewan, Alberta to Sarnia, Ontario, including five
     terminals;

   o our Cypress Pipeline, a 104-mile pipeline transporting natural gas liquids
     from Mont Belvieu, Texas to a major petrochemical producer in Lake Charles,
     Louisiana; and

   o our Transmix operations, which include the processing of petroleum pipeline
     transmix through transmix processing plants in Colton, California;
     Richmond, Virginia; Dorsey Junction, Maryland; Indianola, Pennsylvania; and
     Wood River, Illinois.

   Pacific Operations

   Our Pacific operations' pipelines are split into a South Region and a North
Region. Combined, the two regions consist of seven pipeline segments that serve
six western states with approximately 3,300 miles of refined petroleum products
pipeline and related terminal facilities.

   Refined petroleum products and related uses are:

         Product                 Use
         -------         ----------------------
         Gasoline        Transportation
         Diesel fuel     Transportation  (auto, rail,  marine),  agricultural,
                        industrial and commercial
         Jet fuel        Commercial and military air transportation

   Our Pacific operations transport over 1.1 million barrels per day of refined
petroleum products, providing pipeline service to approximately 39
customer-owned terminals, eight commercial airports and 15 military bases. For
2003, the three main product types transported were gasoline (62%), diesel fuel
(22%) and jet fuel (16%). Our Pacific operations also include 15 truck-loading
terminals (13 on SFPP, L.P. and two on CALNEV).

   Our Pacific operations provide refined petroleum products to some of the
fastest growing population centers in the United States, including
California; Las Vegas and Reno, Nevada; and the Phoenix, Arizona region.
Pipeline transportation of gasoline and jet fuel generally has a direct
correlation with demographic patterns. We believe that the population growth
associated with the markets served by our Pacific operations will continue in
the foreseeable future.

   South Region. Our Pacific operations' South Region consists of four pipeline
segments:

   o West Line;

   o East Line;


                                       12
<PAGE>

   o San Diego Line; and

   o CALNEV Line.

   The West Line consists of approximately 660 miles of primary pipeline and
currently transports products for 38 shippers from six refineries and three
pipeline terminals in the Los Angeles Basin to Phoenix and Tucson, Arizona and
various intermediate commercial and military delivery points. Product for the
West Line can also come from foreign and domestic sources through the Los
Angeles and Long Beach port complexes and the three pipeline terminals. A
significant portion of West Line volumes is transported to Colton, California
for local distribution and for delivery to our CALNEV Pipeline. The West Line
serves our terminals located in Colton and Imperial, California as well as in
Phoenix and Tucson, Arizona.

   The East Line is comprised of two parallel 8-inch diameter and 12-inch
diameter pipelines originating in El Paso, Texas and continuing approximately
300 miles west to our Tucson terminal and one line continuing northwest
approximately 130 miles from Tucson to Phoenix. All products received by the
East Line at El Paso come from a refinery in El Paso or are delivered through
connections with non-affiliated pipelines from refineries in Texas and New
Mexico. The East Line serves our terminals located in Phoenix and Tucson as well
as various intermediate commercial and military delivery points. We have
embarked on a major expansion of this pipeline system. The expansion consists of
replacing 160 miles of 8-inch diameter pipe between El Paso and Tucson and 84
miles of 8-inch diameter pipe between Tucson and Phoenix, with 16-inch and
12-inch diameter pipe, respectively.

   The San Diego Line is a 135-mile pipeline serving major population areas in
Orange County (immediately south of Los Angeles) and San Diego. The same
refineries and terminals that supply the West Line also supply the San Diego
Line. The San Diego Line serves our terminals at Orange and Mission Valley as
well as shipper terminals in San Diego and San Diego Airport through a
non-affiliated connecting pipeline.

   The CALNEV Line consists of two parallel 248-mile, 14-inch and 8-inch
diameter pipelines from our facilities at Colton, California to Las Vegas,
Nevada. It also includes approximately 55 miles of pipeline serving Edwards Air
Force Base. CALNEV originates at Colton, California and serves two CALNEV
terminals at Barstow, California and Las Vegas, Nevada. The CALNEV pipeline also
serves McCarran International Airport, Edwards Air Force Base and Nellis Air
Force Base, as well as certain smaller delivery points, including the Burlington
Northern Santa Fe and Union Pacific railroad yards.

   North Region. Our Pacific operations' North Region consists of three pipeline
segments:

   o the North Line;

   o the Bakersfield Line; and

   o the Oregon Line.

   The North Line consists of approximately 820 miles of trunk pipeline in five
segments originating in Richmond and Concord, California. This line serves our
terminals located in Brisbane, Sacramento, Chico, Fresno and San Jose,
California, and Reno, Nevada. The products delivered through the North Line come
from refineries in the San Francisco Bay Area and from various pipeline and
marine terminals that deliver products from foreign and domestic ports. The
14-inch diameter pipeline between Concord and Sacramento is currently being
replaced with a 20-inch diameter pipeline, expected to be in service by the end
of the fourth quarter of 2004.

   The Bakersfield Line is a 100-mile, 8-inch diameter pipeline serving Fresno,
California. A refinery located in Bakersfield, California, which supplies
substantially all of the products shipped through the Bakersfield Line, has
announced that it will cease operations by the end of 2004. We are currently
evaluating the effects of this closure on our Pacific operations in the San
Joaquin Valley; however, we expect the effect to be relatively neutral to the
overall operating results of our Pacific operations' pipelines.

                                       13
<PAGE>

   The Oregon Line is a 114-mile pipeline serving 11 shippers. Our Oregon Line
receives products from marine terminals in Portland, Oregon and from Olympic
Pipeline. Olympic Pipeline is a non-affiliated pipeline that transports products
from the Puget Sound, Washington area to Portland. From its origination point in
Portland, the Oregon Line extends south and serves our terminal located in
Eugene, Oregon.

   West Coast Terminals.  These terminals are operated as part of our Pacific
operations.

   The terminals include:

   o the Carson Terminal;

   o the Los Angeles Harbor Terminal;

   o the Gaffey Street Terminal;

   o the Richmond Terminal;

   o the Linnton and Willbridge Terminals; and

   o the Harbor Island Terminal.

   The West Coast terminals are fee-based terminals. They are located in several
strategic locations along the west coast of the United States and have a
combined total capacity of nearly eight million barrels of storage for both
petroleum products and chemicals.

   The Carson terminal and the connected Los Angeles Harbor terminal are
strategically located near the many refineries in the Los Angeles Basin. The
combined Carson/LA Harbor system is connected to numerous other pipelines and
facilities throughout the Los Angeles area, which gives the system significant
flexibility and allows customers to quickly respond to market conditions.
Storage at the Carson facility is primarily arranged via term contracts with
customers, ranging from one to five years. Term contracts represent 56% of total
revenues at the facility.

   The Gaffey Street terminal in San Pedro, California, is adjacent to the Port
of Los Angeles. This facility serves as a marine fuel storage and blending
facility for the marketing of local or imported bunker fuels for Los Angeles
ship traffic.

   The Richmond terminal is located in the San Francisco Bay Area. The facility
serves as a storage and distribution center for chemicals, lubricants and
paraffin waxes. It is also the principal location in northern California through
which tropical oils are imported for further processing, and from which United
States' produced vegetable oils are exported to consumers in the Far East.

   The Linnton and Willbridge terminals are located in Portland, Oregon. These
facilities handle petroleum products for distribution to both local and regional
markets. Refined products are received by pipeline, marine vessel, barge, and
rail car for distribution to local markets by truck; to southern Oregon via our
Oregon Line; to Portland International Airport via a non-affiliated pipeline;
and to eastern Washington and Oregon by barge.

   The Harbor Island terminal is located in Seattle, Washington. The facility is
supplied via pipeline and barge from northern Washington-state refineries,
allowing customers to distribute fuels economically to the greater Seattle-area
market by truck. The terminal is the largest marine fuel oil storage facility in
Puget Sound and also has a multi-component, in-line blending system for
providing customized bunker fuels to the marine industry.

   Truck-Loading Terminals. 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 ten million barrels. The truck terminals are located
at most destination points on each of our Pacific operations' pipelines as well
as some intermediate points along each pipeline. The simultaneous truck-loading
capacity of each terminal ranges from two to 12 trucks. We provide the following
services at these terminals:

                                       14
<PAGE>

   o short-term product storage;

   o truck-loading;

   o vapor handling;

   o deposit control additive injection;

   o dye injection;

   o oxygenate blending; and

   o quality control.

   The capacity of terminaling facilities varies throughout our Pacific
operations. We charge a separate fee (in addition to pipeline tariffs) for these
additional terminaling services. These fees are not regulated except for the
fees at the CALNEV terminals. At certain locations, we make product deliveries
to facilities owned by shippers or independent terminal operators.

   Markets. Currently our Pacific operations' pipeline system serves
approximately 68 shippers in the refined products market, with the largest
customers consisting of:

   o major petroleum companies;

   o independent refiners;

   o the United States military; and

   o independent marketers and distributors of refined petroleum products.

   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.

   Currently, the California gasoline market is approximately 940,000 barrels
per day. The Arizona gasoline market is served primarily by us at a market
demand of approximately 155,000 barrels per day. Nevada's gasoline market is
approximately 60,000 barrels per day and Oregon's is approximately 100,000
barrels per day. The diesel and jet fuel market is approximately 510,000 barrels
per day in California, 80,000 barrels per day in Arizona, 50,000 barrels per day
in Nevada and 60,000 barrels per day in Oregon. We transport over 1.1 million
barrels of petroleum products per day in these states.

   The volume of products transported is directly affected by the level of
end-user demand for such products in the geographic regions served. Certain
product volumes can experience seasonal variations and, consequently, overall
volumes may be lower during the first and fourth quarters of each year.

   California mandated the elimination of MTBE (methyl tertiary-butyl ether)
from gasoline by January 1, 2004. Since this date, MTBE-blended gasoline has
been replaced by ethanol-blended gasoline. Since ethanol cannot be shipped by
pipeline, we are realizing a downward adjustment in gasoline delivery volumes in
California; however, our overall revenues are not expected to be adversely
impacted as we charge a fee to blend ethanol at our terminals.

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


                                       15
<PAGE>

   Competition. The 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 as well as
refineries with related trucking arrangements within our market areas. We
believe that high capital costs, tariff regulation and environmental 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 pipelines being constructed 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 remains a competitive
threat for short haul movements by pipeline. The mandated elimination of MTBE
and required substitution of ethanol in California gasoline resulted in at least
a temporary increase in trucking distribution from shipper owned terminals. We
cannot predict with any certainty whether the use of short haul trucking will
decrease or increase in the future.

   Longhorn Partners Pipeline is a joint venture pipeline project that is
expected to begin transporting refined products from refineries on the Gulf
Coast to El Paso and other destinations in Texas in 2004. Increased product
supply in the El Paso area could result in some shift of volumes transported
into Arizona from our West Line to our East Line. Increased movements into the
Arizona market from El Paso would currently displace higher tariff volumes
supplied from Los Angeles on our West Line. However, our East Line is currently
running at full capacity and we have plans to increase East Line capacity to
meet market demand. The planned capacity increase will require significant
investment which should, under the FERC cost of service methodology, result in a
more balanced tariff between our East and West Lines. Such shift of supply
sourcing has not had, and is not expected to have, a material effect on our
operating results.

   Terminals owned by our Pacific operations also compete with terminals owned
by our shippers and by third party terminal operators in numerous locations.
Competing terminals are located in Reno, Sacramento, San Jose, Stockton, Colton,
Mission Valley, and San Diego, California and Phoenix and Tucson, Arizona and
Las Vegas, Nevada.

   Competitors of the Carson terminal in the refined products market include
Shell Oil Products U.S. and BP (formerly Arco Terminal Services Company). In the
crude/black oil market, competitors include Pacific Energy, Wilmington Liquid
Bulk Terminals (Vopak) and BP. Competitors to Gaffey Street include ST Services,
Chemoil and Wilmington Liquid Bulk Terminals (Vopak). Competition to the
Richmond terminal's chemical business comes primarily from IMTT. Competitors to
our Linnton and Willbridge terminals include ST Services, ChevronTexaco and
Shell Oil Products U.S. Our Harbor Island terminal competes primarily with
nearby terminals owned by Shell Oil Products U.S. and ConocoPhillips.

   Central Florida Pipeline

   We own and operate a liquids terminal in Tampa, Florida, a liquids terminal
in Taft, Florida (near Orlando, Florida) and an intrastate common carrier
pipeline system that serves customers' product storage and transportation needs
in Central Florida. The Tampa terminal contains 31 above-ground storage tanks
consisting of approximately 1.4 million barrels of storage capacity and is
connected to two ship dock facilities in the Port of Tampa that unload refined
products from barges and ocean-going vessels into the terminal. The Tampa
terminal provides storage for gasoline, diesel fuel and jet fuel for further
movement into either trucks through five truck-loading racks or into the Central
Florida pipeline system. The Tampa terminal also provides storage for chemicals,
predominantly used to treat citrus crops, delivered to the terminal by vessel or
rail car and loaded onto trucks through five truck-loading racks. The Taft
terminal contains 22 above-ground storage tanks consisting of approximately
670,000 barrels of storage capacity, providing storage for gasoline and diesel
fuel for further movement into trucks through 11 truck-loading racks.

   The 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 Ashland Petroleum. The 10-inch diameter pipeline is connected to our
Taft terminal and is also the sole pipeline supplying jet fuel to the Orlando
International Airport in Orlando, Florida. In 2003, the pipeline

                                       16
<PAGE>

transported approximately 96,000 barrels per day of refined products, with the
product mix being approximately 68% gasoline, 14% diesel fuel, and 18% jet fuel.

   Markets. The estimated total refined petroleum product demand in the State of
Florida is approximately 785,000 barrels per day. Gasoline is, by far, the
largest component of that demand at approximately 500,000 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 335,000
barrels per day, or approximately 43% of the consumption of refined products in
the state. Our market share is approximately 120,000 barrels per day, or
approximately 36% of the Central Florida market. 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 inMarch and April during spring break and again
in the summer vacation season, and is also heavily influenced by tourism, with
Disney World and other amusement parks located in 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 lesser amount
of refined 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 terminal operations at Tampa, the most
significant competitors are proprietary terminals owned and operated by major
oil companies, such as Marathon Ashland Petroleum, BP and Citgo, located along
the Port of Tampa, and the ChevronTexaco 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.
Due to the high capital costs of tank construction in Tampa and state
environmental regulation of terminal operations, we believe it is unlikely that
new competing terminals will be constructed in the foreseeable future.

   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 west of Orlando that are a
relatively short haul from Tampa, and with respect to markets east of Orlando,
our competition comes from trucks loading at marine terminals on the east coast
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.

   Federal regulation of marine vessels, including the requirement, under the
Jones Act, that United States-flagged vessels contain double-hulls, is a
significant factor in reducing the fleet of vessels available to 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. We believe it is unlikely that a new pipeline system
comparable in size and scope to our Central Florida Pipeline operations will be
constructed, due to the high cost of pipeline construction and environmental and
right-of-way permitting in Florida. However, the possibility of such a pipeline
being built is a continuing competitive factor.

   North System

   Our North System is an approximate 1,600-mile interstate common carrier
pipeline used to deliver natural gas liquids and refined petroleum products.
Additionally, we include our 50% ownership interest in Heartland Pipeline
Company as part of our North System operations. ConocoPhillips owns the
remaining 50% of Heartland Pipeline Company.



                                       17
<PAGE>

   Natural gas liquids are typically extracted from natural gas in liquid form
under low temperature and high pressure conditions. Natural gas liquids products
and related uses are as follows:

           Product                          Use
         Propane                  Residential heating, industrial and agricul-
                                 tural uses, petrochemical feedstock
         Isobutane                Further processing
         Natural gasoline         Further processing or blending into gasoline
                                 motor fuel
         Ethane/Propane Mix       Feedstock for petrochemical plants or peak-
                                 shaving facilities
         Normal butane            Feedstock for   petrochemical plants or blending
                                 into gasoline motor fuel

   Our North System extends from south central Kansas to the Chicago area. South
central Kansas is a major hub for producing, gathering, storing, fractionating
and transporting natural gas liquids. Our North System's primary pipelines are
comprised of approximately 1,400 miles of 8-inch and 10-inch diameter pipelines
and include:

   o two pipelines that originate at Bushton, Kansas and continue to a major
     storage and terminal area in Des Moines, Iowa;

   o a third pipeline, that extends from Bushton to the Kansas City, Missouri
     area; and

   o a fourth pipeline that extends from Des Moines to the Chicago area.

   Through interconnections with other major liquids pipelines, our North
System's pipeline system connects mid-continent producing areas to markets in
the Midwest and eastern United States. We also have defined sole carrier rights
to use capacity on an extensive pipeline system owned by Magellan Midstream
Partners, L.P. that interconnects with our North System. This capacity lease
agreement requires us to pay $2.1 million per year, is in place until February
2013 and contains a five-year renewal option. In addition to our capacity lease
agreement with Magellan, we also have a reversal agreement with Magellan to help
provide for the transport of summer-time surplus butanes from Chicago area
refineries to storage facilities at Bushton. We have an annual minimum joint
tariff commitment of $0.6 million to Magellan for this agreement.

   Our North System has approximately 5.6 million barrels of storage capacity,
which includes caverns, steel tanks, pipeline line-fill and leased storage
capacity. This storage capacity provides operating efficiencies and flexibility
in meeting seasonal demands of shippers and provides propane storage for our
truck-loading terminals.

   The Heartland pipeline system, which was completed in 1990, comprises one of
our North System's main line sections that originate at Bushton, Kansas and
terminates at a storage and terminal area in Des Moines, Iowa. We operate the
Heartland pipeline, and ConocoPhillips operates Heartland's Des Moines, Iowa
terminal and serves as the managing partner of Heartland. In 2000, Heartland
leased to ConocoPhillips Inc. 100% of the Heartland terminal capacity at Des
Moines, Iowa for $1.0 million per year on a year-to-year basis. The Heartland
pipeline lease fee, payable to us for reserved pipeline capacity, is paid
monthly, with an annual adjustment. The 2004 lease fee will be approximately
$1.1 million.

   In addition, our North System has seven propane truck-loading terminals at
various points in three states along the pipeline system and one multi-product
complex at Morris, Illinois, in the Chicago area. Propane, normal butane and
natural gasoline can be loaded at our Morris terminal.

   Markets. Our North System currently serves approximately 50 shippers in the
upper Midwest market, including both users and wholesale marketers of natural
gas liquids. These shippers include all three major refineries in the Chicago
area. Wholesale marketers of natural gas liquids primarily make direct large
volume sales to major end-users, such as propane marketers, refineries,
petrochemical plants and industrial concerns. Market demand for natural gas
liquids varies in respect to the different end uses to which natural gas liquids
products may be applied. Demand for transportation services is influenced not
only by demand for natural gas liquids but also by the available supply of
natural gas liquids. Heartland provides transportation of refined petroleum
products from refineries in the Kansas and Oklahoma areas to a BP terminal in
Council Bluffs, Iowa, a ConocoPhillips terminal in Lincoln, Nebraska and
Heartland's Des Moines terminal. The demand for, and supply of, refined
petroleum products in the

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geographic regions served by the Heartland pipeline system directly affect the
volume of refined petroleum products transported by Heartland.

   Supply. Natural gas liquids extracted or fractionated at the Bushton gas
processing plant have historically accounted for a significant portion
(approximately 40-50%) of the natural gas liquids transported through our North
System. Other sources of natural gas liquids transported in our North System
include large oil companies, marketers, end-users and natural gas processors
that use interconnecting pipelines to transport hydrocarbons. Refined petroleum
products transported by Heartland on our North System are supplied primarily
from the National Cooperative Refinery Association crude oil refinery in
McPherson, Kansas and the ConocoPhillips crude oil refinery in Ponca City,
Oklahoma.

   Competition. Our North System competes with other natural gas liquids
pipelines and to a lesser extent with rail carriers. In most cases, established
pipelines are the lowest cost alternative for the transportation of natural gas
liquids and refined petroleum products. Consequently, pipelines owned and
operated by others represent our primary competition. With respect to the
Chicago market, our North System competes with other natural gas liquids
pipelines that deliver into the area and with rail car deliveries primarily from
Canada. Other Midwest pipelines and area refineries compete with our North
System for propane terminal deliveries. Our North System also competes
indirectly with pipelines that deliver product to markets that our North System
does not serve, such as the Gulf Coast market area. Heartland competes with
other refined petroleum product carriers in the geographic market served.
Heartland's principal competitor is Magellan Midstream Partners, L.P.

   Plantation Pipe Line Company

   We own approximately 51% of Plantation Pipe Line Company, a 3,100-mile
pipeline system serving the southeastern United States. ExxonMobil owns the
remaining 49% interest and represents the single largest shipper on the
Plantation system. On December 21, 2000, we assumed day-to-day operations of
Plantation pursuant to agreements with Plantation Services LLC and Plantation
Pipe Line Company. 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 2003, Plantation delivered 612,451 barrels per day, a 3.9%
reduction from a record high in 2002. These delivered volumes were comprised of
gasoline (65%), diesel/heating oil (22%) and jet fuel (13%). The decline in
volume in 2003 compared to 2002 was primarily attributable to several unusual
events. First, three refineries in the State of Louisiana, ExxonMobil (Baton
Rouge), Marathon Ashland (Garyville), and Placid (Port Allen), experienced
extended refinery outages during February and March. Secondly, Chevron's
refinery in Pascagoula, Mississippi experienced an extended outage from February
into April. Finally, Murphy's refinery in Meraux, Louisiana experienced a major
fire in June and was down until November. Another factor affecting Plantation
was the implementation of a more stringent sulfur specification for the Atlanta
gasoline market. Due to limited availability of this grade of gasoline from
Plantation source refineries, much of this gasoline into the Atlanta market was
supplied from Colonial Pipeline.

   Plantation is expecting a 1.8% improvement in overall volumes during 2004. It
is anticipated that this growth will primarily be driven by an improving economy
and a significantly reduced level of refinery outages.

   Markets. Plantation ships products for approximately 40 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 six shippers represent
slightly over 80% of total system volumes.

   The eight states in which Plantation operates represent a collective pipeline
demand of approximately 2.0 million barrels per day of refined 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 Colonial Pipeline
Company. These markets represent potential growth opportunities for the
Plantation system.

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<PAGE>

   In addition, Plantation 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 0.1%
(led by an 18.6% increase in shipments to Ronald Reagan National) in 2003. Jet
fuel demand at Atlanta and Dulles was negatively impacted due to continued weak
international travel. An improving domestic economy should help improve jet fuel
demand in 2004.

   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 nine major refineries representing over
two 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.

   Kinder Morgan Southeast Terminals LLC

   Kinder Morgan Southeast Terminals LLC, a wholly-owned subsidiary referred to
herein as KMST, was formed in 2003 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.
Terminals acquired and operated by KMST will be independent with no affiliation
to major oil companies or marketers.

   On December 11, 2003, KMST acquired seven petroleum products terminals from
ConocoPhillips and Phillips Pipe Line for an aggregate consideration of
approximately $15.1 million, consisting of approximately $14.1 million in cash
and $1.0 million in assumed liabilities. These seven terminals contain
approximately 1.15 million barrels of storage capacity. The terminals are
located in the following markets: Selma, North Carolina; Charlotte, North
Carolina; Spartanburg, South Carolina; North Augusta, South Carolina; Doraville,
Georgia; Albany, Georgia; and Birmingham, Alabama. ConocoPhillips has entered
into a long-term contract to use the terminals. All seven terminals are served
by Colonial Pipeline and three are also connected to Plantation.

   KMST has also recently reached agreement with ExxonMobil to purchase seven of
its refined petroleum products terminals at the following locations: Newington,
Virginia; Richmond, Virginia; Roanoke, Virginia; Greensboro, North Carolina;
Charlotte, North Carolina; Knoxville, Tennessee; and Collins, Mississippi. The
terminals have a combined storage capacity of approximately 3.2 million barrels
for gasoline, jet fuel and diesel fuel. ExxonMobil has entered into a long-term
contract to use the terminals. This transaction is expected to close during
March 2004. All seven of these terminals are served by Plantation and two are
also connected to Colonial.

   Markets. KMST acquisition and marketing activities will be focused on the
Southeastern United States from Mississippi through Virginia, including
Tennessee. The primary marketing activity will involve receipt of petroleum
products from common carrier pipelines, short-term storage in terminal tankage,
and subsequent loading onto tank trucks. With the close of the ExxonMobil
acquisition, KMST will have a physical presence in markets representing over 75%
of the pipeline-supplied demand in the Southeast. KMST will offer a competitive
alternative to marketers seeking a relationship with a truly independent truck
terminal service provider.

   Supply. Product supply will be predominately from either Plantation,
Colonial, or both. To the maximum extent practicable, connectivity to both
Plantation and Colonial will be sought.

   Competition. There are relatively few independent terminal operators in the
Southeast. Most of the refined product terminals in this region are owned by
large oil companies (BP, Motiva, Citgo, Marathon Ashland, 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 (formerly Williams Energy
Partners) and TransMontaigne Product Services represent the only two significant
independent terminal operators in this region.

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<PAGE>

   Cochin Pipeline System

   We own 44.8% of the Cochin pipeline system, an approximate 1,900-mile,
12-inch diameter multi-product pipeline operating between Fort Saskatchewan,
Alberta and Sarnia, Ontario.

   The Cochin pipeline system and related storage and processing facilities
consist of Canadian operations and United States operations:

   o the Canadian facilities are operated under the name of Cochin Pipe Lines,
     Ltd.; and

   o the United States facilities are operated under the name of Dome Pipeline
     Corporation.

   The pipeline operates on a batched basis and has an estimated system capacity
of approximately 112,000 barrels per day. Its peak capacity is approximately
124,000 barrels per day. It includes 31 pump stations spaced at 60 mile
intervals and five United States propane terminals. Associated underground
storage is available at Fort Saskatchewan, Alberta and Windsor, Ontario.

   Markets. Formed in the late 1970's as a joint venture, the pipeline traverses
three provinces in Canada and seven states in the United States transporting
high vapor pressure ethane, ethylene, propane, butane and natural gas liquids to
the Midwestern United States and eastern Canadian petrochemical and fuel
markets. The system operates as a National Energy Board (Canada) and Federal
Energy Regulatory Commission (United States) regulated common carrier, shipping
products on behalf of its owners as well as other third parties. The system is
connected to the Enterprise pipeline system in Minnesota and in Iowa, and
connects with our North System at Clinton, Iowa. The Cochin pipeline system has
the ability to access the Canadian Eastern Delivery System via the Windsor
Storage Facility Joint Venture at Windsor, Ontario.

   Supply. Injection into the system can occur from:

   o BP, EnerPro or Dow fractionation facilities at Fort Saskatchewan, Alberta;

   o Provident Energy storage at five points within the provinces of Canada; or

   o the Enterprise West Junction, in Minnesota.

   Competition. The pipeline competes with railcars and Enbridge Energy Partners
for natural gas liquids longhaul 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 pipeline system
originating at storage facilities in Mont Belvieu, Texas and extending 104 miles
east to the Lake Charles, 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 specification 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.

                                       21
<PAGE>

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

   Transmix Operations

   Our transmix operations consist of transmix processing facilities located in
Richmond, Virginia; Dorsey Junction, Maryland; Indianola, Pennsylvania; Wood
River, Illinois; and Colton, California.

   Transmix occurs when dissimilar refined petroleum products are co-mingled in
the pipeline transportation process. Different products are pushed through the
pipelines abutting each other, and the area where different products mix is
called transmix. At our transmix processing facilities, we process and separate
pipeline transmix into pipeline-quality gasoline and light distillate products.
Transmix processing is performed for Duke Energy Merchants on a "for fee" basis
pursuant to a long-term contract expiring in 2010, and for Colonial Pipeline
Company at Dorsey Junction, Maryland.

   Our Richmond processing facility is comprised of a dock/pipeline, a
170,000-barrel tank farm, a processing plant, lab and truck rack. The facility
is composed of four distillation units that operate 24 hours a day, 7 days a
week providing a processing capacity of approximately 8,000 barrels per day.
Both the Colonial and Plantation pipelines supply the facility, as well as
deep-water barge (25 feet draft), transport truck and rail. We also own an
additional 3.6-acre bulk products terminal with a capacity of 55,000 barrels
located nearby in Richmond.

   Our Dorsey Junction processing facility is located within Colonial's Dorsey
Junction terminal facility. The 5,000-plus barrel per day processing unit began
operations in February 1998. It operates 24 hours a day, 7 days a week providing
dedicated transmix separation service for Colonial.

   Our Indianola processing facility is located near Pittsburgh, Pennsylvania
and is accessible by truck, barge and pipeline. It primarily processes transmix
from Buckeye, Colonial, Sun and Teppco pipelines. It has capacity to process
12,000 barrels of transmix per day and operates 24 hours per day, 7 days a week.
The facility is comprised of a 500,000-barrel tank farm, a quality control
laboratory, a truck-loading rack and a processing unit. The facility can ship
output via the Buckeye pipeline as well as by truck.

   Our Wood River processing facility was constructed in 1993 on property owned
by ConocoPhillips and is accessible by truck, barge and pipeline. It primarily
processes transmix from both Explorer and ConocoPhillips pipelines. It has
capacity to process 5,000 barrels of transmix per day. Located on approximately
three acres leased from ConocoPhillips, the facility consists of one processing
unit. Supporting terminal capability is provided through leased tanks in
adjacent terminals.

   Our Colton processing facility, completed in the spring of 1998, and located
adjacent to our products terminal in Colton, California, produces refined
petroleum products that are delivered into our Pacific operations' pipelines for
shipment to markets in Southern California and Arizona. The facility can process
over 5,000 barrels per day.

   Markets. The Gulf and East Coast refined petroleum products distribution
system, particularly the Mid-Atlantic region, provides 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 Pennsylvania and Illinois assets. Our
West Coast transmix processing operations support the markets served by our
Pacific operations. We are working to expand our Mid-Continent and West Coast
markets.

   Supply. Transmix generated by Colonial, Plantation, Sun, Teppco, Explorer and
our Pacific operations provide the vast majority of our supply. These suppliers
are committed to our transmix facilities by long-term contracts. Individual
shippers and terminal operators provide additional supply. Duke Energy Merchants
is responsible for acquiring transmix supply at all facilities other than at the
Dorsey Junction facility, which is supplied by Colonial Pipeline Company.

   Competition. Placid Refining is our main competitor in the Gulf coast area
and Tosco Refining is a major competitor in the New York harbor area. There are
various processors in the Mid-Continent area, primarily Phillips

                                       22
<PAGE>

and Williams Energy Services, who compete with our expansion efforts in that
market. Shell Oil US and 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, which contains both interstate and
intrastate pipelines, consists of natural gas transportation, storage,
gathering, processing, treating and matched purchases/sales. Within this
segment, we own over 13,400 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. Our Natural Gas Pipeline assets include the
following:

   o our Texas intrastate natural gas pipeline group, which consists of
     approximately 5,800 miles of intrastate natural gas pipeline with a peak
     transport capacity of approximately five billion cubic feet per day of
     natural gas and approximately 120 billion cubic feet of natural gas storage
     capacity (including the West Clear Lake natural gas storage facility
     located in Harris County, Texas, which is committed under a long term
     contract to Coral Energy as part of our Kinder Morgan Tejas acquisition).
     Our intrastate natural gas pipeline group operates primarily along the
     Texas Gulf Coast and includes the following four pipeline systems: Kinder
     Morgan Texas Pipeline, Kinder Morgan Tejas, Mier-Monterrey Mexico Pipeline,
     and the North Texas Pipeline;

   o our two Rocky Mountain interstate natural gas pipeline systems: Kinder
     Morgan Interstate Gas Transmission LLC and Trailblazer Pipeline Company.
     KMIGT owns a 6,100-mile natural gas pipeline system, including the Pony
     Express pipeline system, that extends from northwestern Wyoming east into
     Nebraska and Missouri and south through Colorado and Kansas. Our
     Trailblazer pipeline is a 436-mile pipeline that transports natural gas
     from Colorado to Beatrice, Nebraska;

   o our Casper and Douglas natural gas gathering systems, which are comprised
     of approximately 1,560 miles of natural gas gathering pipelines and two
     facilities in Wyoming capable of processing 210 million cubic feet of
     natural gas per day;

   o our 49% interest in the Red Cedar Gathering Company, which gathers natural
     gas in La Plata County, Colorado and owns and operates two carbon dioxide
     processing plants;

   o our 50% interest in Coyote Gas Treating, LLC, which owns a 250 million
     cubic feet per day natural gas treating facility in La Plata County,
     Colorado; and

   o our 25% interest in Thunder Creek Gas Services, LLC, which gathers,
     transports and processes methane gas from coal beds in the Powder River
     Basin of Wyoming.

   Texas Intrastate Pipeline Group

   As described above, our Texas intrastate natural gas pipeline group consists
of the following four pipeline systems: Kinder Morgan Texas Pipeline, Kinder
Morgan Tejas, Mier-Monterrey Mexico Pipeline and the North Texas Pipeline.

   Our Kinder Morgan Tejas system was acquired on January 31, 2002 from
Intergen, a joint venture owned by affiliates of the Royal Dutch Shell Group of
Companies, and Bechtel Enterprises Holding, Inc. The system has become
increasingly interconnected with our Kinder Morgan Texas Pipeline system, which
was acquired on December 31, 1999 from KMI. These pipelines essentially operate
as a single pipeline system, providing customers and suppliers with improved
flexibility and reliability. The combined assets include over 5,800 miles of
pipeline with a peak transport capacity of approximately five billion cubic feet
per day of natural gas and approximately 120 billion cubic feet of natural gas
storage capacity. In addition, the system has the capability to process over

                                       23
<PAGE>

one billion cubic feet per day of natural gas for liquids extraction and treat
approximately 250 million cubic feet per day of natural gas for carbon dioxide
removal.

   Collectively, the system primarily serves the Texas Gulf Coast, transporting,
processing and treating gas from multiple onshore and offshore supply sources to
serve the Houston/Beaumont/Port Arthur, Texas industrial markets, as well as
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.

   Our North Texas Pipeline, a $65 million investment, was completed in August
2002. The system consists of an 86-mile, 30-inch diameter pipeline that
transports natural gas from an interconnect with KMI's Natural Gas Pipeline
Company of America 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 325,000 dekatherms per day of natural gas and is
fully subscribed under a 30 year contract.  Our Mier-Monterrey Pipeline, an $89
million investment, was completed in March 2003. The system consists of a
95-mile, 30-inch diameter pipeline that stretches from south Texas to Monterrey,
Mexico and can transport up to 375,000 dekatherms per day of natural gas. The
pipeline connects to a 1,000-megawatt power plant complex and to the PEMEX
natural gas transportation system. We have entered into a 15 year contract with
Pemex Gas Y Petroquimica Basica, which has subscribed for all of the pipeline's
capacity.

   Markets. Our Texas intrastate natural gas pipeline group's market area
consumes over eight billion cubic feet per day of natural gas. Of this amount,
we estimate that 75% is industrial demand (including on-site, cogeneration
facilities), about 15% is merchant generation demand and the remainder is split
between local natural gas distribution and utility power demand. The industrial
demand is primarily year-round load. Local natural gas distribution load peaks
in the winter months and is complemented by power demand (both merchant and
utility generation) which peaks in the summer months. As new merchant gas fired
generation has come online and displaced traditional utility generation, we have
successfully attached these new generation facilities to our pipeline systems in
order to maintain our share of natural gas supply for power generation.

    Mexico is an increasingly important market. We serve this market through
interconnection with the facilities of Pemex at the United States-Mexico border
near Arguellas, Mexico and Monterrey, Mexico. Current deliveries through the
existing interconnection near Arguellas are approximately 200,000 dekatherms per
day of natural gas and deliveries to Monterrey generally range from 200,000 to
300,000 dekatherms per day of natural gas. 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 and along the Texas Gulf Coast. 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.

   Gathering, Processing and Treating. Our intrastate natural gas group owns and
operates various gathering systems in South and East Texas. These systems
aggregate pipeline quality natural gas supplies into our main transmission
pipelines, and in certain cases, aggregate natural gas that must be processed or
treated at its own facilities or the facilities of others. We own two processing
plants: our Texas City Plant in Galveston County, Texas and our Galveston Bay
Plant in Chambers County, Texas. Combined, these plants can process 150 million
cubic feet per day of natural gas for liquids extraction. In addition, we have
contractual rights to process approximately one billion cubic feet per day of
natural gas at various third-party owned facilities. We also own and operate
four natural gas treating plants that offer carbon dioxide and/or hydrogen
sulfide removal. We can treat up to 150 million cubic feet per day of natural
gas for carbon dioxide removal at our Fandango Complex in Zapata

                                       24
<PAGE>

County, Texas, 60 million cubic feet per day of natural gas at our M.P. 16 Plant
in Webb County, Texas and approximately 40 million cubic feet per day of natural
gas at our Thompsonville Facility in Jim Hogg County, Texas. Not all of these
plants are currently operating. Economic conditions and gas quality conditions
dictate operations. In addition, we own and operate the Indian Rock Plant
located in Upshur County, Texas. The plant is capable of treating 45 million
cubic feet per day of natural gas for carbon dioxide and/or hydrogen sulfide
removal.

   Storage. We own the West Clear Lake natural gas storage facility located in
Harris County, Texas. Under a long term contract, Coral Energy Resources, L.P.
operates the facility and controls the 96 billion cubic feet of natural gas
working capacity, and we provides transportation service into and out of the
facility. We lease a salt dome storage facility located near Markham, Texas. The
facility consists of two salt dome caverns with approximately 7.5 billion cubic
feet of total natural gas storage capacity, over 4.8 billion cubic feet of
working natural gas capacity and up to 400 million cubic feet per day of peak
deliverability. We also lease salt dome caverns from Dow Hydrocarbon &
Resources, Inc. and BP America Production Company in Brazoria County, Texas. The
salt dome caverns are referred to as the Stratton Ridge Facilities and have a
combined capacity of 11.8 billion cubic feet of natural gas, working natural gas
capacity of 5.4 billion cubic feet and a peak day deliverability of up to 400
million cubic feet per day. In addition, we control, through contractual
arrangements, another ten billion cubic feet of third-party natural gas storage
capacity in the Houston, Texas area and 4.1 billion cubic feet of natural gas
storage capacity in the East Texas area.

   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.

   Kinder Morgan Interstate Gas Transmission LLC

   Kinder Morgan Interstate Gas Transmission LLC, referred to herein as KMIGT,
owns approximately 5,000 miles of transmission lines in Wyoming, Colorado,
Kansas, Missouri and Nebraska. It provides transportation and storage services
to KMI affiliates, third-party natural gas distribution utilities and other
shippers. Pursuant to transportation agreements and Federal Energy Regulatory
Commission tariff provisions, KMIGT offers its customers firm and interruptible
transportation and storage services, including no-notice transportation and park
and loan services. Under KMIGT's tariffs, firm transportation and storage
customers pay reservation fees 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. Reservation fees are based upon geographical location
(KMIGT does not have seasonal rates) and the distance of the transportation
service provided. 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.

   The system is powered by 28 transmission and storage compressor stations with
approximately 149,000 horsepower. The pipeline system provides storage services
to its customers from its Huntsman Storage Field in Cheyenne County, Nebraska.
The facility has approximately 39.5 billion cubic feet of total storage
capacity, 12.5 billion cubic feet of working gas capacity and can withdraw up to
101 million cubic feet of natural gas per day.

   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 for 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 for crop irrigation during the summer from
time-to-time exceeds heating season demand and provides KMIGT relatively
consistent volumes throughout the year.

   Supply. Approximately 18%, by volume, of KMIGT's firm contracts expire within
one year and 26% expire within one to five years. Affiliated entities are
responsible for approximately 22% of the total contracted firm transportation
and storage capacity on KMIGT's system. Over 98% of the system's firm transport
capacity is currently subscribed.



                                       25
<PAGE>

   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

   Trailblazer Pipeline Company is an Illinois partnership and its principal
business is to transport and redeliver natural gas to others in interstate
commerce. It does business in the states of Wyoming, Colorado, Nebraska and
Illinois. Natural Gas Pipeline Company of America, a subsidiary of KMI, manages,
maintains and operates Trailblazer, for which it is reimbursed at cost.
Trailblazer's 436-mile natural gas pipeline system 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 Trailblazer's pipeline system interconnects with
Natural Gas Pipeline Company of America's and Northern Natural Gas Company's
pipeline systems.

   Trailblazer's pipeline is the fourth and last segment of a 791-mile pipeline
system known as the Trailblazer Pipeline System, which originates in Uinta
County, Wyoming with Canyon Creek Compression Company, a 22,000 horsepower
compressor station located at the tailgate of BP Amoco Production Company's
processing plant in the Whitney Canyon Area in Wyoming (Canyon Creek's
facilities are the first segment). Canyon Creek receives gas from the BP Amoco
processing plant and provides transportation and compression of gas for delivery
to Overthrust Pipeline Company's 88-mile, 36-inch diameter pipeline system at an
interconnection in Uinta County, Wyoming (Overthrust's system is the second
segment). Overthrust delivers gas to Wyoming Interstate's 269-mile, 36-inch
diameter pipeline system at an inter-connection (Kanda) in Sweetwater County,
Wyoming (Wyoming Interstate's system is the third segment). Wyoming Interstate's
pipeline delivers gas to Trailblazer's pipeline at an interconnection near
Rockport in Weld County, Colorado.

   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. In May
2002, we completed a fully-subscribed, $48 million expansion project on the
Trailblazer system that expanded its transportation capacity by 324,000
dekatherms of natural gas per day. The expansion increased capacity on the
pipeline by approximately 60% and provides new firm long-term transportation
service. In conjunction with the expansion, the FERC also granted Trailblazer's
request to assess incremental rates and fuel for shippers taking capacity
related to the expansion facilities.

   Supply. As of December 31, 2003, none of Trailblazer's firm contracts expire
before one year and 38%, by volume, expire within one to five years. Affiliated
entities hold less than 1% of the total firm transportation capacity. All of the
system's firm transport capacity is currently subscribed.

   Competition. While competing pipelines have been announced which would move
gas east out of the Rocky Mountains, 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 October 2003, the FERC issued a preliminary determination approving
the Cheyenne Plains pipeline project that is being developed by Colorado
Interstate Gas Company. This project, which has a proposed in service date of
August 2005, would allow for the transportation of 560,000 dekatherms per day of
natural gas from Weld County, Colorado to Greensburg, Kansas and is expected to
compete with Trailblazer.

   Casper and Douglas Natural Gas Gathering and Processing Systems

   We own and operate our Casper and Douglas natural gas gathering and
processing facilities.

   The Douglas gathering system is comprised of approximately 1,500 miles of
4-inch to 16-inch diameter pipe that gathers approximately 35 million cubic feet
per day of natural gas from 650 active receipt points. Douglas Gathering has an
aggregate 24,495 horsepower of compression situated at 17 field compressor
stations. Gathered volumes are processed at our Douglas plant, located in
Douglas, Wyoming. Residue gas is delivered into KMIGT and recovered liquids are
injected in ConocoPhillips Petroleum's natural gas liquids pipeline for
transport to Borger, Texas.

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   The Casper gathering system is comprised of approximately 60 miles of 4-inch
to 8-inch diameter pipeline gathering approximately 20 million cubic feet per
day of natural gas from eight active receipt points. Gathered volumes are
delivered directly into KMIGT. Current gathering capacity is contingent upon
available capacity on KMIGT and the Casper Plant's 50 to 80 million cubic feet
per day processing capacity.

   We believe that Casper-Douglas' unique combination of percentage-of-proceeds,
sliding scale percent-of-proceeds and keep whole plus fee processing agreements
helps to reduce our exposure to commodity price volatility.

   Markets. Casper and Douglas are processing plants servicing gas streams
flowing into KMIGT.

   Competition. There are three other natural gas gathering and processing
alternatives available to conventional natural gas producers in the Greater
Powder River Basin. However, Casper and Douglas are the only two plants in the
region that provide straddle processing of natural gas streams flowing into
KMIGT upsteam of our two plant facilities. The other regional facilities include
the Hilight (80 million cubic feet per day) and Kitty (17 million cubic feet per
day) plants owned and operated by Western Gas Resources, and the Sage Creek
Processors (50 million cubic feet per day) plant owned and operated by Devon
Energy.

   Red Cedar Gathering Company

   We own a 49% equity interest in the Red Cedar Gathering Company, a joint
venture organized in August 1994, referred to in this document as Red Cedar. The
Southern Ute Indian Tribe owns the remaining 51%. 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's gas gathering system currently consists of over 900 miles of
gathering pipeline connecting more than 700 producing wells, 76,000 horsepower
of compression at 21 field compressor stations and two carbon dioxide treating
plants. A majority of the natural gas on the system moves through 8-inch to
20-inch diameter pipe. The capacity and throughput of the Red Cedar system as
currently configured is approximately 750 million cubic feet per day of natural
gas.

   Coyote Gas Treating, LLC

   We own a 50% equity interest in Coyote Gas Treating, LLC, referred to herein
as Coyote Gulch. Coyote Gulch is a joint venture that was organized in December
1996. Gulf Terra Energy Partners, L.P. owns the remaining 50%. The sole asset
owned by the joint venture is a 250 million cubic feet per day natural gas
treating facility located in La Plata County, Colorado. We are the managing
partner of Coyote Gas Treating, LLC.

   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.

   Effective January 1, 2002, Coyote Gulch entered into a five-year operating
lease agreement with Red Cedar. Under the terms of the lease, Red Cedar operates
the facility and is responsible for all operating and maintenance expense and
capital costs. In place of the treating fees that were previously received by
Coyote Gulch from Red Cedar, Red Cedar is required to make monthly lease
payments.

   Thunder Creek Gas Services, LLC

   We own a 25% equity interest in Thunder Creek Gas Services, LLC, referred to
herein as Thunder Creek. Thunder Creek is a joint venture that was organized in
September 1998. 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. Throughput volumes include both coal seam
and conventional plant residue gas.  Thunder

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Creek is independently operated from offices located in Denver, Colorado with
field offices in Glenrock and Gillette, Wyoming.

   Thunder Creek's operations are a combination of mainline and low pressure
gathering assets. The mainline assets include 125 miles of 24-inch diameter
mainline pipeline, 308 miles of 4-inch to 12-inch diameter high and low pressure
laterals, 19,890 horsepower of mainline compression and carbon dioxide removal
facilities consisting of a 240 million cubic feet per day carbon dioxide
treating plant complete with dehydration. The mainline assets receive gas from
34 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 169
miles of 4-inch to 14-inch diameter gathering pipeline and 50,260 horsepower of
field compression. Gas is gathered from 79 receipt points and delivered to the
mainline at seven primary locations.

CO2

   Our CO2 segment consists of Kinder Morgan CO2 Company, L.P. and its
consolidated affiliates, referred to herein 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 and owns interests in other related assets in
the continental United States, through the following:

   o our interests in carbon dioxide reserves, including an approximate 45%
     interest in the McElmo Dome unit and an approximate 11% interest in the
     Bravo Dome unit;

   o our carbon dioxide pipelines, including:

        o  our Central Basin pipeline, a 320-mile carbon dioxide pipeline system
           located in the Permian Basin of West Texas between Denver City, Texas
           and McCamey, Texas;

        o  our Centerline pipeline, a 113-mile carbon dioxide pipeline located
           in the Permian Basin of West Texas between Denver City, Texas and
           Snyder, Texas; and

        o  our interests in other carbon dioxide pipelines, including an
           approximate 98% interest in the Canyon Reef Carriers pipeline, a 50%
           interest in the Cortez pipeline, a 13% undivided interest in the
           Bravo pipeline system and an approximate 69% interest in the Pecos
           pipeline;

   o our 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 22% net profits interest in the H.T. Boyd unit and minority
     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; and

   o our interests in gasoline plants, including an approximate 22% working
     interest in and an additional 26% net profits interest in the Snyder
     gasoline plant, 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.

   Carbon Dioxide Reserves

   We own approximately 45% of the McElmo Dome unit, and operate the unit which
contains more than 10 trillion cubic feet of nearly pure carbon dioxide.
Deliverability and compression capacity exceeds one billion cubic feet per day.
The McElmo Dome unit produces from the Leadville formation at approximately
8,000 feet with 47 wells that produce at individual rates of up to 60 million
cubic feet per day.

   We also own approximately 11% of Bravo Dome unit, which holds reserves of
approximately two trillion cubic feet of carbon dioxide. The Bravo dome produces
approximately 310 million cubic feet per day, with production coming from more
than 350 wells in the Tubb Sandstone at 2,300 feet.


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   Markets. Our principal market for carbon dioxide is for injection into mature
oil fields in the Permian Basin, where industry demand is expected to be
comparable to historical demand for the next several years. We are exploring
additional potential markets, including enhanced oil recovery targets in the
North Sea, California, Mexico 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. Our ownership interests in the Cortez and Bravo pipelines are in direct
competition with other carbon dioxide pipelines. We also compete with other
interest owners in McElmo Dome for transportation of carbon dioxide to the
Denver City, Texas market area. 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

   Placed in service in 1985, our Central Basin pipeline consists of
approximately 143 miles of 16-inch to 20-inch diameter pipe and 178 miles of
4-inch to 12-inch lateral supply lines located in the Permian Basin between
Denver City, Texas and McCamey, Texas with a throughput capacity of 650 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 Occidental and BP,
respectively). 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 16-inch
diameter pipe located in the Permian Basin between Denver City, Texas and
Snyder, Texas. The pipeline has a capacity of 250 million cubic feet per day. We
constructed this pipeline and placed it in service in May 2003. The tariffs
charged by the Centerline pipeline are not regulated.

   As a result of our 50% ownership interest in Cortez Pipeline Company, we own
a 50% interest in and operate the 502-mile, 30-inch diameter Cortez pipeline.
The pipeline carries carbon dioxide from the McElmo Dome source reservoir in
Cortez, Colorado to the Denver City, Texas hub. The Cortez pipeline currently
transports nearly one billion cubic feet per day, including approximately 90% of
the carbon dioxide transported downstream on our Central Basin pipeline and our
Centerline pipeline.

   We own a 13% undivided interest in the 218-mile, 20-inch diameter Bravo
pipeline, which delivers to the Denver City hub and has a capacity of more than
350 million cubic feet per day. Major delivery points along the line include the
Slaughter field in Cochran and Hockley Counties, Texas, and the Wasson field in
Yoakum County, Texas. Tariffs on the Cortez and Bravo pipelines are not
regulated.

   In addition, we own 98% of the Canyon Reef Carriers pipeline and
approximately 69% of the Pecos pipeline. The Canyon Reef Carriers pipeline
extends 138 miles from McCamey, Texas, to the SACROC unit. The pipeline has a
16-inch diameter, 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, 8-inch diameter pipeline that runs from McCamey to
Iraan, Texas. We acquired an additional 65% ownership interest in the pipeline
on November 1, 2003 from a subsidiary of Marathon Oil Company and we are
currently bringing the pipeline back into service.

   Oil Reserves

   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 50,000 acres located in the Permian Basin in Scurry County, Texas.
SACROC was discovered in 1948 and has produced over 1.26 billion barrels of oil
since inception, or approximately 47% of 2.7 billion barrels of original oil in
place. We have continued the development of the carbon

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dioxide project initiated by the previous owners and have reversed the decline
in production through increased carbon dioxide injection.

   Effective June 1, 2003, we increased our interest in SACROC to approximately
97% by acquiring MKM Partners, L.P.'s 12.75% ownership interest. MKM Partners,
L.P. was an oil and gas joint venture formed on January 1, 2001 and owned 15% by
KMCO2 and 85% by subsidiaries of Marathon Oil Company. The joint venture's
assets consisted of a 12.75% interest in the SACROC field unit and a 49.9%
interest in the Yates field unit. MKM Partners, L.P. was dissolved effective
June 30, 2003, and its net assets were distributed to partners in accordance
with its partnership agreement.

   As of December 2003, the SACROC unit had 255 producing wells, and the
purchased carbon dioxide injection rate was 317 million cubic feet per day, up
from an average of 140 million cubic as of December 2002. The oil production
rate as of December 2003 was approximately 23,000 barrels of oil per day, up
from approximately 17,000 barrels of oil per day as of December 2002.   The
Yates unit is also one of the largest oil fields ever discovered in the United
States. It originally held more than five billion barrels of oil, of which about
28% has been produced. The field is comprised of approximately 26,400 acres
located about 90 miles south of Midland, Texas. The Yates field was discovered
in 1926. Effective November 1, 2003, we increased our interest in Yates and
became operator of the field by acquiring an additional 42.5% ownership interest
from subsidiaries of Marathon Oil Company. We now own a nearly 50% ownership
interest in the Yates field unit. We also acquired all of the crude oil
gathering lines and equipment surrounding the Yates field.

   As of December 2003, the Yates unit was producing about 18,000 barrels of oil
per day. Our plan is to increase the production life of Yates by combining
horizontal drilling with carbon dioxide flooding to ensure a relatively steady
production profile over the next several years. Unlike our operations at SACROC,
where we use carbon dioxide and water to drive oil to the producing wells, we
plan on 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.

   Gas Plant Interests

   We operate and own an approximate 22% working interest plus an additional 26%
of the net profits of the Snyder gasoline plant, 51% of the Diamond M gas plant
and 100% of the North Snyder plant. 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 pursuant to contract agreements.
Production of natural gas liquids at the Snyder gasoline plant has increased
from approximately 7,102 barrels per day as of December 2002 to approximately
9,076 barrels per day as of December 2003.

Terminals

   Our Terminals segment includes the business portfolio of approximately 52
terminals that transload and store coal, dry-bulk materials and
petrochemical-related liquids, as well as approximately 57 transload operations
located throughout the United States. Our liquids terminal operations primarily
store commercial liquids, including refined petroleum products and industrial
chemicals, in aboveground storage tanks and transfer products to and from
pipelines, tank trucks, tank barges and tank rail cars. Our bulk terminal
operations primarily involve bulk material handling services; however, we also
provide terminal engineering and design services and in-plant services covering
material handling, maintenance and repair services, rail car switching services,
ship agency and miscellaneous marine services.

   Liquids Terminals

   Kinder Morgan Liquids Terminals LLC, referred to herein as KMLT, is comprised
of 12 bulk liquids terminal facilities and 51 rail transloading and materials
handling operations. Together, these facilities have a total capacity

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of approximately 36.2 million barrels of liquid products, primarily gasoline,
distillates, petrochemicals and vegetable oil products. In 2003, our liquids
terminals handled approximately 514 million barrels of clean petroleum,
petrochemical and vegetable oil products for approximately 250 different
customers, and our transloading operations handled approximately 59,000 rail
cars. The liquids terminals are located in Houston, New York Harbor, South
Louisiana, Chicago, Cincinnati and Pittsburgh.

   Houston. KMLT's Houston terminal complex, located in Pasadena and Galena
Park, Texas along the Houston Ship Channel, has approximately 18 million barrels
of capacity. The complex is connected via pipeline to 14 refineries, four
petrochemical plants and ten major outbound pipelines. In addition, the
facilities have four ship docks and seven barge docks for inbound and outbound
movements. The terminals are served by the Union Pacific railroad.

   New York Harbor. KMLT owns two facilities in the New York Harbor area, one in
Carteret, N.J. and the other in Perth Amboy, N.J. The Carteret facility has a
capacity of approximately 7.1 million barrels of petroleum and petrochemical
products. This facility has two ship docks with a 37-foot mean low water depth
and four barge docks.
It is connected to the Colonial, Buckeye, Sun and Harbor pipeline systems and
CSX and Norfolk Southern railroads. The Perth Amboy facility has a capacity of
approximately 2.3 million barrels of petroleum and petrochemical products. Tank
sizes range from 2,000 gallons to 300,000 barrels. The facility has one ship
dock and one barge dock. This facility is connected to the Colonial and Buckeye
pipeline systems and CSX and Norfolk Southern railroads.

   South Louisiana. KMLT owns two facilities in South Louisiana: one in the Port
of New Orleans located in Harvey, Louisiana and the other near a major
petrochemical complex in Geismar, Louisiana. The New Orleans facility has
approximately 3.0 million barrels of total tanks ranging in sizes from 416
barrels to 200,000 barrels. There are three ship docks and one barge dock, and
the Union Pacific railroad provides rail service. The terminal also provides
ancillary drumming, packaging and cold storage services. A second facility is
located approximately 75 miles north of the New Orleans facility on the left
descending bank of the Mississippi River near the town of St. Gabriel,
Louisiana. The facility has approximately 400,000 barrels of tank capacity and
the tanks vary in sizes ranging from 1,990 barrels to 80,000 barrels. There are
three local pipeline connections at the facility which enable the movement of
products from the facility to the petrochemical plants in Geismar, Louisiana.

   Chicago. KMLT owns two facilities in the Chicago area. One facility is in
Argo, Illinois about 14 miles southwest of downtown Chicago. The facility has
approximately 2.4 million barrels of capacity in tankage ranging from 50,000
gallons to 80,000 barrels. The Argo terminal is situated along the Chicago
sanitary and ship channel and has three barge docks. The facility is connected
to TEPPCO and Westshore pipelines, as well as a new direct connection to Midway
Airport. The Canadian National railroad services this facility. The other
facility is located in the Port of Chicago along the Calumet River. The facility
has approximately 741,000 barrels of capacity in tanks ranging from 12,000
gallons to 55,000 barrels. There are two ship docks and four barge docks, and
the facility is served by the Norfolk Southern railroad.

   Cincinnati. KMLT has two facilities along the Ohio River in Cincinnati, Ohio.
The total storage is approximately 850,000 barrels in tankage ranging from 120
barrels to 96,000 barrels. There are three barge docks, and the NNU and CSX
railroads provide rail service.

   Pittsburgh. This KMLT facility is located in Dravosburg, Pennsylvania, along
the Monongahela River. There is approximately 250,000 barrels of storage in
tanks ranging from 1,200 to 38,000 barrels. There are two barge docks, and
Norfolk Southern railroad provides rail service.

   Rail Transloading Operations. We own Kinder Morgan Materials Services LLC,
referred to herein as KMMS. KMMS operates approximately 57 rail transloading
facilities, of which 47 are located east of the Mississippi River. The CSX,
Norfolk Southern, Union Pacific, Kansas City Southern and A&W railroads provide
rail service for our terminal facilities. Approximately 50% of the products
handled by KMMS are liquids and 50% are dry bulk products. KMMS also designs and
builds transloading facilities, performs inventory management services and
provides value-added services such as blending, heating and sparging.

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   Competition. We are one of the largest independent operators of liquids
terminals in North America. Our largest competitors are Magellan, ST Services,
IMTT, Vopak, Oil Tanking and Transmontaigne.

   Bulk Terminals

   Our Bulk Terminals consist of 40 bulk terminals, which handle approximately
60 million tons of bulk products annually. Collectively, our bulk terminals have
two million tons of covered storage and 14 million tons of open storage.

   Coal Terminals

   We handled approximately 25 million tons of coal in 2003, which is 45% of the
total volume at our bulk terminals.

   Our Cora Terminal is a high-speed, rail-to-barge coal transfer and storage
facility. Built in 1980, the terminal is located on approximately 480 acres of
land along the upper Mississippi River near Cora, Illinois, about 80 miles
south of St. Louis, Missouri. The terminal has a throughput capacity of about 15
million tons per year that can be expanded to 20 million tons with certain
capital additions. The terminal currently is equipped to store up to one million
tons of coal. This storage capacity provides customers the flexibility to
coordinate their supplies of coal with the demand at power plants. Storage
capacity at the Cora Terminal could be doubled with additional capital
investment.

   Our Grand Rivers Terminal is operated on land under easements with an initial
expiration of July 2014. Grand Rivers is a coal transloading and storage
facility located along the Tennessee River just above the Kentucky Dam. The
terminal has current annual throughput capacity of approximately 12 to 15
million tons with a storage capacity of approximately two million tons. With
capital improvements, the terminal could handle 25 million tons annually.

   Our Pier IX Terminal is located in Newport News, Virginia. The terminal
originally opened in 1983 and has the capacity to transload approximately 12
million tons of coal annually. It can store 1.3 million tons of coal on its
30-acre storage site. In addition, the Pier IX Terminal operates a cement
facility, which has the capacity to transload over 400,000 tons of cement
annually. In late 2002, Pier IX began to operate a synfuel plant on site, and in
early 2004, Pier IX began to operate a second synfuel plant on site. Volumes of
synfuel produced in 2003 were between one and two million tons.

   In addition, we operate the LAXT Coal Terminal in Los Angeles, California. In
2002, LAXT ceased shipping export coal, but continues to handle petroleum coke.
The facility is currently for sale and we will be dealing with a new owner
during 2004.

   We also developed our Shipyard River Terminal in Charleston, South Carolina,
to be able to unload, store and reload coal imported from various foreign
countries. The imported coal is expected to be cleaner burning low sulfur and
would be used by local utilities to comply with the Clean Air Act. Shipyard
River Terminal has the capacity to handle 2.5 million tons per year.

   Markets. Coal continues to be the fuel of choice for electric generation,
accounting for more than 50% of United States electric generation feedstock.
Forecasts of overall coal usage and power plant usage for the next 20 years show
an increase of about 1.5% per year. Current domestic supplies are predicted to
last for several hundred years. Most coal transloaded through our coal terminals
is destined for use in coal-fired electric generation.

   We believe that obligations to comply with the Clean Air Act Amendments of
1990 will cause shippers to increase the use of cleaner burning low sulfur coal
from the western United States and from foreign sources. Approximately 80% of
the coal loaded through our Cora Terminal and our Grand Rivers Terminal is low
sulfur coal originating from mines located in the western United States,
including the Hanna and Powder River basins in Wyoming, western Colorado and
Utah. In 2003, four major customers accounted for approximately 90% of all the
coal loaded through our Cora Terminal.


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  Our Pier IX Terminal exports coal to foreign markets. In addition, Pier IX
serves power plants on the eastern seaboard of the United States and imports
cement pursuant to a long-term contract.

   Supply. Our Cora and Grand Rivers terminals handle low sulfur coal
originating in Wyoming, Colorado, and Utah as well as coal that originates in
the mines of southern Illinois and western Kentucky. However, since many
shippers, particularly in the East, are using western coal or a mixture of
western coal and other coals as a means of meeting environmental restrictions,
we anticipate that growth in volume through the terminals will be primarily due
to western low sulfur coal originating in Wyoming, Colorado and Utah.

   Our Cora Terminal sits on the mainline of the Union Pacific Railroad and is
strategically positioned to receive coal shipments from the West. Grand Rivers
provides easy access to the Ohio-Mississippi River network and the
Tennessee-Tombigbee River system. The Paducah & Louisville Railroad, a short
line railroad, serves Grand Rivers with connections to seven Class I rail lines
including the Union Pacific, CSX, Illinois Central and Burlington Northern Santa
Fe. The Pier IX Terminal is served by the CSX Railroad, which transports coal
from central Appalachian and other eastern coal basins. Cement imported to the
Pier IX Terminal primarily originates in Europe.

   Competition. Two new coal terminals that compete with our Cora Terminal and
our Grand Rivers Terminal were completed in 2003. While Cora and Grand Rivers
are modern high capacity terminals, some volume will be diverted to the new
terminals by the Tennessee Valley Authority to promote increased competition.
The total reduction in 2003 was approximately three million tons; however, such
amounts could be higher if the new terminals aggressively compete for the
existing customers of our Cora and Grand Rivers coal terminals. Our Pier IX
Terminal competes primarily with two modern coal terminals located in the same
Virginian port complex as our Pier IX Terminal.

   Petroleum Coke and Other Bulk Terminals

   We own or operate eight petroleum coke terminals in the United States.
Petroleum coke is a by-product of the refining process and has characteristics
similar to coal. Petroleum coke supply in the United States has increased in the
last several years due to the increased use of coking units by domestic
refineries. Petroleum coke is used in domestic utility and industrial steam
generation facilities and is exported to foreign markets. Most of our customers
are large integrated oil companies that choose to outsource the storage and
loading of petroleum coke for a fee. We handled almost six million tons of
petroleum coke in 2003.

   We own or operate an additional 13 bulk terminals located primarily on the
southern edge of the lower Mississippi River, the Gulf Coast and the West Coast.
These other bulk terminals serve customers in the alumina, cement, salt, soda
ash, ilmenite, fertilizer, ore and other industries seeking specialists who can
build, own and operate bulk terminals.

   Included among these terminals is our Owensboro Gateway terminal, acquired on
September 1, 2002 and our 66 2/3% ownership interest in International Marine
Terminals Partnership, acquired on February 1, 2002. The Owensboro Gateway
terminal, located in Owensboro, Kentucky, is one of the nation's largest storage
and handling points for bulk aluminum. The facility also handles various other
bulk materials, as well as a barge scrapping facility. The IMT partnership
operates a bulk terminal site in Port Sulphur, Louisiana that handles
approximately eight million tons per year of iron ore, coal, petroleum coke and
barite. Additionally, on December 31, 2002, we purchased four barge-mounted
crane units from Stevedoring Services of America for use at the IMT terminal. We
had previously leased these cranes from a third-party under an operating lease
and our ownership of these cranes has reduced our overall operating costs during
2003 and ensured crane availability.

   Competition. Our petroleum coke and other bulk terminals compete with
numerous independent terminal operators, other terminals owned by oil companies
and other industrials opting not to outsource terminal services. Competition
against the petroleum coke terminals that we operate but do not own has
increased significantly, primarily from companies that also market and sell the
product. This increased competition will likely decrease profitability in this
portion of the segment. Many of our other 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.

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   New Terminals

   Effective January 1, 2003, we acquired the assets of Rudolph Stevedoring for
approximately $31.3 million. On December 31, 2002, we paid $29.9 million for the
Rudolph acquisition and in the first quarter of 2003, we paid the remaining $1.4
million. The acquired operations serve various terminals located at the ports of
New York and Baltimore, along the Delaware River in Camden, New Jersey, and in
Tampa Bay, Florida. Combined, these facilities transload nearly four million
tons annually of products such as fertilizer, iron ore and salt.

   In December 2003, we acquired two bulk terminal facilities in Tampa, Florida
for an aggregate consideration of approximately $29.5 million, consisting of
$26.0 million in cash and $3.5 million in assumed liabilities. The principal
purchase was a marine terminal acquired from a subsidiary of IMC Global, Inc. We
also entered into a long-term agreement with IMC to enable it to be the primary
user of the facility, which we will operate and refer to as the Kinder Morgan
Tampaplex terminal. The terminal sits on a 114-acre site, and serves as a
storage and receipt point for imported ammonia, as well as an export location
for dry bulk products, including fertilizer and animal feed. The second facility
includes assets from the former Nitram, Inc. bulk terminal, which we plan to use
as an inland bulk storage warehouse facility for overflow cargoes from our Port
Sutton import terminal.

Major Customers

   Our total operating revenues are derived from a wide customer base. For each
of the years ended December 31, 2003, 2002 and 2001, one customer accounted for
more than 10% of our total consolidated revenues. Total transactions with
CenterPoint Energy accounted for 16.8% of our total consolidated revenues during
2003 and 15.6% of our total consolidated revenues during 2002. Total
transactions in 2001 with the Reliant Energy group of companies, including the
entities which became CenterPoint Energy in October 2002, accounted for 20.2% of
our total consolidated revenues. The high percentage of our total revenues
attributable to CenterPoint Energy directly relates to the growth of our Natural
Gas Pipelines segment, especially since our acquisition of Kinder Morgan Texas
Pipeline on December 31, 2000 and Kinder Morgan Tejas on January 31, 2002. Due
to these acquisitions and the subsequent formation of our Texas intrastate
natural gas group, we have realized significant increases in the volumes of
natural gas we buy and sell within the State of Texas. As a result, both our
total consolidated revenues and our total consolidated purchases (cost of sales)
have increased considerably since 2000 due to the inclusion of the cost of gas
in both financial statement line items. These higher revenues and higher
purchased gas cost do not necessarily translate into increased margins in
comparison to those situations in which we charge to transport gas owned by
others. 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 Regulation

   Some of our pipelines are interstate common carrier pipelines, subject to
regulation by the Federal Energy Regulatory Commission under the Interstate
Commerce Act. 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. 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. 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 as alternatives to the indexing approach in
certain specified circumstances. In addition, during the first quarter of 2003,
the FERC made a significant positive adjustment to the index which petroleum
products pipelines use to adjust their regulated tariffs for inflation. The old
index used percent growth in the producer price index for finished goods, and
then subtracted one percent. The new index eliminated the one percent reduction.
As a result, we have filed for rate adjustments on a number of our petroleum
products pipelines and have realized benefits from the new index beginning in
the second quarter of 2003. In 2002 and 2001, application of the indexing
methodology did not significantly affect rates on our petroleum products
pipelines.

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<PAGE>

   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 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 charge for transportation service on our North System and
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 Item 3.
Legal Proceedings.

   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 and, to a lesser extent, the Natural Gas Policy Act.

   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:

   o Order 436 (1985) requiring open-access, nondiscriminatory transportation of
     natural gas;

   o Order 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

   o Order 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:

   o requiring the unbundling of sales services from other services;

   o 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

   o 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.

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<PAGE>

   We are also subject to the requirements of FERC Order Nos. 497, et seq., and
566, et. seq., the Marketing Affiliate Rules, which prohibit preferential
treatment by an interstate natural gas pipeline of its marketing affiliates
and govern, in particular, the provision of information by an interstate natural
gas pipeline to its marketing affiliates. The FERC, in a Notice of Proposed
Rulemaking in RM01-10-000, has proposed standards of conduct to govern
interactions between interstate natural gas pipelines and electric transmission
utilities and their energy affiliates. These standards would entirely replace
the current standards of conduct related to affiliate interaction. Numerous
parties, including KMI's Natural Gas Pipeline Company of America, have filed
comments on the proposed rulemaking.

   FERC Order 637

   See Note 16 of the Notes to our Consolidated Financial Statements included
elsewhere in this report.

   Cash Management

   See Note 16 of the Notes to our Consolidated Financial Statements included
elsewhere in this report.

   Standards of Conduct Rulemaking

   See Note 16 of the Notes to our Consolidated Financial Statements included
elsewhere in this report.

   California Public Utilities Commission

   The intrastate common carrier operations of our Pacific operations' pipelines
in California are subject to regulation by the California Public Utilities
Commission 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 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 Item 3. Legal Proceedings.

   Safety Regulation

   Our interstate pipelines are subject to regulation by the United States
Department of Transportation and our intrastate pipelines are subject to
comparable state regulations with respect to their design, installation,
testing, construction, operation, replacement and management. We must permit
access to and copying of records, and make certain reports and provide
information as required by the Secretary of Transportation. 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 rail cars. We believe that we are in substantial compliance with
U.S. DOT and comparable state regulations.

   The Pipeline Safety Improvement Act of 2002 was signed into law on December
17, 2002, providing guidelines in the areas of testing, education, training and
communication. The 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. Pipeline companies are required
to perform the integrity tests within ten years of 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
consists of hydrostatic testing, internal electronic 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, using criteria the U.S. DOT is responsible for providing.
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
Operator Qualification Program, which is already

                                       36
<PAGE>

in place and functioning. 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.

   On March 25, 2003, the U.S. DOT issued their final rules on Hazardous
Materials: Security Requirements for Offerors and Transporters of Hazardous
Materials. We believe that we are in substantial compliance with these rules and
have made revisions to our Facility Security Plan to remain consistent with the
requirements of these rules. The revisions relate primarily to three areas:

   o training, the plan now incorporates provisions for conducting awareness
     level training and in-depth level training for employees working with
     hazardous materials;

   o hiring practices, the plan now includes provisions to verify information
     provided by job applicants; and

   o transportation route security, the plan now calls for verification from
     carriers that they have addressed route security from point of origin to
     destination.

   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 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:

   o marketing;

   o production;

   o pricing;

   o pollution;

   o protection of the environment; and

   o 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 and facilities are in substantial
compliance with applicable environmental laws and regulations. Any failure to
comply with these laws and regulations may result in the assessment of
administrative, civil and criminal penalties, imposition of remedial
requirements, issuance of injunction as to future compliance or other mandatory
or consensual measures. We have an ongoing environmental compliance program.
However, risks of accidental leaks or spills are associated with the
transportation and storage of natural gas liquids, refined petroleum products,
natural gas and carbon dioxide, the handling and storage of liquid and bulk
materials and the other activities conducted by us. There can be no assurance
that we will not incur significant costs and liabilities relating to claims for
damages to property, the environment, natural resources, or persons resulting
from the operation of our businesses. Moreover, it is possible that other
developments, such as

                                       37
<PAGE>

increasingly strict environmental laws and regulations and enforcement policies
thereunder, could result in increased costs and liabilities to us.

   Environmental laws and regulations have changed substantially and rapidly
over the last 25 years, and we anticipate that there will be continuing changes.
One trend in environmental regulation is to increase reporting obligations and
place more restrictions and limitations on activities, such as emissions of
pollutants, generation and disposal of wastes and use, storage and handling of
chemical substances, that may impact human health, the environment and/or
endangered species. Increasingly strict environmental restrictions and
limitations have resulted in increased operating costs for us and other similar
businesses throughout the United States. It is possible that the costs of
compliance with environmental laws and regulations may continue to increase. We
will attempt to anticipate future regulatory requirements that might be imposed
and to plan accordingly, but there can be no assurance that we will identify and
properly anticipate each such charge, or that our efforts will prevent material
costs, if any, from arising.

   We are currently involved in environmentally related legal proceedings and
clean up activities. 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 recorded a total reserve for environmental matters in the amount of $39.6
million as of December 31, 2003. For additional information related to
environmental matters, see Note 16 to our Consolidated Financial Statements
included elsewhere in this report.

   Solid Waste

   We own numerous properties that have been used for many years for the
production of crude oil, natural gas and carbon dioxide, the transportation and
storage of refined petroleum products and natural gas liquids and the handling
and storage of coal and other liquid and bulk materials. Solid waste disposal
practices within the petroleum industry have changed over the years with the
passage and implementation of various environmental laws and regulations.
Hydrocarbons and other solid wastes may have been disposed of in, on or under
various properties owned by us during the operating history of the facilities
located on such properties. In addition, some of these properties have been
operated by third parties whose treatment and disposal or release of
hydrocarbons or other solid wastes was not under our control. In such cases,
hydrocarbons and other solid wastes could migrate from their original disposal
areas and have an adverse effect on soils and groundwater. We maintain a reserve
to account for the costs of cleanup at sites known to have surface or subsurface
contamination requiring response action.

   We generate both hazardous and nonhazardous 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 nonhazardous waste. Furthermore, it is possible that some
wastes that are currently classified as nonhazardous, 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 nonhazardous 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, and analogous state laws, impose 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 of 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 material resource
damages, if any. Although "petroleum" is excluded from CERCLA's definition of a
"hazardous substance," in the course of our ordinary operations, we 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

                                       38
<PAGE>

part of the costs required to clean up sites at which such materials are
present, in addition to compensation for material resource damages, if any.

   Clean Air Act

   Our operations are subject to the Clean Air Act and comparable state
statutes. We believe that the operations of our pipelines, storage facilities
and terminals are in substantial compliance with such statutes.

   Numerous amendments to the Clean Air Act were adopted in 1990. These
amendments contain 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. The U.S. EPA is developing, over a
period of many years, regulations to implement those requirements. Depending on
the nature of those regulations, and upon requirements that may be imposed by
state and local regulatory authorities, we may be required to incur certain
capital 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 controversial nature of the regulations, full
development and implementation of many Clean Air Act regulations have been
delayed. Until such time as the new Clean Air Act requirements are implemented,
we are unable to estimate the effect on earnings or operations or the amount 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 strict 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 diking 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.

   EPA Gasoline Volatility Restrictions

   In order to control air pollution in the United States, the U.S. EPA has
adopted regulations that require the vapor pressure of motor gasoline sold in
the United States to be reduced from May through mid-September of each year.
These regulations mandated vapor pressure reductions beginning in 1989, with
more stringent restrictions beginning in 1992. States may impose additional
volatility restrictions. The regulations have had a substantial effect on the
market price and demand for normal butane, and to some extent isobutane, in the
United States. Gasoline manufacturers use butanes in the production of motor
gasolines. Since normal butane is highly volatile, it is now less desirable for
use in blended gasolines sold during the summer months. Although the U.S. EPA
regulations have reduced demand and may have contributed to a significant
decrease in prices for normal butane, low normal butane prices have not impacted
our pipeline business in the same way they would impact a business with
commodity price risk. The U.S. EPA regulations have presented the opportunity
for additional transportation services on our North System. In the summer of
1991, our North System began long-haul transportation of refinery grade normal
butane produced in the Chicago area to the Bushton, Kansas area for storage and
subsequent transportation north from Bushton during the winter gasoline blending
season.

   Methyl Tertiary-Butyl Ether

   Methyl tertiary-butyl ether (MTBE) is used as an additive in gasoline. It is
manufactured by chemically combining a portion of petrochemical production with
purchased methanol. Due to environmental and health concerns, California
mandated the elimination of MTBE from gasoline by January 1, 2004. Furthermore,
both the

                                       39
<PAGE>

United States House of Representatives and the United States Senate introduced
legislation in 2003 that would bar the use of MTBE within four years of
enactment. Both bills contain provisions that would gradually phase out the
use of MTBE as a gasoline blendstock. We cannot provide assurances regarding the
likelihood of the passage of either of these bills in any form.

   In California, MTBE-blended gasoline has been replaced by an ethanol blend.
However, ethanol cannot be shipped through pipelines and therefore, we will
realize some reduction in California gasoline volumes transported by our Pacific
operations' pipelines. The conversion from MTBE to ethanol in California has
resulted in an increase in ethanol blending services at refined petroleum
product terminal facilities, and we believe the fees we earn for new
ethanol-related services at our terminals will more than offset the expected
reduction in pipeline transportation fees. Furthermore, we have aggressively
pursued additional ethanol opportunities.

   Our role in conjunction with ethanol is proving beneficial to our various
business segments as follows:

   o our Products Pipelines' terminals are blending ethanol because unlike MTBE,
     it cannot flow through pipelines;

   o our Natural Gas Pipelines segment is delivering natural gas through our
     pipelines to service new ethanol plants that are being constructed in the
     Midwest (natural gas is the feedstock for ethanol plants); and

   o our Terminals segment is entering into liquid storage agreements for
     ethanol around the country, in such areas as Houston, Nebraska and on the
     East Coast.

Risk Factors

   Like all businesses, we face various obstacles, including rising legal fees,
environmental issues and escalating employee health and benefit costs.
Regulatory challenges to our pipeline transportation rates, including the
current case involving our Pacific operations' pipelines, and possible policy
changes and/or reparation and refund payments ordered by governmental regulatory
entities could negatively affect our future financial performance.

   Further, we are well-aware of the general uncertainty associated with the
current world economic and political environments in which we exist and we
recognize that we are not immune to the fact that 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 at 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 reasonable rates throughout 2004. Currently, we
do not believe that the increased cost associated with these measures will have
a material effect on our operating results.

   Some of our specifically identified risk factors include the following:

   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, 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. In 1992, and from 1995
through 2001, some shippers on our pipelines 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.

   The FERC complaints, separately docketed in two different proceedings,
predominantly attacked the interstate pipeline tariff rates of our Pacific
operations' pipeline system, contending that the rates were not just and
reasonable under the Interstate Commerce Act and should not be entitled to
"grandfathered" status under the Energy Policy Act. Hearings on the second of
these two proceedings began in October 2001.

   On June 24, 2003, a non-binding, phase one initial decision was issued by an
administrative law judge hearing a FERC case on the rates charged by our Pacific
operations' interstate portion of its pipelines. In his phase one initial
decision, the administrative law judge recommended that the FERC "ungrandfather"
our Pacific operations'

                                       40
<PAGE>

interstate rates and found most of our Pacific operations'rates at issue to be
unjust and unreasonable. The administrative law judge has indicated that a phase
two initial decision will address prospective rates and whether reparations are
necessary. Initial decisions have no force or effect and must be reviewed by the
FERC. The FERC is not obliged to follow any of the administrative law judge's
findings and can accept or reject this initial decision in whole or in part. If
the FERC ultimately finds that these rates should be "ungrandfathered" and are
unjust and unreasonable, they could be lowered prospectively and complaining
shippers could be entitled to reparations for prior periods. Ultimate resolution
of phase one and phase two of this matter by the FERC is not expected before
early 2005.

   The complaints filed before the CPUC challenge the rates charged for
intrastate transportation of refined petroleum products through our Pacific
operations' pipeline system in California. After the CPUC dismissed the initial
complaint and subsequently granted a limited rehearing on April 10, 2000, the
complainants filed a new complaint with the CPUC asserting the intrastate rates
were not just and reasonable.

   We currently believe the FERC complaints seek approximately $154 million in
tariff reparations and prospective annual tariff reductions, the aggregate
average annual impact of which would be approximately $45 million. We currently
believe the CPUC complaints seek approximately $15 million in tariff reparations
and prospective annual tariff reductions, the aggregate average annual impact of
which would be approximately $31 million. If any amounts are ultimately owed, it
will be impacted by the passage of time and the application of interest.
Decisions regarding these complaints could negatively impact our cash flow.
Additional challenges to tariff rates could be filed with the FERC and CPUC in
the future. For additional information regarding these complaints, please see
Note 16 of the Notes to the Consolidated Financial Statements included elsewhere
in this report.

   Proposed rulemaking by the Federal Energy Regulatory Commission or other
regulatory agencies having jurisdiction could adversely impact our income and
operations. New regulations or different interpretations of existing regulations
applicable to our assets could have a negative impact on our business, financial
condition and results of operations. For example, on September 27, 2001, the
FERC issued a Notice of Proposed Rulemaking in Docket No. RM01-10. The proposed
rule would expand the FERC's current standards of conduct to include a regulated
transmission provider and all of its energy affiliates. It is not known whether
the FERC will issue a final rule in this docket and, if it does, whether as a
result we could incur increased costs and increased difficulty in our
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. For example, federal legislation
signed into law in December 2002 includes guidelines for the U.S. DOT and
pipeline companies in the areas of testing, education, training and
communication. Compliance with existing and recently enacted regulations
requires significant expenditures. Additional laws and regulations that may be
enacted in the future, such as U.S. DOT implementation of additional hydrostatic
testing requirements, could significantly increase the amount of these
expenditures.

   Our rapid growth may cause difficulties integrating 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 that will
allow us to increase distributions to our unitholders. If we do no successfully
integrate acquisitions, 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:

   o demands on management related to the increase in our size after an
     acquisition;

   o the diversion of our management's attention from the management of daily
     operations;

   o difficulties in implementing or unanticipated costs of accounting,
     estimating, reporting and other systems;

   o difficulties in the assimilation and retention of employees; and

   o potential adverse effects on operating results.

   We may not be able to maintain the levels of operating efficiency that
acquired companies will have achieved or might achieve separately. Successful
integration of each of their operations will depend upon our ability to manage

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<PAGE>

those operations and to eliminate redundant and excess costs. Because of
difficulties in combining 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 requires 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 that will allow us to
increase distributions to our unitholders. During the period from December 31,
1996 to December 31, 2003, we made a significant number of acquisitions that
increased our asset base over 30 times and increased our net income over 58
times. We regularly consider and enter into discussions regarding potential
acquisitions and are currently contemplating potential acquisitions. These
transactions can be effected quickly, may occur at any time and may be
significant in size relative to our existing assets and operations. 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 equity and debt offerings. 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. One of the
factors that increases our attractiveness to investors, and as a result may make
it easier for us to access the capital markets, is the fact that distributions
to our partners are not subject to the double taxation that shareholders in
corporations may experience with respect to dividends that they receive. The
Jobs and Growth Tax Relief Reconciliation Act of 2003 generally reduces the
maximum tax rate on dividends paid by corporations to individuals to 15% in 2003
and, for taxpayers in the 10% and 15% ordinary income tax brackets, to 5% in
2003 through 2007 and to zero in 2008. This legislation may cause some
investments in corporations to be more attractive to individual investors than
they used to be when compared to an investment in partnerships, thereby
exerting downward pressure on the market price of our common units and
potentially making it more difficult for us to access the capital markets.

   Environmental regulation could result in increased operating and capital
costs for us. Our business operations are subject to federal, state and local
laws and regulations relating to environmental protection. If an accidental leak
or spill of liquid petroleum products or chemicals occurs from our pipelines or
at our storage facilities, we may have to pay a significant amount to clean up
the leak or spill or pay for government penalties, liability to government
agencies for natural resource damage, personal injury or property damage to
private parties or significant business interruption. The resulting costs and
liabilities could negatively affect our level of cash flow. In addition,
emission controls required under the Federal Clean Air Act and other similar
federal and state laws could require significant capital expenditures at our
facilities. The impact on us of Environmental Protection Agency standards or
future environmental measures could increase our costs significantly if
environmental laws and regulations become stricter. The costs of environmental
regulation are already significant, and additional regulation could increase
these costs or could otherwise negatively affect our business.

   Competition could ultimately lead to lower levels of profits and lower cash
flow. We face competition from other pipelines and terminals in the same markets
as our assets, as well as from other means of transporting and storing energy
products. For a description of the competitive factors facing our business,
please see Items 1 and 2 "Business and Properties" in this report for more
information.

   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 the pipelines
on other people's land for a period of time. If we were to lose these rights,
our business could be affected negatively.

   Southern Pacific Transportation Company has allowed us to construct and
operate a significant portion of our Pacific operations' pipeline system on
railroad rights-of-way. Southern Pacific Transportation Company and its
predecessors were given the right to construct their railroad tracks under
federal statutes enacted in 1871 and 1875. The 1871 statute was thought to be an
outright grant of ownership that would continue until the land ceased to be used
for railroad purposes. Two United States Circuit Courts, however, ruled in 1979
and 1980 that railroad rights-of-way granted under laws similar to the 1871
statute provide only the right to use the surface of the land for railroad
purposes without any right to the underground portion. If a court were to rule
that the 1871 statute does not permit the use of the underground portion for the
operation of a pipeline, we may be required to obtain permission from the
landowners in order to continue to maintain the pipelines. Approximately 10% of
our pipeline assets are located in the ground underneath railroad rights-of-way.

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   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.

   We could be treated as a corporation for United States income tax purposes.
Our treatment as a corporation would substantially reduce the cash distributions
on the common units that we distribute quarterly. The anticipated benefit of an
investment in our common units depends largely on the treatment of us as a
partnership for federal income tax purposes. 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. Current law requires us to derive at least 90% of our
annual gross income from specific activities to continue to be treated as a
partnership for federal income tax purposes. We may not find it possible,
regardless of our efforts, to meet this income requirement or may inadvertently
fail to meet this income requirement. Current law may change so as to cause us
to be treated as a corporation for federal income tax purposes without regard to
our sources of income or otherwise subject us to entity-level taxation.

   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 unitholders would generally be taxed as a
corporate distribution. Because a tax would be imposed upon us as a corporation,
the cash available for distribution to a unitholder would
be substantially reduced. Treatment of us as a corporation would cause a
substantial reduction in the value of our units.

   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:

   o incurring additional debt;

   o entering into mergers, consolidations and sales of assets;

   o granting liens; and

   o 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.

   If interest rates increase, our earnings could be adversely affected. As of
December 31, 2003, we had approximately $2.4 billion of debt, excluding market
value of interest rate swaps, subject to variable interest rates. Approximately
$2.0 billion of this debt was long-term fixed rate debt converted to floating
rate debt through the use of interest rate swaps. Should interest rates increase
significantly, our earnings could be adversely affected.

   The distressed financial condition of some of our 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 severe financial
problems. The bankruptcy of one or more of them, 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.

   In addition, some of our customers are experiencing severe financial problems
that have had a significant impact on their creditworthiness. We are working to
implement, to the extent allowable under applicable contracts, tariffs and
regulations, prepayments and other security requirements, such as letters of
credit, to enhance our credit position

                                       43
<PAGE>

relating to amounts owed from these customers. 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.

   The interests of KMI may differ from our interest and the interests of our
unitholders. KMI 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 KMI and our general partner and have
fiduciary duties to manage the businesses of KMI in a manner that may not be in
the best interest of our unitholders. KMI 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.

   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.

Other

   We do not have any employees.  KMGP Services Company, Inc. and Kinder Morgan,
Inc. employ all persons necessary for the operation of our business. Generally
we reimburse KMGP Services Company, Inc. and Kinder Morgan, Inc. for the
services of their employees. As of December 31, 2003, KMGP Services Company,
Inc. and Kinder Morgan, Inc. had, in the aggregate, approximately 5,539
employees. Approximately 997 hourly personnel at certain terminals and pipelines
are represented by labor unions. KMGP Services Company, Inc. and Kinder Morgan,
Inc. consider relations with their employees to be good. For more information on
our related party transactions, see Note 12 of the Notes to the Consolidated
Financial Statements included elsewhere in this report.

   We are of the opinion 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 therein
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.
Amounts we have spent during 2003, 2002 and 2001 on research and development
activities were not material.

(d) Financial Information about Geographic Areas

   The amount of our assets and operations that are located outside of the
continental United States of America are not material.

(e) Available Information

   We make available free of charge on or through our Internet website, at
http://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.


                                       44
<PAGE>


Item 3.  Legal Proceedings.

   See Note 16 of the Notes to the 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 2003.



                                       45
<PAGE>


                                     PART II

Item 5.  Market for Registrant's Common Equity and Related Stockholder Matters.

   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
                            ------------------        Cash             i-unit
                             High         Low    Distributions     Distributions
                            -------     -------  -------------    -------------
       2003
       First Quarter         $ 37.00    $ 34.25   $ 0.6400           0.018488
       Second Quarter          40.00      36.55      0.6500            0.017138
       Third Quarter           42.80       39.01     0.6600            0.016844
       Fourth Quarter          49.69      42.84      0.6800            0.015885

       2002
       First Quarter         $ 38.65    $ 28.60   $ 0.5900           0.016969
       Second Quarter          36.55      30.98      0.6100            0.019596
       Third Quarter           33.90       28.00     0.6100            0.020969
       Fourth Quarter          35.45      30.15      0.6250            0.018815

   All of the 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 that we will continue to pay comparable cash
and i-unit distributions in the future assuming no adverse change in our
operations, economic conditions and other factors. However, we can give no
assurance that future distributions will continue at such levels.

   As of February 12, 2004, there were approximately 141,000 beneficial owners
of our common units, 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 the fourth quarter of 2003.


                                       46
<PAGE>

Item 6.  Selected Financial Data

   The following tables set forth, for the periods and at the dates indicated,
summary historical financial and operating data for us. 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.

<TABLE>
<CAPTION>
                                                                             Year Ended December 31,
                                                        --------------------------------------------
                                                           2003(3)       2002(4)      2001(5)       2000(6)      1999(7)
                                                        -----------   -----------  -----------  -----------  ----------
                                                                     (In thousands, except per unit data)
<S>                                                      <C>           <C>           <C>           <C>           <C>
Income and Cash Flow Data:
Revenues............................................    $ 6,624,322  $ 4,237,057  $ 2,946,676  $   816,442  $   428,749
Cost of product sold................................       4,880,118    2,704,295     1,657,689      124,641        16,241
Operating expense...................................         459,936      427,805       396,354      182,445       104,970
Fuel and power......................................         108,112        86,413       73,188        43,216       31,745
Depreciation, depletion and amortization............         219,032      172,041       142,077       82,630        46,469
General and administrative..........................         150,435      122,205       113,540       67,949        41,917
                                                        -----------   -----------  -----------  -----------  -----------
Operating income....................................         806,689      724,298       563,828      315,561       187,407
Earnings from equity investments....................          92,199        89,258       84,834        71,603       42,918
Amortization of excess cost of equity investments...          (5,575)       (5,575)      (9,011)       (8,195)      (4,254)
Interest expense....................................        (182,777)    (178,279)     (175,930)     (97,102)      (54,336)
Interest income and other, net......................             (33)       (6,042)      (5,005)       10,415       20,393
Income tax provision................................         (16,631)     (15,283)      (16,373)     (13,934)       (9,826)
                                                        -----------   -----------  -----------  -----------  -----------
Income before cumulative effect  of a change in
   accounting principle.............................         693,872      608,377       442,343      278,348       182,302
Cumulative effect of a change in accounting
   principle........................................           3,465            --            --            --            --
                                                        -----------   -----------  -----------  -----------  -----------
Net income..........................................    $    697,337  $   608,377  $   442,343  $    278,348  $   182,302
General Partner's interest in net income............         326,524      270,816       202,095      109,470        56,273
Limited Partners' interest in net income............    $    370,813  $   337,561  $   240,248  $    168,878  $   126,029

Basic and Diluted Limited Partners' Net Income per
unit:
Income before cumulative effect  of a change in
   accounting principle(1)..........................    $       1.98  $      1.96  $       1.56  $      1.34  $       1.29
Cumulative effect of a change in accounting
   principle........................................            0.02            --            --            --            --
                                                        -----------   -----------  -----------  -----------  -----------
Net income..........................................    $       2.00  $      1.96  $       1.56  $      1.34  $       1.29

Per unit cash distribution paid.....................    $       2.58  $      2.36  $       2.08  $      1.60  $       1.39
Additions to property, plant and equipment..........    $    576,979  $   542,235  $   295,088  $    125,523  $    82,725

Balance Sheet Data (at end of period):
Net property, plant and  equipment                       $ 7,091,558  $ 6,244,242  $ 5,082,612  $ 3,306,305  $ 2,578,313
Total assets...............                              $ 9,139,182  $ 8,353,576  $ 6,732,666  $ 4,625,210  $ 3,228,738
Long-term debt(2)..........                              $ 4,316,678  $ 3,659,533  $ 2,237,015  $ 1,255,453  $    989,101
Partners' capital..........                              $ 3,510,927  $ 3,415,929  $ 3,159,034  $ 2,117,067  $ 1,774,798
----------
</TABLE>


(1)  Represents income before cumulative effect of a change in accounting
     principle per unit adjusted for the two-for-one split of units on August
     31, 2001. Basic Limited Partners' income per unit before cumulative effect
     of a change in accounting principle was computed by dividing the interest
     of our unitholders in income 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 potential dilution, by application of the treasury stock method, that
     could occur if options to issue units were exercised, which would result in
     the issuance of additional units that would then share in our net income.

(2)  Excludes market value of interest rate swaps.

(3)  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 on January 1,
     2003. The additional 12.75% interest in SACROC was acquired on June 1,
     2003. The five refined petroleum products terminals were acquired October
     1, 2003. The additional 42.5% interest in the Yates field unit, the Yates
     gathering system

                                       47
<PAGE>


     and the additional 65% interest in Pecos Carbon Dioxide Company were
     acquired on 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 on December 10 and 23,
     2003.

(4)  Includes results of operations for the additional 10% interest in the
     Cochin Pipeline System, Kinder Morgan Materials Services LLC (formerly
     Laser Materials Services LLC), the 66 2/3% interest in International Marine
     Terminals, Tejas Gas, LLC, Milwaukee Bagging Operations, the remaining 33
     1/3% interest in Trailblazer Pipeline Company, the Owensboro Gateway
     Terminal and IC Terminal Holdings Company and Consolidated Subsidiaries
     since dates of acquisitions. The additional interest in Cochin was acquired
     on December 31, 2001. Kinder Morgan Materials Services LLC was acquired on
     January 1, 2002. We acquired a 33 1/3% interest in International Marine
     Terminals on January 1, 2002 and an additional 33 1/3% interest on February
     1, 2002. Tejas Gas, LLC was acquired on January 31, 2002. The Milwaukee
     Bagging Operations were acquired on May 1, 2002. The remaining interest in
     Trailblazer was acquired on May 6, 2002. The Owensboro Gateway Terminal and
     IC Terminal Holdings Company and Subsidiaries were acquired on September 1,
     2002.

(5)  Includes results of operations for the remaining 50% interest in the Colton
     Processing Facility, Kinder Morgan Texas Pipeline, Casper and Douglas gas
     gathering assets, 50% interest in Coyote Gas Treating, LLC, 25% interest in
     Thunder Creek Gas Services, LLC, Central Florida Pipeline LLC, Kinder
     Morgan Liquids Terminals LLC, Pinney Dock & Transport LLC, CALNEV Pipe Line
     LLC, 34.8% interest in the Cochin Pipeline System, Vopak terminal LLCs,
     Boswell terminal assets, Stolt-Nielsen terminal assets and additional
     gasoline and gas plant interests since dates of acquisition. The remaining
     interest in the Colton Processing Facility, Kinder Morgan Texas Pipeline,
     Casper and Douglas gas gathering assets and our interests in Coyote and
     Thunder Creek were acquired on December 31, 2000. Central Florida and
     Kinder Morgan Liquids Terminals LLC were acquired January 1, 2001. Pinney
     Dock was acquired March 1, 2001. CALNEV was acquired March 30, 2001. Our
     second investment in Cochin, representing a 2.3% interest, was made on June
     20, 2001. Vopak terminal LLCs were acquired July 10, 2001. Boswell
     terminals were acquired August 31, 2001. Stolt-Nielsen terminals were
     acquired on November 8 and 29, 2001, and our additional interests in the
     Snyder Gasoline Plant and the Diamond M Gas Plant were acquired on November
     14, 2001.

(6)  Includes results of operations for Kinder Morgan Interstate Gas
     Transmission, 66 2/3% interest in Trailblazer, 49% interest in Red Cedar,
     Milwaukee Bulk Terminals, Dakota Bulk Terminal, remaining 80% interest in
     Kinder Morgan CO2 Company, L.P., Devon Energy carbon dioxide properties,
     Kinder Morgan Transmix Company, LLC, a 32.5% interest in Cochin Pipeline
     System and Delta Terminal Services LLC since dates of acquisition. Kinder
     Morgan Interstate Gas Transmission, Trailblazer assets, and our 49%
     interest in Red Cedar were acquired on December 31, 1999. Milwaukee Bulk
     Terminals, Inc. and Dakota Bulk Terminal, Inc. were acquired on January 1,
     2000. The remaining 80% interest in Kinder Morgan CO2 Company, L.P. was
     acquired April 1, 2000. The Devon Energy carbon dioxide properties were
     acquired June 1, 2000. Kinder Morgan Transmix Company, LLC was acquired on
     October 25, 2000. Our 32.5% interest in Cochin was acquired on November 3,
     2000, and Delta Terminal Services LLC was acquired on December 1, 2000.

(7)  Includes results of operations for 51% interest in Plantation Pipe Line
     Company, Products Pipelines' initial transmix operations and 33 1/3%
     interest in Trailblazer Pipeline Company since dates of acquisition. Our
     second investment in Plantation, representing a 27% interest was made on
     June 16, 1999. The Products Pipelines' initial transmix operations were
     acquired on September 10, 1999, and our initial 33 1/3% investment in
     Trailblazer was made on November 30, 1999.


                                       48
<PAGE>

Item 7.  Management's Discussion and Analysis of Financial Condition and Results
of Operations.

   Our discussion and analysis of our financial condition and results of
operations are based on our Consolidated Financial Statements, which were
prepared in accordance with accounting principles generally accepted in the
United States of America. You should read the following discussion and analysis
in conjunction with our Consolidated Financial Statements included elsewhere in
this report.

   Additional sections in this report which should be helpful to your reading of
our Management Discussion include the following:

   o a description of our business strategy and management philosophy, found in
     Items 1 and 2 "Business and Properties-Business Strategy";

   o a description of recent developments during 2003, found in Items 1 and 2
     "Business and Properties-Recent Developments"; and

   o a description of our risk factors, found in Items 1 and 2 "Business and
     Properties-Risk Factors."

Critical Accounting Policies and Estimates

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 assets and liabilities and our
disclosure of contingent assets and liabilities at the date of the 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.

   In preparing our financial statements and related disclosures, we must use
estimates in determining the economic useful lives of our assets, the fair
values used to determine possible asset impairment charges, provisions for
uncollectible accounts receivable, exposures under contractual indemnifications
and various other recorded or disclosed amounts. However, we believe that
certain accounting policies covering the matters discussed below are of more
significance in our financial statement preparation process than others.

   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. 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. In
December 2002, after a thorough review of potential environmental issues that
could impact our assets or operations, we recognized a $0.3 million reduction in
environmental expense and in our overall accrued environmental liability, and we
included this amount within Other, net in the accompanying Consolidated
Statement of Income for 2002. The $0.3 million income item resulted from
adjusting and realigning our environmental expenses and accrued liabilities
between our reportable business segments, specifically between our Products
Pipelines and our Terminals business segments. The $0.3 million reduction in
environmental expense resulted from a $15.7 million loss in our Products
Pipelines business segment and a $16.0 million gain in our Terminals business
segment.

   Legal Matters

   With respect to legal proceedings, 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. To
the extent that actual outcomes differ from

                                       49
<PAGE>

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.

   SFPP, L.P. is the subsidiary limited partnership that owns our Pacific
operations, excluding CALNEV Pipe Line LLC and related terminals acquired from
GATX Corporation. Tariffs charged by SFPP are subject to certain proceedings at
the Federal Energy Regulatory Commission involving shippers' complaints
regarding the interstate rates, as well as practices and the jurisdictional
nature of certain facilities and services, on our Pacific operations' pipeline
systems. 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. We currently
believe that these FERC complaints seek approximately $154 million in tariff
reparations and prospective annual tariff reductions, the aggregate average
annual impact of which would be approximately $45 million. However, even if
"substantially changed circumstances" are found to exist, we believe that the
resolution of these FERC complaints will be for amounts substantially less than
the amounts sought. For more information on our Pacific operations' regulatory
proceedings, see Note 16 to the Consolidated Financial Statements included
elsewhere in this report.

   Intangible Assets

   With respect to goodwill and other intangible assets having indefinite useful
economic lives, effective January 1, 2002, we adopted 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 required us to prospectively cease amortizing all of our intangible
assets having indefinite useful economic lives, including goodwill. Such assets
are not to be amortized until their lives are determined to be finite. The new
rules also impact future period net income by an amount equal to the
discontinued goodwill amortization offset by goodwill impairment charges, if
any, and adjusted for any differences between the old and new rules for defining
intangible assets on future business combinations. Additionally, a recognized
intangible asset with an indefinite useful life should 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 completed
this initial transition impairment test in June 2002 and determined that our
goodwill was not impaired as of January 1, 2002. 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, 2004. As of January 1, 2004, our
goodwill was $729.5 million.

Results of Operations
<TABLE>
<CAPTION>
                                                              Year Ended December 31,
                                                      ------------------------------------
                                                         2003          2002          2001
                                                      ----------    ----------   ----------
                                                                  (In thousands)
<S>                                                    <C>           <C>           <C>
  Earnings before depreciation, depletion and
    amortization expense and amortization of excess
    cost of equity investments
    Products Pipelines.............................   $   441,600   $  411,604   $  383,920
    Natural Gas Pipelines..........................       373,350      325,454       226,770
    CO2............................................       203,599      132,196       111,666
    Terminals......................................       240,776      224,963       167,512
                                                      ----------    ----------   ----------
      Segment earnings before DD&A and amort. of
        excess cost of equity investments(a).......     1,259,325    1,094,217       889,868

    Total consolidated DD&A expense................      (219,032)    (172,041)    (142,077)
    Total consolidated amort. of excess cost of
      invests......................................        (5,575)      (5,575)       (9,011)
    Interest and corporate administrative
      expenses(b)..................................      (337,381)    (308,224)    (296,437)
                                                      ----------    ----------   ----------
      Net income...................................   $   697,337   $  608,377   $  442,343
                                                      ==========    ==========   ==========
----------
</TABLE>


(a)  Includes  revenues,  earnings  from equity  investments,   income  taxes and
     other, net, less operating expenses.

                                       50
<PAGE>

(b)  Includes interest and debt expense,  general and  administrative   expenses,
     minority interest expense and cumulative effect adjustment from a change in
     accounting principle (2003 only).


   In 2003, we again achieved record levels of net income, earnings per unit,
earnings before depreciation, depletion and amortization, and revenues. The
fiscal year ended December 31, 2003 marked the sixth successive year since the
change in control of our general partner in February 1997 that we have improved
on all four of these operating measures.

   In 2003, our net income was $697.3 million ($2.00 per diluted unit) on
revenues of $6,624.3 million, compared to net income of $608.4 million ($1.96
per diluted unit) on revenues of $4,237.1 million in 2002, and net income of
$442.3 million ($1.56 per diluted unit) on revenues of $2,946.7 million in 2001.
In 2003, we benefited from a cumulative effect adjustment of $3.4 million
related to a change in accounting for asset retirement obligations pursuant to
our adoption of Statement of Financial Accounting Standards No. 143, "Accounting
for Asset Retirement Obligations" on January 1, 2003. Our 2003 income before the
cumulative effect adjustment totaled $693.9 million ($1.98 per diluted unit).
For more information on this cumulative effect adjustment from a change in
accounting principle, see Note 4 to our Consolidated Financial Statements,
included elsewhere in this report. Equity earnings from our investments
accounted for under the equity method of accounting, net of expense from
amortization of excess investment costs, were $86.6 million in 2003, $83.7
million in 2002 and $75.8 million in 2001.

   Because our partnership agreement requires us to distribute 100% of our
available cash to our partners on a quarterly basis, we look at each period's
earnings before all non-cash depreciation, depletion and amortization expenses
(including amortization of excess cost of equity investments) as an important
measure of our success in maximizing returns to our partners. Available cash, as
defined in our partnership agreement, consists primarily of all cash receipts,
less cash disbursements and net additions to reserves. Our general partner and
our common and Class B unitholders receive quarterly distributions in cash,
while KMR, the sole owner of our i-units, receives quarterly distributions in
additional i-units. The value of the quarterly per-share distribution of i-units
is based on the value of the quarterly per-share cash distribution made to our
common and Class B unitholders.

   In both 2003 and 2002, all four of our reportable business segments reported
year-to-year increases in earnings before depreciation, depletion and
amortization. The increases in our earnings before depreciation, depletion and
amortization in 2003 over 2002 were primarily due to higher earnings from our
CO2 and Natural Gas Pipelines business segments. Our CO2 segment benefited from
both increased activity in oil field operations and the acquisition of
additional working interests in oil producing properties. These acquisitions
included the following:

   o effective June 1, 2003, we acquired MKM Partners, L.P.'s 12.75% ownership
     interest in the SACROC oil field unit for $23.3 million and the assumption
     of $1.9 million of liabilities. This transaction increased our ownership
     interest in the SACROC unit to approximately 97%; and

   o effective November 1, 2003, we acquired certain assets in the Permian Basin
     of West Texas from a subsidiary of Marathon Oil Corporation for $231.0
     million and the assumption of $28.0 million of liabilities. The assets
     acquired included Marathon's approximate 42.5% interest in the Yates oil
     field unit, the crude oil gathering system surrounding the Yates field and
     Marathon's 65% ownership interest in the Pecos Carbon Dioxide Pipeline
     Company. This transaction increased our ownership interest in the Yates
     unit to nearly 50% and allowed us to become operator of the field.

   Our Natural Gas Pipelines segment benefited from increases in natural gas
transportation, storage and sales activities. This increase was primarily due to
the further integration of our Kinder Morgan Tejas and Kinder Morgan Texas
Pipeline systems, and to our newly completed North Texas and Mier-Monterrey,
Mexico pipeline systems. We acquired Kinder Morgan Tejas, formerly Tejas Gas,
LLC, effective January 31, 2002. Our North Texas and Mier-Monterrey pipeline
systems began operations in August 2002 and March 2003, respectively. We also
benefited from the inclusion of a full year of expanded operations on our
Trailblazer Pipeline. In May 2002, we completed an expansion project that
increased Trailblazer's transportation capacity by approximately 60%. The
acquisition, construction and subsequent integration of all of our natural gas
related operations, especially within and around the State of Texas, has
resulted in an integrated and valuable portfolio of natural gas businesses.

                                       51
<PAGE>

   The increase in total segment earnings before depreciation, depletion and
amortization in 2002 over 2001 was primarily due to higher earnings from our
Natural Gas Pipelines and Terminals business segments. The increase was
attributable to both solid internal growth and to contributions from acquired
assets. Our significant acquisitions included the purchase of Kinder Morgan
Tejas, as well as the acquisition of various bulk and liquid terminal businesses
acquired since the end of 2001. For more information on our acquisitions, please
see Note 3 to our Consolidated Financial Statements, included elsewhere in this
report.

   Additionally, we declared a record cash distribution of $0.68 per unit for
the fourth quarter of 2003 (an annualized rate of $2.72). Our distribution for
the fourth quarter of 2003 was 9% higher than the $0.625 per unit distribution
we made for the fourth quarter of 2002, and 24% higher than the $0.55 per unit
distribution we made for the fourth quarter of 2001. We expect to declare cash
distributions of at least $2.84 per unit for 2004, however, no assurance can be
given that we will be able to achieve this level of distribution.

<TABLE>
<CAPTION>
   Products Pipelines
                                                                 Year Ended December 31,
                                                      ---------------------------------------------
                                                           2003             2002            2001
                                                      -------------    -------------   -------------
                                                       (In thousands, except operating statistics)
<S>                                                    <C>              <C>              <C>
    Revenues.......................................   $      585,376   $     576,542    $     605,392
    Operating expenses(a)..........................         (169,526)        (169,782)        (240,537)
    Earnings from equity investments...............           30,948           28,998           28,278
    Other, net(b)..................................            6,471          (14,000)             440
    Income taxes...................................          (11,669)         (10,154)          (9,653)
                                                      -------------    -------------   -------------
      Earnings before DD&A and amort. of excess
        cost of equity investments.................          441,600          411,604          383,920

    Depreciation, depletion and amortization expense         (67,345)         (64,388)         (65,864)
    Amortization of excess cost of equity
     investments...................................           (3,281)          (3,281)          (5,592)
                                                      -------------    -------------   -------------
      Segment earnings.............................   $      370,974   $     343,935    $     312,464
                                                      =============    =============   =============

    Refined product volumes (MMBbl)................            723.7            733.0            724.6
    Natural gas liquids (MMBbl)....................             42.2             44.4             45.5
                                                       ------------     ------------    ------------
    Total delivery volumes (MMBbl)(c)..............            765.9            777.4            770.1
                                                       ============     ============    ============
</TABLE>

----------

(a)  Includes costs of sales, operations and maintenance expenses, fuel and
     power expenses and taxes, other than income taxes.
(b)  Amounts for 2002 include environmental expense adjustments resulting in a
     $15.7 million loss to our Products Pipelines business segment and a $16.0
     million gain to our Terminals business segment.
(c)  Includes Pacific, Plantation, North System, CALNEV, Central Florida,
     Cypress and Heartland pipeline volumes.

   Our Products Pipelines segment reported earnings before depreciation,
depletion and amortization of $441.6 million on revenues of $585.4 million in
2003. This compared to earnings before depreciation, depletion and amortization
of $411.6 million on revenues of $576.5 million in 2002 and earnings before
depreciation, depletion and amortization of $383.9 million on revenues of $605.4
million in 2001.

                                       52
<PAGE>

   As noted in the table above, the segment's 2002 earnings include a $15.7
million loss from the adjustment and realignment of our environmental
liabilities referred to above in our "Critical Accounting Policies and
Estimates." Excluding this 2002 environmental loss, segment earnings before
depreciation, depletion and amortization increased $14.3 million (3%) in 2003
compared to 2002. This increase resulted from higher earnings from our Pacific
operations, North System, CALNEV Pipe Line LLC, Transmix operations, Central
Florida Pipeline, our approximate 51% ownership interest in Plantation Pipe Line
Company and our West Coast product terminals. Earnings in 2003 were positively
impacted by higher revenues, mainly from fees for ethanol blending services at
our Pacific operations and West Coast terminals and revenues from product
deliveries related to overall strong demand for diesel fuel. The overall
increase was offset by lower earnings before depreciation, depletion and
amortization from both our 44.8% ownership interest in the Cochin pipeline
system and our Cypress Pipeline mainly due to lower operating revenues. In
addition, due to the continuing process of converting from methyl tertiary-butyl
ether (MTBE) to ethanol in the State of California, we realized a small
reduction in California gasoline volumes. MTBE-blended gasoline is being
replaced by an ethanol blend and ethanol is not shipped in our pipelines;
however, fees that we earn from ethanol-related services at our terminals
positively contribute to our earnings. As of December 31, 2003, we had ethanol
blending facilities in place at all of our California terminals necessary to
serve all of our customers. We do not anticipate that the switch to ethanol from
MTBE will have a material adverse effect on our Products Pipeline segment.

   Excluding the 2002 environmental loss, segment earnings before depreciation,
depletion and amortization increased $43.4 million (11%) in 2002 compared to
2001. All of our Products Pipelines businesses reported year-over-year
increases, with the exception of Plantation, where earnings were essentially
flat across both years. The overall increase was driven by higher earnings
before depreciation, depletion and amortization from our CALNEV pipeline and
terminal operations, where we benefited from including a full year of operations
in 2002 versus nine months in 2001. We acquired CALNEV Pipe Line LLC on March
30, 2001. In addition to CALNEV, we realized higher earnings before
depreciation, depletion and amortization expenses in 2002 compared to 2001 from
all of the following businesses: our proportionate interest in Cochin, our
Pacific operations, Central Florida Pipeline, Transmix operations, West Coast
terminals, North System and our Cypress Pipeline.

   The $8.9 million (2%) increase in segment revenues in 2003 compared to 2002
was driven by a $7.1 million (2%) increase in combined revenues from our Pacific
operations and West Coast terminals, largely due to increased terminal services.
Revenues from our North System increased $3.9 million (11%) in 2003 versus 2002.
Although throughput deliveries on our North System dropped by 4% in 2003, we
benefited from a 15% increase in average tariff rates as a result of an
increased cost of service tariff agreement filed with the Federal Energy
Regulatory Commission in May 2003. Revenues from our CALNEV Pipeline increased
$2.9 million (6%) in 2003 versus 2002, due to higher revenues from both refined
product deliveries and fees associated with ethanol blending operations. CALNEV
benefited from a 5% increase in the average tariff per barrel moved, due mostly
to an increase in transportation of longer-haul, higher margin barrels. Revenues
from our Transmix operations increased $1.6 million (6%) in 2003 compared to
2002, primarily due to higher processing volumes at our transmix facilities
located in Richmond, Virginia and Indianola, Pennsylvania. Revenues from our
Central Florida Pipeline operations also increased by $1.6 million (5%) in 2003
versus 2002, due to higher storage revenues at our liquids terminal located in
Tampa, Florida and to higher refined product delivery revenues associated with a
2% increase in delivery volumes.

   The overall increase in segment revenues in 2003 compared to the prior year
was offset by a $7.5 million (23%) decrease in revenues from our investment in
the Cochin pipeline system and a $1.1 million (16%) decrease in revenues earned
from our Cypress Pipeline. In 2003, Cochin's earnings and revenues were
negatively impacted by lower delivery volumes associated with decreased propane
production in western Canada and by a pipeline rupture and fire in July. The
drop in propane production was a reaction to lower profit margins from the
extraction and sale of natural gas liquids caused by the rise in natural gas
prices since the end of 2002, and the pipeline rupture and fire led to the shut
down of the system for 29 days during the third quarter. The year-to-year drop
in Cypress' revenues was due to lower throughput volumes and to customers
catching up on liquids volumes earned but not delivered in prior periods.
Combining all of the segment's operations, total throughput delivery of refined
petroleum products, consisting of gasoline, diesel fuel and jet fuel, decreased
1.3% in 2003 compared to 2002. This decrease reflects the impact of the 2003
transition from MTBE-blended gasoline to ethanol-blended gasoline, and the fact
that ethanol cannot be transported via pipeline but must instead be blended at
terminals. Our combined diesel and jet fuel deliveries, however, increased 1.8%
in 2003 versus 2002, mainly due to a 5.7% increase in diesel delivery volumes
and to improvement in jet fuel delivery volumes in the fourth quarter of 2003.


                                       53
<PAGE>

   The $28.9 million (5%) decrease in revenues and the $70.8 million (29%)
decrease in operating expenses in 2002 compared to 2001 include reductions of
$67.8 million in transmix revenues and $68.6 million in transmix expenses, both
resulting from our long-term transmix processing agreement with Duke Energy
Merchants. During the first quarter of 2001, we entered into a 10-year agreement
with Duke Energy Merchants to process transmix on a fee basis only. Under the
agreement, Duke Energy Merchants is responsible for procurement of the transmix
and sale of the products after processing. This agreement allows us to eliminate
commodity price exposure in our transmix operations.

   Excluding the decrease in transmix revenues, segment revenues increased $38.9
million (6%) in 2002 compared to the prior year. The increase was mainly due to
a $14.7 million (40%) increase in revenues earned from our CALNEV Pipeline, the
result of an almost 2% increase in average pipeline tariff rates and the
inclusion, in 2002, of a full year of operations versus nine months in 2001. Our
proportionate share of revenues from the Cochin pipeline system increased $12.0
million (59%) in 2002 compared to 2001 as a result of higher volumes and tariffs
as well as increases related to our additional 10% ownership interest acquired
on December 31, 2001. Our Pacific operations reported a $10.6 million (4%)
increase in revenues in 2002 compared to 2001. Although mainline delivery
volumes remained flat in 2002, compared to the prior year, overall revenues were
higher due to a 2% increase in average pipeline tariff rates and higher
non-transportation revenues. For all products pipelines owned or operated at
both December 31, 2002 and 2001, total throughput delivery of refined petroleum
products was up 1.2% in 2002 over 2001. Our gasoline delivery volumes increased
4.5% in 2002, compared to a 2.6% increase nationally. Although our total jet
fuel delivery volumes were down 3.8% in 2002, reflecting the effects of the
September 11, 2001 terrorist attacks, deliveries of jet fuel improved steadily
throughout the year.

   The segment's operating expenses remained flat in 2003, compared to 2002,
and, excluding the $68.6 million decrease in our transmix cost of sales expense
referred to above, the segment's operating expenses increased only $2.2 million
(1%) in 2002, compared to 2001. This increase was primarily due to higher
operating and maintenance expenses on the Cochin pipeline system, due to the
increase in delivery volumes and our additional ownership interest.

   Earnings from equity investments consist primarily of earnings from our
approximate 51% ownership interest in Plantation Pipe Line Company and our 50%
ownership interest in Heartland Pipeline Company, both accounted for under the
equity method of accounting. Earnings from our Products Pipelines' equity
investments were $30.9 million in 2003, $29.0 million in 2002 and $28.3 million
in 2001.

   The $1.9 million (7%) increase in equity earnings in 2003 versus 2002 was
primarily due to a $1.5 million (5%) increase in equity earnings related to our
ownership interest in Plantation. The increase resulted primarily from higher
litigation settlement costs recognized during the fourth quarter of 2002,
partially offset by lower earnings from product deliveries in 2003. The decrease
in earnings from product deliveries were mainly due to lower revenues associated
with a 4% decrease in product delivery volumes in 2003 compared to 2002. The
decrease in delivery volumes in 2003 compared to 2002 resulted from longer than
anticipated refinery maintenance, weather and a new specification for Atlanta,
Georgia gasoline, which some of the refiners that supply Plantation did not make
in 2003. In 2002, Plantation delivered a record level of refined products. The
$0.7 million (2%) increase in equity earnings in 2002 versus 2001 was again due
to an increase in our proportionate share of Plantation's earnings. In 2002,
Plantation had both higher revenues, lower operating expenses and lower interest
expenses than in 2001. The higher revenues resulted from record delivery
volumes, the lower operating expenses resulted from lower power costs and the
lower interest expenses resulted from lower average borrowing rates. In December
2000, we assumed the operating duties of Plantation Pipe Line Company pursuant
to an agreement reached with the other owner of Plantation.

   Excluding the 2002 environmental loss, other income items increased $4.7
million in 2003 versus 2002, mainly due to gains realized from sales of
property, plant and equipment by our Pacific operations. The year-to-year
increases in income taxes from 2001 to 2002 and from 2002 to 2003 primarily
related to the overall growth in taxable income related to the operations of
Plantation Pipe Line Company.

   Non-cash depreciation, depletion and amortization charges, including
amortization of excess cost of investments, were $70.6 million, $67.7 million
and $71.5 million in each of the years ended December 31, 2003, 2002 and 2001,

                                       54
<PAGE>

respectively. The $2.9 million (4%) increase in 2003 versus 2002 was driven by
higher property and plant depreciation expenses from our Pacific operations,
CALNEV Pipeline and West Coast terminals. This increase was related to the
capital spending we have made since the end of 2002 in order to strengthen and
enhance our business operations on the West Coast. The $3.8 million (5%)
decrease in 2002 versus 2001 was primarily due to a $2.3 million decrease in
expenses from the amortization of excess investment costs, related to our 51%
ownership interest in Plantation Pipe Line Company. Effective January 1, 2002,
we adopted Statement of Financial Accounting Standards No. 142 "Goodwill and
Other Intangible Assets" and ceased amortizing the amount of our equity
investment costs that exceeded the underlying fair value of net assets. For more
information on our adoption of SFAS No. 142, see Note 8 to our Consolidated
Financial Statements, included elsewhere in this report.

   In addition, on July 30, 2003, we experienced a rupture on our Pacific
operations' Tucson to Phoenix line. Through a combination of increased
deliveries on our Los Angeles to Phoenix line and terminal modifications at our
Tucson terminal that allowed volumes of Phoenix-grade gasoline to be trucked
into Phoenix, we were able to deliver most of the volumes into the Phoenix area
which normally flow through the ruptured line. The 8-inch diameter line, which
was temporarily taken out of service on August 8, 2003, resumed service on
August 24, 2003. The impact of the rupture on our results of operations for 2003
was not material.

   For 2004, we currently expect that our Products Pipelines segment will report
earnings before depreciation, depletion and amortization expense of
approximately $483 million, an approximate 9% increase over 2003. The earnings
increase is expected to be driven by a continued improvement in gasoline and jet
fuel delivery volumes, planned capital improvements and expansions, terminal
acquisitions and expected adjustments to FERC-indexed tariff rates.

<TABLE>
<CAPTION>
   Natural Gas Pipelines
                                                               Year Ended December 31,
                                                    ---------------------------------------------
                                                         2003             2002             2001
                                                    -------------    -------------   -------------
                                                     (In thousands, except operating statistics)
<S>                                                  <C>              <C>              <C>
  Revenues.......................................   $   5,316,853    $   3,086,187   $   1,869,315
  Operating expenses(a)..........................       (4,967,531)     (2,784,278)      (1,665,852)
  Earnings from equity investments...............           24,012           23,887           22,558
  Other, net.....................................            1,082               36              749
  Income taxes...................................           (1,066)            (378)               -
                                                    -------------    -------------   -------------
    Earnings before DD&A and amort. of excess
      cost of equity investments.................          373,350          325,454          226,770

  Depreciation, depletion and amortization
   expense.......................................          (53,785)         (48,411)         (31,564)
  Amortization of excess cost of equity
   investments...................................             (277)            (277)          (1,402)
                                                    -------------    -------------   -------------
    Segment earnings.............................   $      319,288   $     276,766    $     193,804
                                                    =============    =============   =============

  Natural gas transport volumes (Bcf)(b).........          1,244.9          1,105.3            977.1
                                                    =============    =============   =============
  Natural gas sales volumes (Bcf)(c).............            906.0            882.8            359.5
                                                    =============    =============   =============
</TABLE>


----------

(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)  Includes Kinder Morgan Interstate Gas Transmission, Texas Intrastate group
     and Trailblazer pipeline volumes.
(c)  Represents Texas Intrastate group. Sales volumes for 2002 include first
     quarter sales volumes for Kinder Morgan Tejas, which was under prior
     management, and may not be comparable. Sales volumes for 2001 include KMTP
     only.


   Our Natural Gas Pipelines segment reported earnings before depreciation,
depletion and amortization of $373.4 million on revenues of $5,316.9 million in
2003. This compared to earnings before depreciation, depletion and amortization
of $325.5 million on revenues of $3,086.2 million in 2002 and earnings before
depreciation, depletion and amortization of $226.8 million on revenues of
$1,869.3 million in 2001.

   The segment's $47.9 million (15%) increase in earnings before depreciation,
depletion and amortization as well as its increases in both revenues and
operating expenses in 2003 compared to 2002, were primarily attributable to

                                       55
<PAGE>

internal growth on our Texas intrastate gas pipeline systems and to
contributions from two pipeline expansion projects: our North Texas Pipeline,
completed in August 2002, and our Mier-Monterrey Mexico Pipeline, completed in
March 2003.

   The combined operations of Kinder Morgan Tejas and Kinder Morgan Texas
Pipeline, the two major components of our Texas Intrastate group, accounted for
$30.7 million of the segment's total increase in earnings before depreciation,
depletion and amortization in 2003, compared to 2002. The increase was driven by
higher natural gas sale volumes and higher earnings from storage and
transportation services. Our Kinder Morgan Tejas' operations include a
3,400-mile intrastate natural gas pipeline system that has access to a number of
natural gas supply basins in Texas. The acquisition and subsequent integration
of Kinder Morgan Tejas' assets with our Kinder Morgan Texas Pipeline, has
produced a strategic and complementary intrastate pipeline business that
purchases, sells and transports significant volumes of natural gas. Since our
acquisition of Kinder Morgan Tejas, we have increased the interconnection
capability between its system and Kinder Morgan Texas Pipeline, improved systems
processes and controls and further refined the management of risk associated
with the sale and transmission of natural gas. Our objective is to match every
purchase and sale, thus locking-in the equivalent of a transportation fee. We
manage any remaining price risk by the use of energy financial instruments.

   Combined, our North Texas Pipeline and our Mier-Monterrey Pipeline accounted
for $14.9 million of the segment's total increase in earnings before
depreciation, depletion and amortization in 2003, compared to 2002. Included in
this amount are 2003 earnings before depreciation, depletion and amortization
of $9.2 million from the start-up of our Mier-Monterrey Pipeline. The pipeline
stretches from south Texas to Monterrey, Mexico and can transport up to 375,000
dekatherms per day of natural gas. We have entered into a 15-year contract with
Pemex Gas Y Petroquimica Basica, which has subscribed for all of the capacity on
the pipeline. The pipeline connects to a 1,000-megawatt power plant complex and
to the PEMEX natural gas transportation system. By integrating the operations of
our North Texas and Mier-Monterrey pipeline systems with our Texas intrastate
systems, by entering into new long-term transportation, storage and sales
contracts with customers like BP and Pemex, and by extending existing contracts
with other customers, the segment increased total natural gas transport volumes
by 13% and natural gas sales volumes by nearly 3% in 2003, compared to 2002.

   The segment's $98.7 million (44%) increase in earnings before depreciation,
depletion and amortization in 2002 compared to 2001, as well as the significant
increases in both revenues and operating expenses between these two years,
related primarily to our January 31, 2002 acquisition of Kinder Morgan Tejas and
its subsequent integration with Kinder Morgan Texas Pipeline. The intrastate
systems accounted for $83.4 million of the segment's total increase in earnings
before depreciation, depletion and amortization in 2002, compared to 2001. Both
Kinder Morgan Tejas and Kinder Morgan Texas Pipeline operate intrastate natural
gas pipelines within the State of Texas and both purchase and sell significant
volumes of natural gas, which is transported through their pipeline systems. The
purchase and sale activity results in considerably higher revenues and operating
expenses compared to our Rocky Mountain interstate natural gas pipeline systems:
Kinder Morgan Interstate Gas Transmission and Trailblazer Pipeline Company. Both
KMIGT and Trailblazer charge a transportation fee for gas transmission service
but neither system has significant gas purchases and resales.

   Together, our Rocky Mountain pipelines accounted for $4.6 million and $12.4
million of the segment's total year-to-year increases in earnings before
depreciation, depletion and amortization for the years 2003 and 2002,
respectively. The increase in both years was mainly due to the benefits
resulting from an expansion of our Trailblazer pipeline system. In May 2002, we
completed a $48 million expansion project that increased transportation capacity
on the pipeline by approximately 60%. As a result, Trailblazer realized a 12%
increase in natural gas transportation volumes in 2003 compared to 2002, and a
24% increase in natural gas transportation volumes in 2002 compared to 2001. In
2003, the segment also benefited from higher operational sales of natural gas at
higher margins by KMIGT. The overall increase in segment earnings before
depreciation, depletion and amortization in 2003 compared to 2002 included a
$2.4 million (14%) decrease in earnings from our Casper and Douglas natural gas
gathering and processing system, primarily due to higher natural gas liquids
producer settlement payments, in 2003, resulting from increases in natural gas
prices in the Rocky Mountain region since the end of 2002.

   We account for this segment's investments in Red Cedar Gas Gathering Company,
Coyote Gas Treating, LLC and Thunder Creek Gas Services, LLC under the equity
method of accounting. Earnings from these equity

                                       56
<PAGE>

investments were relatively flat across all three years. In 2003, higher
earnings from our investment in Thunder Creek were offset by lower earnings from
our investment in Red Cedar. In 2002, the $1.3 million (6%) increase in equity
earnings compared to 2001 resulted primarily from increases of $0.5 million from
each of our 50% ownership interest in Coyote and our 25% ownership interest in
Thunder Creek.

   Non-cash depreciation, depletion and amortization charges, including
amortization of excess cost of investments, were up $5.4 million (11%) in 2003
compared to 2002, primarily due to depreciation charges on the newly completed
North Texas and Mier-Monterrey pipeline systems. The $15.7 million (48%)
increase in depreciation, depletion and amortization charges in 2002 over 2001
were primarily the result of our Kinder Morgan Tejas
acquisition and higher depreciation expense related to the completed expansion
of our Trailblazer pipeline system.

   For 2004, we currently expect that our Natural Gas Pipelines segment will
report earnings before depreciation, depletion and amortization expense of
approximately $384 million, an approximate 3% increase over 2003. The earnings
increase is expected to be driven by increases in storage and transportation
services, additional earnings realized from the sale of natural gas at higher
margins and the benefits of reaching new markets and customers by planned
capital spending.

   CO2
                                                  Year Ended December 31,
                                        -----------------------------------
                                           2003          2002         2001
                                        ---------     ---------    ---------
                                     (In thousands, except operating statistics)

    Revenues..........................  $ 248,535    $ 146,280    $ 122,094
    Operating expenses(a).............    (82,055)      (50,524)     (44,973)
    Earnings from equity investments        37,198       36,328        33,998
    Other, net........................         (40)          112           547
    Income taxes......................         (39)            -             -
                                        ---------     ---------    ---------
      Earnings before DD&A and
       amort. of excess cost of
       equity investments.............     203,599      132,196       111,666

    Depreciation, depletion and
     amortization expense.............    (60,827)      (29,196)     (17,562)
    Amortization  of excess  cost of        (2,017)      (2,017)       (2,017)
     equity investments...............
                                        ---------     ---------    ---------
      Segment earnings................  $ 140,755     $ 100,983    $  92,087
                                        =========     =========    =========

    Carbon dioxide volumes
     transported (Bcf)(b).............       504.7        431.7         387.4
                                        =========     =========    =========
    SACROC Oil production (MBbl/d)....        20.2          13.0           9.1
                                        =========     =========    =========
----------

(a)  Includes costs of sales, operations and maintenance expenses, fuel and
     power expenses and taxes, other than income taxes.

(b)  Includes Cortez, Central Basin, Canyon Reef Carriers and Centerline
     pipeline volumes.


   Our CO2 segment consists of Kinder Morgan CO2 Company, L.P. and its
consolidated affiliates. In 2003, our CO2 segment reported earnings before
depreciation, depletion and amortization of $203.6 million on revenues of $248.5
million. This compared to earnings before depreciation, depletion and
amortization of $132.2 million on revenues of $146.3 million in 2002 and
earnings before depreciation, depletion and amortization of $111.7 million on
revenues of $122.1 million in 2001.

   Both the $71.4 million (54%) increase in earnings before depreciation,
depletion and amortization and the $31.5 million (62%) increase in operating
expenses in 2003 over 2002, and the $20.5 million (18%) increase in earnings
before depreciation, depletion and amortization and the $5.6 million (12%)
increase in operating expenses in 2002 over 2001, were chiefly due to higher oil
production volumes and higher carbon dioxide pipeline delivery volumes. The
increase in oil production was driven by both expansion projects at SACROC and
by acquisitions of additional ownership interests in the SACROC and Yates oil
field units, as referred to above.

   Oil production at SACROC, located in the Permian Basin of West Texas,
increased 55% in 2003 compared to 2002, and 43% in 2002 compared to 2001. In
2003, we also benefited from an almost 6% increase in our realized

                                       57
<PAGE>

weighted average price of oil per barrel (from $22.45 per barrel in 2002 to
$23.73 per barrel in 2003). As a result of our oil reserve ownership interests,
we are exposed to commodity price risk, but the risk is mitigated by our
long-term hedging strategy that is intended to generate more stable realized
prices. For more information on our hedging activities, see Note 14 to our
Consolidated Financial Statements, included elsewhere in this report.

   Increases in oil field operations throughout the Permian Basin since the end
of 2001 resulted in higher delivery volumes of carbon dioxide, including
deliveries on our Central Basin Pipeline, our majority-owned Canyon Reef
Carriers Pipeline, our 50% owned Cortez Pipeline and our new Centerline
Pipeline, which began operations in May 2003. For these four pipelines combined,
carbon dioxide delivery volumes increased 17% in 2003 and 11% in 2002. The
Centerline Pipeline consists of approximately 113 miles of 16-inch diameter pipe
located in the Permian Basin between Denver City, Texas and Snyder, Texas, and
primarily transports carbon dioxide to the SACROC oil field unit. The pipeline
transported 50.5 billion cubic feet of carbon dioxide during 2003. We do not
recognize profits on carbon dioxide sales to ourselves.

   As discussed in Note 2 to our Consolidated Financial Statements, included
elsewhere in this report, we capitalize the cost of CO2 that is injected into
the SACROC unit as part of our enhanced oil recovery process. The CO2 costs
incurred and capitalized as development costs for the SACROC unit were $45.1
million, $30.3 million and $12.5 million for the years ended December 31, 2003,
2002 and 2001, respectively. We estimate that such costs will be approximately
$56.0 million, $62.1 million and $52.8 million in 2004, 2005 and 2006,
respectively. It is expected that, due to the nature of this enhanced recovery
process and the underlying reservoir, the capitalized cost for CO2 in the 2005
through 2006 period will represent a peak and will decline thereafter.

   The year-to-year increases in operating expenses were primarily related to
higher operating, maintenance, and fuel and power costs, all as a result of the
higher oil production volumes. The $0.9 million (2%) increase in earnings from
equity investments in 2003 compared to 2002 reflects the net of a $4.1 million
(14%) increase in equity earnings from our 50% investment in Cortez Pipeline
Company, partially offset by a $3.2 million (39%) decrease in equity earnings
from our previous 15% interest in MKM Partners, L.P. The increase in earnings
from our equity interest in Cortez was mainly due to higher carbon dioxide
delivery volumes, lower average debt balances and slightly lower borrowing
rates. Equity earnings from MKM Partners, L.P. was lower during 2003 due to the
fact that we acquired the partnership's 12.75% ownership interest in the SACROC
unit effective June 1, 2003, and the partnership was dissolved effective June
30, 2003. The $2.3 million (7%) increase in earnings from equity investments in
2002 compared to 2001 resulted from higher earnings from the segment's
investment in Cortez, again mainly due to lower average debt balances and lower
average borrowing rates, partially offset by slightly lower carbon dioxide
delivery volumes in 2002 compared to 2001.

   Non-cash depreciation, depletion and amortization charges were up $31.6
million (101%) in 2003 compared to 2002, primarily due to higher production
volumes, capital investments, and acquisitions of property interests since the
end of 2002. The $11.6 million (59%) increase in depreciation, depletion and
amortization charges in 2002 over 2001 were primarily the result of the capital
expenditures we have made since the end of 2001, which resulted in a higher
unit-of-production depletion rate.

   For 2004, we currently expect that our CO2 segment will report earnings
before depreciation, depletion and amortization expense of approximately $322
million, an approximate 58% increase over 2003. The earnings increase is
expected to be driven by the continuing development of the SACROC oil field
unit, increased ownership interests in the Yates oil field unit for the full
year (with oil production expected to be essentially even with 2003), and
increased transportation of carbon dioxide volumes across all of our carbon
dioxide pipelines.


                                       58
<PAGE>

<TABLE>
<CAPTION>

   Terminals
                                                               Year Ended December 31,
                                                          2003            2002             2001
                                                     -------------    -------------   -------------
                                                     (In thousands, except operating statistics)
<S>                                                   <C>              <C>              <C>
   Revenues.......................................   $      473,558   $     428,048    $     349,875
   Operating expenses(a)..........................         (229,054)        (213,929)        (175,869)
   Earnings from equity investments...............               41               45                -
   Other, net(b)..................................               88           15,550              226
   Income taxes...................................           (3,857)          (4,751)          (6,720)
                                                     -------------    -------------   -------------
     Earnings before DD&A and amort. of excess
       cost of equity investments.................          240,776          224,963          167,512
   Depreciation, depletion and amortization expense         (37,075)         (30,046)         (27,087)
   Amortization of excess cost of equity
    investments...................................                -                -                -
                                                     -------------    -------------   -------------
     Segment earnings.............................   $      203,701   $     194,917    $     140,425
                                                     =============    =============   =============

   Bulk transload tonnage (MMtons)(c).............             56.2             58.7             58.3
                                                     =============    =============   =============
   Liquids leaseable capacity (MMBbl).............             36.2             35.3             34.0
                                                     =============    =============   =============
   Liquids utilization %..........................             96.0%            97.0%            97.0%
                                                     =============    =============   =============
</TABLE>

----------
(a) Includes costs of sales, operations and maintenance expenses, fuel and power
    expenses and taxes, other than income taxes.
(b) Amounts for 2002 include environmental expense adjustments resulting in a
    $15.7 million loss to our Products Pipelines business segment and a $16.0
    million gain to our Terminals business segment.
(c) Includes Cora, Grand Rivers and Kinder Morgan Bulk Terminals aggregate
    terminal throughputs; excludes operatorship of LAXT bulk terminal.


   Our Terminals segment includes the operations of approximately 52 terminals
that transload and store coal, dry-bulk materials and petrochemical-related
liquids, as well as approximately 57 transload operations located throughout the
United States. The segment reported earnings before depreciation, depletion and
amortization of $240.8 million on revenues of $473.6 million in 2003. This
compared to earnings before depreciation, depletion and amortization of $225.0
million on revenues of $428.0 million in 2002 and earnings before depreciation,
depletion and amortization of $167.5 million on revenues of $349.9 million in
2001.

   As noted in the above table, the segment's 2002 earnings include a $16.0
million gain from the adjustment and realignment of our environmental
liabilities referred to above in our "Critical Accounting Policies and
Estimates." Excluding the 2002 environmental gain, segment earnings before
depreciation and amortization increased $31.8 million (15%) in 2003 compared to
2002. Approximately half of this year-to-year increase was attributable to
expansion projects at existing liquids terminals, and the remainder was
attributable to solid contributions from the bulk and liquid terminal businesses
we have acquired since September 1, 2002. The internal growth was driven by the
ongoing expansion projects undertaken to increase leaseable liquids capacity at
our liquid terminal facility located in Carteret, New Jersey on the New York
Harbor, and at our Pasadena and Galena Park, Texas facilities, located along the
Houston Ship Channel. These expansion projects have contributed to a 2.5%
increase in our overall liquids terminals' leaseable capacity in 2003 compared
to 2002, more than offsetting the slight 1% drop in our overall utilization
percentage. Over half of the decline in utilization during 2003 was associated
with tank maintenance.

   The acquisition of new terminal businesses acquired since September 1, 2002,
included the following:

   o the Owensboro Gateway Terminal, acquired effective September 1, 2002;

   o the St. Gabriel Terminal, acquired effective September 1, 2002;

   o the purchase of four floating cranes at our bulk terminal facility in Port
     Sulphur, Louisiana in December 2002;

   o the bulk terminal businesses acquired from M.J. Rudolph Corporation,
     effective January 1, 2003; and


                                       59
<PAGE>

   o the two bulk terminal businesses in Tampa, Florida, acquired in December
     2003.

   The above acquisitions accounted for $30.7 million of the total $45.6 million
(11%) increase in revenues in 2003, compared to 2002. The remaining increase
includes year-to-year increases of $9.1 million from our Carteret and Galena
Park liquids terminal facilities and $5.1 million from our 66 2/3% ownership
interest in the International Marine Terminals Partnership. The increase from
Carteret and Galena Park was driven by expansion projects, additional liquids
storage contracts and escalations in annual contract provisions. We have
completed the construction of five 100,000 barrel petroleum products storage
tanks at our Carteret facility since the end of the third quarter of 2002. The
increase from IMT, which operates a bulk commodity transfer terminal facility
located in Port Sulphur, Louisiana, was driven by an almost 10% increase in bulk
tonnage transfer volume, primarily coal and iron ore, and by higher dockage
revenues.

   The segment's overall increases in both earnings before depreciation,
depletion and amortization and revenues in 2003 compared to 2002 included
decreases of $1.8 million (24%) and $3.0 million (23%), respectively, from our
Cora coal terminal facility located near Cora, Illinois. The decrease in coal
revenues and earnings was primarily related to an expected decrease in coal
tonnage handled under contract for the Tennessee Valley Authority. The TVA has
diverted some of its business to new competing coal terminals that have come
on-line since the end of 2002. The $15.1 million (7%) increase in operating
expenses in 2003 compared to 2002 was due to the above acquisitions and to
higher operating, maintenance and rental expenses at IMT, all resulting from
the increase in transfer volumes.

   Excluding the 2002 environmental item mentioned above, segment earnings
before depreciation, depletion and amortization increased $41.5 million (25%) in
2002, compared to 2001. Revenues and operating expenses increased $78.1 million
(22%) and $38.1 million (22%) in 2002 versus 2001, respectively. This growth in
earnings before depreciation, depletion and amortization, revenues and operating
expenses was driven by the acquisitions and asset purchases that we have made
since the last half of 2001 and internal growth.

   In addition to the acquisitions referred to above, these acquisitions
included the following;

   o the terminal businesses we acquired from Koninklijke Vopak N.V., effective
     July 10, 2001;

   o the terminal businesses we acquired from The Boswell Oil Company, effective
     August 31, 2001;

   o the terminal businesses we acquired from an affiliate of Stolt-Nielsen,
     Inc. in November 2001;

   o Kinder Morgan Materials Services LLC, formerly Laser Materials Services
     LLC, acquired effective January 1, 2002;

   o a 66 2/3% interest in International Marine Terminals Partnership (a 33 1/3%
     interest acquired effective January 1, 2002 and an additional 33 1/3%
     interest acquired effective February 1, 2002); and

   o the Milwaukee Bagging Operations, acquired effective May 1, 2002.

   Combined, all of our acquisitions since the last half of 2001 accounted for
incremental amounts of $29.5 million in earnings before depreciation, depletion
and amortization, $88.5 million in revenues and $58.5 million in operating
expenses in 2002, compared to 2001. The remaining $12.0 million increase in
segment earnings before depreciation, depletion and amoritization was
attributable to internal growth at existing facilities, primarily driven by the
expansion work at various terminals that were completed since the end of 2001.
Expansion projects undertaken during 2002 at our Carteret and Pasadena terminals
contributed to a 3.8% increase in the segment's leaseable capacity of liquids
products, compared to the prior year. In addition, while adding the incremental
capacity during 2002, we maintained a strong liquids capacity utilization rate
of 97%, the same level reached in 2001. The segment's overall increases in
earnings before depreciation, depletion and amortization, revenues and operating
expenses in 2002 compared to 2001, included decreases of $3.9 million, $15.7
million and $11.7 million, respectively, related to a decline in engineering
services resulting from a general downturn in business since the end of 2001.


                                       60
<PAGE>

   Income tax expenses totaled $3.9 million in 2003, $4.8 million in 2002 and
$6.7 million in 2001. Both the $0.9 million (19%) decrease in 2003 compared to
2002, and the $1.9 million (28%) decrease in 2002 compared to 2001 were
primarily due to favorable tax adjustments related to the taxable income and
tax-paying obligations of Kinder Morgan Bulk Terminals, Inc. and its
consolidated subsidiaries.

   Non-cash depreciation, depletion and amortization charges were $37.1 million,
$30.0 million and $27.1 million in each of the years ended December 31, 2003,
2002 and 2001, respectively. The $7.1 million (24%) increase in 2003 versus 2002
was primarily driven by higher depreciation charges on property, plant and
equipment utilized in our bulk terminal operations. The increase was mainly due
to higher bulk terminal property acquisitions and capital spending, and to
adjustments made to the estimated remaining useful lives of depreciable property
since the end of 2002. The $2.9 million (11%) increase in 2002 compared to 2001
was primarily due to additional acquisitions and expansions that were
capitalized since the end of 2001.

   For 2004, we currently expect that our Terminals segment will report earnings
before depreciation, depletion and amortization expense of approximately $257
million, an approximate 7% increase over 2003. The earnings increase is expected
to be driven by the on-going capital expansion projects at our liquids terminal
facilities, by expected increases in certain bulk tonnage transfer volumes, most
notably soda ash, petroleum coke, fertilizer and synfuel, and by the addition
of our Tampa, Florida bulk terminal facilities, purchased in December 2003.

   Other

   Items not attributable to any segment include general and administrative
expenses, interest income and expense and minority interest. Our general and
administrative expenses include such items as salaries and employee-related
expenses, payroll taxes, legal fees, insurance and office supplies and rentals.
Overall general and administrative expenses totaled $150.4 million in 2003,
compared to $122.2 million in 2002 and $113.5 million in 2001. The $28.2 million
(23%) increase in general and administrative expenses in 2003 compared to the
prior year was primarily due to higher legal expenses, employee benefit and
pension costs and overall corporate and worker-related insurance expenses. The
$8.7 million (8%) increase in general and administrative expenses in 2002
compared to 2001 was principally due to additional employee benefit,
compensation and reimbursement charges, higher insurance related expenses and
administrative expenses related to our Kinder Morgan Tejas acquisition. We
continue to manage aggressively our infrastructure expense and to focus on our
productivity and expense controls.

   Our total interest expense, net of interest income, was $181.4 million in
2003, $176.5 million in 2002 and $171.5 million in 2001. The $4.9 million (3%)
increase in net interest items in 2003 compared to 2002 and the $5.0 million
(3%) increase in net interest items in 2002 compared to 2001each reflect higher
average borrowings since the end of the prior year, partially offset by
decreases in our average borrowing rates.

   Minority interest, which includes the 1.0101% general partner interest in our
five operating limited partnerships, totaled $9.1 million in 2003, compared to
$9.6 million in 2002 and $11.4 million in 2001. Both the $0.5 million (5%)
decrease in 2003 compared to 2002, and the $1.8 million (16%) decrease in 2002
from 2001 resulted primarily from our May 2002 acquisition of the remaining 33
1/3% ownership interest in Trailblazer Pipeline Company that we did not already
own, thereby eliminating the minority interest related to Trailblazer.

Liquidity and Capital Resources

   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 (other than distributions to our common
unitholders, Class B unitholders and general partner) through borrowings under
our credit facilities, issuing short-term commercial paper, long-term notes or
additional common units or issuing additional i-units to KMR. In general, we
expect to fund:

   o cash distributions and sustaining capital expenditures with existing cash
     and cash flows from operating activities;

   o expansion capital expenditures and working capital deficits with cash
     retained (as a result of including i-units in the determination of cash
     distributions per unit but paying quarterly distributions on i-units in
     additional
                                       61
<PAGE>

     i-units rather than cash), additional borrowings, the issuance
     of additional common units or the issuance of additional i-units to KMR;

   o interest payments with cash flows from operating activities; and

   o debt principal payments with additional borrowings, as such debt principal
     payments become due, or by the issuance of additional common units or the
     issuance of additional i-units to 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 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.

   The following table illustrates the sources of our invested capital. In
addition to our results of operations, these balances are affected by our
financing activities as discussed below (dollars in thousands):

<TABLE>
<CAPTION>

                                                                       December 31,
                                                         -----------------------------------------
                                                             2003            2002           2001
                                                         ------------    ------------  ------------
<S>                                                       <C>             <C>            <C>
   Long-term debt, excluding market value of
    interest rate swaps...............................   $   4,316,678   $  3,659,533  $  2,237,015
   Minority interest..................................          40,064          42,033         65,236
   Partners' capital..................................       3,510,927      3,415,929      3,159,034
                                                         ------------    ------------  ------------
     Total capitalization............................        7,867,669      7,117,495      5,461,285
   Short-term debt, less cash and cash equivalents....         (21,081)        (41,088)      497,417
                                                         ------------    ------------  ------------
     Total invested capital...........................   $   7,846,588   $  7,076,407  $  5,958,702
                                                         ============    ============  ============

   Capitalization:
   Long-term debt, excluding market value of
    interest rate swaps...............................           54.9%           51.4%          41.0%
     Minority interest................................            0.5%            0.6%           1.2%
     Partners' capital................................           44.6%           48.0%          57.8%
                                                         ------------    ------------  ------------
                                                               100.0%          100.0%         100.0%
                                                         ============    ============  ============

   Invested Capital:
     Total debt, less cash and cash equivalents
       and excluding market value of interest
       rate swaps.....................................           54.7%           51.1%          45.9%
     Partners' capital and minority interest..........           45.3%           48.9%          54.1%
                                                         ------------    ------------  ------------
                                                               100.0%          100.0%         100.0%
                                                         ============    ============  ============
</TABLE>


   Short-term Liquidity

   Our principal sources of short-term liquidity are our revolving bank credit
facilities, our $1.05 billion short-term commercial paper program (which is
supported by our revolving bank credit facilities, with the amount available for
borrowing under our credit facilities being reduced by our outstanding
commercial paper borrowings) and cash provided by operations. Our bank
facilities can be used for general corporate purposes and as a backup for our
commercial paper program. As of December 31, 2003, we had available a $570
million unsecured 364-day credit facility due October 12, 2004, and a $480
million unsecured three-year credit facility due October 15, 2005. There were no
borrowings under either credit facility as of December 31, 2003. After inclusion
of our outstanding commercial paper borrowings and letters of credit, the
remaining available borrowing capacity under our bank facilities was $572.0
million as of December 31, 2003.

   As of December 31, 2003, we intend and have the ability to refinance $428.1
million of our short-term debt on a long-term basis under our unsecured
long-term credit facility. Accordingly, such amount has been classified as
long-term debt in our accompanying consolidated balance sheet. Currently, we
believe our liquidity to be adequate. For more information on our credit
facilities, see Note 9 to our Consolidated Financial Statements included
elsewhere in this report.

                                       62
<PAGE>

   Long-term Financing Transactions

   Debt Financing

   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 revolving
credit facilities, generally have the same terms except for interest rates,
maturity dates and prepayment restrictions. All of our outstanding debt
securities are unsecured obligations that rank equally with all of our other
senior debt obligations. 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.

On November 21, 2003, we closed a public offering of $500 million in principal
amount of senior notes due December 15, 2013 at a price to the public of 99.363%
per note. In the offering, we received proceeds, net of underwriting discounts
and commissions, of approximately $493.6 million. We used the proceeds to reduce
our outstanding balance on our commercial paper borrowings. As of December 31,
2003, our total liability balance due on the various series of our senior notes
was approximately $3.7 billion. For more information on our senior notes, see
Note 9 to our Consolidated Financial Statements included elsewhere in this
report.


   Equity Financing

   In June 2003, we issued in a public offering, an additional 4,600,000 of our
common units, including 600,000 units upon exercise by the underwriters of an
over-allotment option, at a price of $39.35 per share, less commissions and
underwriting expenses. After commissions and underwriting expenses, we received
net proceeds of $173.3 million for the issuance of these common units. We used
the proceeds to reduce the borrowings under our commercial paper program.

   On February 3, 2004, we announced that we had priced the public offering of
an additional 5,300,000 of our common units at a price of $46.80 per unit, less
commissions and underwriting expenses. We also granted to the underwriters an
option to purchase up to 795,000 additional common units to cover
over-allotments. On February 9, 2004, 5,300,000 common units were issued. We
received net proceeds of $237.8 million for the issuance of these common units
and we used the proceeds to reduce the borrowings under our commercial paper
program.

   Capital Requirements for Recent Transactions

   During 2003, our cash outlays for the acquisitions of assets and equity
investments totaled $359.9 million. We utilized our commercial paper program to
fund these acquisitions and then reduced our short-term borrowings with the
proceeds from our June 2003 issuance of common units and our November 2003
issuances of long-term senior notes. We intend to refinance the remainder of our
current short-term debt and any additional short-term debt incurred during 2004
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 60% equity financing and
40% debt financing. We issued common units in February 2004 in a public offering
as discussed above.

   In regard to acquisition expenditures, our primary capital requirements
during 2003 included the following:

   Owensboro Gateway Terminal. Effective September 1, 2002, we acquired certain
bulk and terminal assets from Lanham River Terminal, LLC for approximately $7.7
million in aggregate consideration, consisting of $7.7 million in cash. We paid
$7.2 million in September 2002 and the remaining $0.5 million in September 2003.

   M.J. Rudolph. Effective January 1, 2003, we acquired certain bulk terminal
assets from M.J Rudolph Corporation for approximately $31.3 million in cash. We
paid $29.9 million on December 31, 2002 and the remaining $1.4 million in March
2003.


                                       63
<PAGE>

   MKM Partners, L.P. Effective June 1, 2003, we acquired the MKM Partners,
L.P.'s 12.75% ownership interest in the SACROC oil field unit for approximately
$25.2 million in aggregate consideration, consisting of $23.3 million in cash
and $1.9 million in assumed liabilities.

   Red Cedar Gas Gathering Company. Effective August 1, 2003, we acquired
reversionary interests in the Red Cedar Gas Gathering Company held by the
Southern Ute Indian Tribe. We paid $10.0 million in cash in September 2003.

   Shell Products Terminals. Effective October 1, 2003, we acquired five refined
petroleum products terminals in the western United States from Shell Oil
Products U.S. for approximately $20.0 million in cash. We paid this amount in
October 2003.

   Yates Field Unit and Carbon Dioxide Assets. Effective November 1, 2003, we
acquired from a subsidiary of Marathon Oil Corporation an approximate 42.5%
ownership interest in the Yates oil field unit, crude oil gathering facilities
surrounding the Yates field and Marathon Carbon Dioxide Transportation Company.
Marathon Carbon Dioxide Transportation Company owns a 65% ownership interest in
the Pecos Carbon Dioxide Pipeline Company. We paid Marathon approximately $259.0
million in aggregate consideration, consisting of $231.0 million in cash and
$28.0 million in assumed liabilities.

   MidTex Gas Storage Company, LLP. Effective November 1, 2003, we acquired the
remaining approximate 32% of MidTex Gas Storage Company, LLP that we did not
already own for approximately $17.5 million in aggregate consideration. We paid
$15.8 million in cash and assumed $1.7 million in debt.

   ConocoPhillips Products Terminals. Effective December 11, 2003, we acquired
seven refined petroleum products terminals in the southeastern United States
from ConocoPhillips and Phillips Pipe Line Company for approximately $14.0
million in cash and $1.1 million in assumed liabilities. We paid this amount in
December 2003.

   Tampa, Florida Bulk Terminals. Effective December 10 and 23, 2003, we
acquired two bulk terminal facilities located in Tampa, Florida from Nitram,
Inc. and IMC Global, Inc., respectively. Our consideration consisted of
approximately $26.0 million in cash and $3.5 million in assumed liabilities. We
paid this amount in December 2003.

   Summary of Off Balance Sheet Arrangements

   We have invested in entities that are not consolidated in our financial
statements. Our obligations with respect to these investments, as well as our
obligations with respect to a letter of credit, are summarized below (in
millions):
<TABLE>
<CAPTION>
                                                                                                                  Our
                                                     Our           Remaining           Total       Total           Contingent
                                   Investment      Ownership       Interest(s)        Entity      Entity           Share of
Entity                                Type           Interest        Ownership         Assets(4)     Debt         Entity Debt(5)
---------------------------------- ----------     ---------        -----------      ---------     ------       --------------
<S>                                  <C>               <C>              <C>              <C>          <C>             <C>
                                    General           50%              (1)              $132         $231            $116 (2)
Cortez Pipeline Company........     Partner

                                    Common             51%           Affiliate of       $280        $179              $5
                                    Shareholder,                   Exxon Mobil
Plantation Pipe Line Company...     Operator                       Corporation

Red Cedar Gas Gathering              General            49%          Southern Ute        $166          $55             $55
    Company....................     Partner                        Indian Tribe

Nassau County,                          N/A             N/A          Nassau County,       N/A         N/A             $28
    Florida Ocean Highway                                          Florida Ocean
    and Port Authority (3).....                                    Highway and
                                                                  Port Authority
</TABLE>

---------


                                       64
<PAGE>

(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 of the Cortez
     Pipeline Company debt. Further, pursuant to a Throughput and Deficiency
     Agreement, the owners 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
     owners 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. Their respective parent or other companies further severally
     guarantee the obligations of the Cortez Pipeline owners under this
     agreement.

(3)  Results from our Vopak terminal acquisition in July 2001. See Note 3 to the
     Consolidated Financial Statements. 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.

(4)  Principally property, plant and equipment.

(5) Represents the portion of the entity's debt that we may be responsible for
    if the entity cannot satisfy the obligation.

   For the year ended December 31, 2003, our share of earnings, based on our
ownership percentage, before income taxes and amortization of excess investment
cost was $32.2 million from Cortez Pipeline Company, $28.0 million from
Plantation Pipe Line Company and $18.6 million from Red Cedar Gas Gathering
Company. Additional information regarding the nature and business purpose of
these investments is included in Notes 7 and 13 to our Consolidated Financial
Statements included elsewhere in this report.

<TABLE>
<CAPTION>
  Summary of Certain Contractual Obligations

                                                 Amount of Commitment Expiration per Period
                                       ---------------------------------------------------------------
                                                      1 Year                                   After 5
                                          Total        or Less     2-3 Years      4-5 Years      Years
                                       ----------     --------     --------       --------    ----------
                                                               (In thousands)
<S>                                     <C>            <C>           <C>            <C>          <C>
Commercial paper outstanding......    $  426,130     $426,130     $      -       $      -    $         -
Other debt borrowings.............     3,892,796        4,218      248,252        257,857     3,382,469
Operating leases..................       102,753       17,076       27,780         22,457         35,440
Postretirement welfare plans(a)...         1,800          300           600            600            300
Other obligations.................         3,600          600         1,200          1,200            600
                                       ----------     --------     --------       --------    ----------
Total.............................    $4,427,079    $448,324      $277,832      $282,114     $3,418,809
                                       ==========     ========     ========       ========    ==========

Other commercial commitments:
Capital expenditures..............    $   54,918     $ 54,918             -              -              -
                                       ==========     ========     ========       ========    ==========
</TABLE>

----------

(a) Represents expected annual contributions of $0.3 million per year based on
    calculations of independent Enrolled Actuary as of December 31, 2003.

   Our budgeted expenditures for capital spending during 2004 are approximately
$115.9 million. This amount has been budgeted primarily for the purchase of
plant and equipment and is based on the payments we expect to make as part of
our 2004 sustaining capital expenditure plan. All of our capital expenditures,
with the exception of sustaining capital expenditures, are discretionary.

   Operating Activities

   Net cash provided by operating activities was $768.5 million in 2003, versus
$869.7 million in 2002. The $101.2 million (12%) decrease in 2003 compared to
2002 was primarily the result of an $87.9 million use of cash relative to net
changes in the collection on and payments of our accounts receivables and
payables in 2003 compared to a $111.5 million source of cash from these changes
in 2002. In addition to

                                       65
<PAGE>

timing differences, we made higher payments to settle related party payables at
the beginning of 2003, primarily for reimbursements to KMI for costs related to
the construction of our Mier-Monterrey natural gas pipeline and for general and
administrative services.

   We also paid $44.9 million in 2003 for reparations and refunds under order
from the Federal Energy Regulatory Commission. The reparation and refund
payments were mandated by the FERC in a consolidated proceeding in FERC Docket
OR92-8-000 concerning rates charged by our Pacific operations on certain
interstate portions of their products pipelines. For more information on our
Pacific operations' regulatory proceedings, see Note 16 to our Consolidated
Financial Statements included elsewhere in this report.

   The impact of these payments and the working capital timing differences were
partially offset by a $131.9 million increase in overall cash earnings,
reflecting the strong performance and growth that occurred across our business
portfolio during 2003. It also includes a $20.1 million increase in cash flows
related to higher payments made in 2002 under certain settlement agreements and
a $5.3 million increase related to higher distributions from equity investments
in 2003. The litigation settlements were primarily related to tariff-related
agreements between shippers and our Products Pipelines, and the increase in
distributions from equity investments in 2003 compared to 2002 mainly related to
higher returns from our 49% equity interest in the Red Cedar Gathering Company.

   Investing Activities

   Net cash used in investing activities was $943.1 million for the year ended
December 31, 2003, compared to $1,450.9 million for the prior year. The $507.8
million (35%) decrease in funds utilized in investing activities was mainly
attributable to higher expenditures made for strategic acquisitions in 2002.
Outlays for acquisition of assets, new businesses and investments totaled $910.3
million in 2002, versus $359.9 million in 2003. The $550.4 million (60%)
difference in acquisition expenditures was mainly due to our acquisition of
Kinder Morgan Tejas on January 31, 2002.

   We continue to invest significantly in strategic acquisitions in order to
fuel future growth and increase unitholder value. These expenditures in 2003 are
detailed under "- Capital Requirements for Recent Transactions" above. Our
expenditures in 2002 included, (i) $721.6 million for Kinder Morgan Tejas, (ii)
$80.1 million for the remaining 33 1/3% ownership interest in Trailblazer
Pipeline Company and a contingent interest in Trailblazer from CIG Trailblazer
Gas Company, (iii) $29.9 million for certain bulk terminal assets previously
owned by M.J. Rudolph Corporation and (iv) $29.0 million for an additional 10%
ownership interest in the Cochin Pipeline system, which was made effective
December 31, 2001. For more information on our acquisitions, see Note 3 to our
Consolidated Financial Statements included elsewhere in this report.

   The overall decline in funds used in investing activities in 2003 compared to
2002 includes a $34.7 million increase in funds used for capital expenditures
and an $11.8 million reduction in proceeds from sales and retirements of
property, plant and equipment. Including expansion and maintenance projects, our
capital expenditures were a record $577.0 million in 2003. We spent $542.2
million for capital expenditures in 2002. This $34.8 million (6%) increase was
principally due to higher 2003 capital investment in our CO2 and Products
Pipelines business segments. We continue to expand and grow our existing
businesses and have current projects in place that will, together with recent
acquisitions, significantly add production and throughput capacity to our oil
field and carbon dioxide flooding operations, and will add storage and transfer
capacity to our terminaling and natural gas businesses. Our sustaining capital
expenditures were $92.8 million for 2003, compared to $77.0 million for 2002.

   Financing Activities

   Net cash provided by financing activities amounted to $156.8 million in 2003,
compared to $559.5 million in 2002. This decrease of $402.7 million (72%) from
the prior year was chiefly due to both a $157.8 million decrease in cash flows
from overall debt financing activities and a $157.2 million decrease in cash
flows from partnership equity issuances. Both decreases were related to our
higher acquisition expenditures during 2002, as described above. During each of
the years 2003 and 2002, we purchased the pipeline and terminal businesses we
acquired primarily with borrowings under our commercial paper program. We
subsequently raised funds by completing public and private debt offerings of
senior notes and by issuing additional common units and i-units. We used the
proceeds from these debt and equity issuances to reduce our borrowings under our
commercial paper program.


                                       66
<PAGE>

   In 2003, we closed a public offering of $500 million in principal amount of
senior notes, resulting in a net cash inflow of $493.6 million net of discounts
and issuing costs, and we borrowed an additional $206.1 million under our
commercial paper program. We used our commercial paper borrowings to fund our
asset acquisitions, capital expansion projects and other partnership activities,
and we used the proceeds from the senior note issuance to reduce commercial
paper borrowings. In 2002, we closed a public offering of $750 million in
principal amount of senior notes, completed a private placement of $750 million
in principal amount of senior notes to qualified institutional buyers (we then
exchanged these notes in the fourth quarter of 2002 with substantially identical
notes that are registered under the Securities Act of 1933) and retired a
maturing amount of $200 million in principal amount of senior notes. We also
made payments of $55.0 million to retire the outstanding balance on our
Trailblazer Pipeline Company's two-year revolving credit facility and used
$370.5 million to reduce our commercial paper borrowings.

   The year-to-year decrease in cash flows from partnership equity issuances
primarily relates to the difference in cash received from our June 2003 issuance
of common units and our August 2002 issuance of i-units. In June 2003, we issued
4,600,000 of our common units in a public offering at a price of $39.35 per
share, less commissions and underwriting expenses. After commissions and
underwriting expenses, we received net proceeds of $173.3 million for the
issuance of these common units. In August 2002, we issued 12,478,900 i-units to
KMR at a price of $27.50 per share, less commissions and underwriting expenses.
After commissions and underwriting expenses, we received net proceeds of $331.2
million for the issuance of these i-units. We used the proceeds from each of
these issuances to reduce the borrowings under our commercial paper program.

   The overall decrease in funds provided by financing activities in 2003
compared to 2002 also resulted from a $97.2 million increase in distributions to
our partners in 2003 compared to the prior year. Cash distributions to all
partners, including KMI, increased to $679.3 million in 2003 compared to $582.1
million in 2002. The increase in distributions was due to increases in the per
unit cash distributions paid, the number of outstanding units and the resulting
increase in the general partner incentive distributions.

   We paid distributions of $2.575 per unit in 2003 compared to $2.36 per unit
in 2002. The 9% increase in paid distributions per unit resulted from favorable
operating results in 2003. We also distributed 3,342,417 and 2,538,785 i-units
in quarterly distributions during 2003 and 2002, respectively, to KMR, our sole
i-unitholder. The amount of i-units distributed in each quarter was based upon
the amount of cash we distributed to the owners of our common and Class B units
during that quarter of 2003 and 2002. For each outstanding i-unit that KMR held,
a fraction of an i-unit was issued. The fraction was determined by dividing the
cash amount distributed per common unit by the average of KMR's shares' closing
market prices for 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.

   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, less cash
disbursements and net additions to reserves (including any reserves required
under debt instruments for future principal and interest payments) 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 2003, 2002 and
2001, we distributed 100.4%, 97.6% and 100%, of the total of cash receipts less
cash disbursements, respectively (calculations assume that KMR unitholders
received cash). The difference between these numbers and 100% reflects net
changes in reserves.

                                       67
<PAGE>

   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. 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. We do not distribute cash
to i-unit owners but retain the cash for use in our business.

   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:

   o 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;

   o 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;

   o 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

   o 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 2003 was $322.8 million, while the incentive distribution paid
to our general partner during 2003 was $309.4 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.

   On February 13, 2004, we paid a quarterly distribution of $0.68 per unit for
the fourth quarter of 2003. This distribution was 9% greater than the $0.625
distribution per unit we paid for the fourth quarter of 2002 and 6% greater than
the $0.64 distribution per unit we paid for the first quarter of 2003. 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 $0.68 cash distribution per common unit.

   Litigation and Environmental

   As of December 31, 2003, we have recorded a total reserve for environmental
claims in the amount of $39.6 million. This 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. 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 and to identify if the
reserve allocation is appropriately valued. 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. After consideration of
reserves established, we believe that costs for environmental remediation and
ongoing compliance with environmental regulations will not have a material
adverse effect on our cash flows, financial position or results of operations or
diminish our ability to operate our businesses. However, there can be no
assurances that future events, such as changes in existing laws, the
promulgation of new laws, or the development or discovery of new or existing
facts or conditions will not cause us to incur significant unanticipated costs.

   Please refer to Note 16 to our Consolidated Financial Statements included
elsewhere in this report for additional information on our pending environmental
and litigation matters, respectively. We believe we have established


                                       68
<PAGE>

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. However,
changing circumstances could cause these matters to have a material adverse
impact.

   Regulation

   On June 26, 2003, FERC issued an interim rule to be effective August 7, 2003,
under which regulated companies are required to document cash management
arrangements and transactions. The interim rule does not include a proposed rule
that would have required regulated companies, as a prerequisite to participation
in cash management programs, to maintain a proprietary capital ratio of 30% and
an investment grade credit rating. On October 22, 2003, the FERC issued its
final rule amending its regulations effective November 2003 which, among other
things, requires FERC-regulated entities to file their cash management
agreements with the FERC and to notify the FERC within 45 days after the end of
the quarter when their proprietary capital ratio drops below 30%, and when it
subsequently returns to or exceeds 30%. KMIGT and Trailblazer filed their cash
management agreements with the FERC on or before the deadline, which was
December 10, 2003.

   On November 25, 2003, the FERC issued Order No. 2004, adopting new Standards
of Conduct to become effective February 9, 2004. Every interstate pipeline must
file a compliance plan by that date and must be in full compliance with the
Standards of Conduct by June 1, 2004. The primary change from existing
regulation is to make such standards applicable to an interstate pipeline's
interaction with many more affiliates (which are referred to as "energy
affiliates"), including intrastate/Hinshaw pipelines, 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 pipeline.
Local distribution companies are excluded, however, if they do not make
off-system sales. 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 the interstate pipeline to an
energy affiliate.

   Kinder Morgan Interstate Gas Transmission LLC filed for clarification and
rehearing of Order No. 2004 on December 29, 2003. In the request for rehearing,
Kinder Morgan Interstate Gas Transmission LLC asked that intrastate/Hinshaw
pipeline affiliates not be included in the definition of energy affiliates. To
date the FERC has not acted on these hearing requests. On February 19, 2004,
Kinder Morgan Interstate Gas Transmission LLC and Trailblazer Pipeline Company
filed exemption requests with the FERC. The pipelines seek a limited exemption
from the requirements of Order No. 2004 for the purpose of allowing their
affiliated Hinshaw and intrastate pipelines, which are subject to state
regulation and do not make any off-system sales, to be excluded from the rule's
definition of energy affiliate. We expect the one-time costs of compliance with
the Order, assuming the request to exempt intrastate pipeline affiliates is
granted, to range from $600,000 to $700,000, to be shared between us and KMI.

   The Pipeline Safety Improvement Act of 2002 was signed into law on December
17, 2002, providing guidelines in the areas of testing, education, training and
communication. The 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. Pipeline companies are required
to perform the integrity tests within ten years of 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. In addition, within one year of the law's enactment,
pipeline companies must implement a qualification program to make certain that
employees are properly trained; using criteria the U.S. Department of
Transportation is responsible for providing. 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.
At least half of the line pipe affecting High Consequence Areas must be assessed
by September 30, 2004. We have included all incremental expenditures estimated
to occur during 2004 associated with the Pipeline Safety Improvement Act of 2002
and the integrity management of our products pipelines in our 2004 capital
expenditure plan.


                                       69
<PAGE>

   Please refer to Note 16 to our Consolidated Financial Statements included
elsewhere in this report for additional information regarding regulatory
matters.

New Accounting Pronouncements

   Please refer to Note 17 to our Consolidated Financial Statements included
elsewhere in this report for information on New 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," "will," 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:

   o 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 the United States;

   o economic activity, weather, alternative energy sources, conservation and
     technological advances that may affect price trends and demand;

   o changes in our tariff rates implemented by the Federal Energy Regulatory
     Commission or the California Public Utilities Commission;

   o 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;

   o difficulties or delays experienced by railroads, barges, trucks, ships or
     pipelines in delivering products to or from our terminals or pipelines;

   o our ability to successfully identify and close acquisitions and make
     cost-saving changes in operations;

   o 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;

   o 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;

   o 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;

   o 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;

   o interruptions of electric power supply to our facilities due to natural
     disasters, power shortages, strikes, riots, terrorism, war or other causes;

                                       70
<PAGE>

   o acts of nature, sabotage, terrorism or other similar acts causing damage
     greater than our insurance coverage limits;

   o capital markets conditions;

   o the political and economic stability of the oil producing nations of the
     world;

   o national, international, regional and local economic, competitive and
     regulatory conditions and developments;

   o the ability to achieve cost savings and revenue growth;

   o inflation;

   o interest rates;

   o the pace of deregulation of retail natural gas and electricity;

   o foreign exchange fluctuations;

   o the timing and extent of changes in commodity prices for oil, natural gas,
     electricity and certain agricultural products; and

   o the timing and success of business development efforts.

   You should not put undue reliance on any forward-looking statements.

   See Items 1 and 2 "Business and Properties -- Risk Factors" for a more
detailed description of these and other factors that may affect the
forward-looking statements. Our future results also could be adversely impacted
by unfavorable results of litigation and the fruition of contingencies referred
to in Note 16 to the Consolidated Financial Statements included elsewhere in
this report. 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 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 are
characterized as "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 interest rates or commodity prices and the timing of transactions.

Energy Financial Instruments

   We use energy financial instruments to reduce our risks associated with
changes in the market price of natural gas, natural gas liquids, crude oil and
carbon dioxide. To minimize the risks associated with changes in the market
price of natural gas, natural gas liquids, crude oil and carbon dioxide, we use
certain financial instruments for hedging purposes. These instruments 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. For more information on our risk management
activities, see Note 14 to our Consolidated Financial Statements included
elsewhere in this report.

                                       71
<PAGE>

   While we enter into derivative transactions only with investment grade
counterparties and actively monitor their credit ratings, it is nevertheless
possible that additional losses will result from counterparty credit risk in the
future. The credit ratings of the primary parties from whom we purchase energy
financial instruments are as follows:

                                                  Credit Rating
                                                  -------------
               J. Aron & Company / Goldman Sachs      A+
               Morgan Stanley..................       A+
               Deutsche Bank...................       AA-

   During the fourth quarter of 2001, we determined that Enron Corp. was no
longer likely to honor the obligations it had to us in conjunction with
derivatives we were accounting for as hedges under Statement of Financial
Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities." Upon making that determination, we (i) ceased to account for those
derivatives as hedges, (ii) entered into new derivative transactions on
substantially similar terms with other counterparties to replace our positions
with Enron, (iii) designated the replacement derivative positions as hedges of
the exposures that had been hedged with the Enron positions and (iv) recognized
a $6.0 million loss (included with General and administrative expenses in the
accompanying Consolidated Statement of Income for 2001) in recognition of the
fact that it was unlikely that we would be paid the amounts then owed under the
contracts with Enron.

   Pursuant to our management's approved risk management policy, we are to
engage in these activities only as a hedging mechanism against price volatility
associated with:

   o pre-existing or anticipated physical natural gas, natural gas liquids and
     crude oil sales;

   o pre-existing or anticipated physical carbon dioxide sales that have pricing
     tied to crude oil prices;

   o natural gas purchases; and

   o system use and storage.

   Our risk management activities are only used in order to protect our profit
margins, and our risk management policies prohibit us from engaging in
speculative trading. Commodity-related activities of our risk management group
are monitored by our Risk Management Committee, which is charged with the review
and enforcement of our management's risk management policy.

   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. Accordingly, as of December 31, 2003, no financial
instruments were used to limit the effects of foreign exchange rate fluctuations
on our financial results. In February 2004, we entered into a single $17.0
million foreign currency call option that expires on December 31, 2004.

   Through December 31, 2000, gains and losses on hedging positions were
deferred and recognized as cost of sales in the periods in which the underlying
physical transactions occurred. On January 1, 2001, we began accounting for
derivative instruments under Statement of Financial Accounting Standards No.
133, "Accounting for Derivative Instruments and Hedging Activities" (after
amendment by SFAS No. 137 and SFAS No. 138). As discussed above, our principal
use of derivative financial instruments is to mitigate the market price risk
associated with anticipated transactions for the purchase and sale of natural
gas, natural gas liquids, crude oil and carbon dioxide. SFAS No. 133 allows
these transactions to continue to be treated as hedges for accounting purposes,
although the changes in the market value of these instruments will affect
comprehensive income in the period in which they occur and any ineffectiveness
in the risk mitigation performance of the hedge will affect net income
currently. The change in the market value of these instruments representing
effective hedge operation will continue to affect net income in the period in
which the associated physical transactions are consummated. Our adoption of SFAS
No. 133 has resulted in $155.8 million of deferred net loss being reported as
"Accumulated other comprehensive loss" in our accompanying Balance Sheet as of
December 31, 2003, and $45.3 million of deferred

                                       72
<PAGE>

net loss being reported as "Accumulated other comprehensive loss" in our
accompanying Balance Sheet as of December 31, 2002.

   We measure the risk of price changes in the natural gas, natural gas liquids,
crude oil and carbon dioxide 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 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. Financial instruments 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, 2003 and
2002, Value-at-Risk reached a high of $12.8 million and $12.8 million,
respectively, and a low of $2.2 million and $11.6 million, respectively.
Value-at-Risk as of December 31, 2003, was $6.2 million and averaged $5.2
million for 2003. Value-at-Risk as of December 31, 2002, was $12.8 million and
averaged $11.9 million for 2002.

   Our calculated Value-at-Risk exposure represents an estimate of the
reasonably possible net losses that would be recognized on our portfolio of
derivatives 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 derivatives 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 derivatives is, with the exception of a minor amount
of hedging inefficiency, offset by changes in the value of the underlying
physical transactions.

Interest Rate Risk

   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.

   We utilize both variable rate and fixed rate debt in our financing strategy.
See Note 9 to the Consolidated Financial Statements included elsewhere in this
report for additional information related to our debt instruments. 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, 2003 and 2002, the carrying values of our long-term fixed
rate debt were approximately $3,801.7 million and $3,346.1 million,
respectively, compared to fair values of $4,372.3 million and $4,161.6 million,
respectively. The increase in the excess of fair value over carrying value is
primarily due to the decrease in interest rates during 2003. 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 in the average interest rates applicable to such debt
for 2003 and 2002, respectively, would result in changes of approximately $158.6
million and $195.1 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 market value of interest rate swaps,
was $493.0 million as of December 31, 2003 and $293.4 million as of December 31,
2002. Fair value was determined using future cash flows discounted based on
market rates for similar types of borrowing arrangements. A hypothetical 10%
change in the average interest rate applicable to this debt would result in a
change of approximately $2.3 million and $1.6 million in our 2003 and 2002
annualized pre-tax earnings, respectively.

   As of December 31, 2003, we were party to interest rate swap agreements with
a notional principal amount of $2.1 billion for the purpose of hedging the
interest rate risk associated with our fixed and variable rate debt

                                       73
<PAGE>

obligations.  A hypothetical 10% change in the average interest rates related to
these swaps would not have a material effect on our annual pre-tax earnings in
2003 or 2002. 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 swaps or other interest rate hedging agreements.

   As of December 31, 2003, 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.


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 91.

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

   None.


Item 9A.  Controls and Procedures.

   As of December 31, 2003, 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 in all material respects 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. There has been no change in our
internal control over financial reporting during the fourth quarter of 2003 that
has materially affected, or is reasonably likely to materially affect, our
internal control over financial reporting.



                                       74
<PAGE>


                                    PART III

Item 10.  Directors and Executive Officers of the Registrant.

Directors and Executive Officers of our General Partner and the Delegate

   Set forth below is certain information concerning the directors and executive
officers of our general partner and KMR as 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
the delegate are elected annually by, and may be removed by, our general partner
as the sole holder of the delegate's voting shares. Kinder Morgan (Delaware),
Inc. is a wholly owned subsidiary of KMI. All officers of the general partner
and the delegate serve at the discretion of the board of directors of our
general partner. In addition to the individuals named below, KMI was a director
of the delegate until its resignation in January 2003.

                                    Position with our General Partner and the
           Name                 Age    Delegate
  ----------------------      ----   --------------------------------------------
  Richard D. Kinder.........   59   Director, Chairman and Chief Executive
                                     Officer
  Michael C. Morgan.........   35   President
  C. Park Shaper............   35   Director, Vice President and Chief Financial
                                     Officer
  Edward O. Gaylord.........   72   Director
  Gary L. Hultquist.........   60   Director
  Perry M. Waughtal.........   68   Director
  Thomas A. Bannigan........   50   President, Products Pipelines
  R. Tim Bradley............   48   President, CO2
  David D. Kinder...........   29   Vice President, Corporate Development
  Joseph Listengart.........   35   Vice President, General Counsel and
                                     Secretary
  Deborah A. Macdonald......   52   President, Natural Gas Pipelines
  Jeffrey R. Armstrong......   35   President, Terminals
  James E. Street...........   47   Vice President, Human Resources and
                                     Administration

   Richard D. Kinder is Director, Chairman and Chief Executive Officer of KMR,
Kinder Morgan G.P., Inc. and KMI. 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 KMI in October 1999.
He was elected Director, Chairman and Chief Executive Officer of Kinder Morgan
G.P., Inc. in February 1997. Mr. Kinder is also a director of Baker Hughes
Incorporated. Mr. Kinder is the uncle of David Kinder, Vice President, Corporate
Development of KMR, Kinder Morgan G.P., Inc. and KMI.

   Michael C. Morgan is President of KMR, Kinder Morgan G.P., Inc. and KMI.
Mr. Morgan was elected to each of these positions in July 2001. He was also
elected Director of KMI in January 2003. Mr. Morgan served as Vice
President-Strategy and Investor Relations of KMR from February 2001 to July
2001. He served as Vice President-Strategy and Investor Relations of KMI and
Kinder Morgan G.P., Inc. from January 2000 to July 2001. He served as Vice
President, Corporate Development of Kinder Morgan G.P., Inc. from February 1997
to January 2000. Mr. Morgan was the Vice President, Corporate Development of KMI
from October 1999 to January 2000. From August 1995 until February 1997, Mr.
Morgan was an associate with McKinsey & Company, an international management
consulting firm. In 1995, Mr. Morgan received a Masters in Business
Administration from the Harvard Business School. From March 1991 to June 1993,
Mr. Morgan held various positions, including Assistant to the Chairman, at PSI
Energy, Inc. Mr. Morgan received a Bachelor of Arts in Economics and a Masters
of Arts in Sociology from Stanford University in 1990.

   C. Park Shaper is Director, Vice President and Chief Financial Officer of KMR
and Kinder Morgan G.P., Inc. and Vice President and Chief Financial Officer of
KMI. Mr. Shaper was elected Director of KMR and Kinder Morgan G.P., Inc. in
January 2003. He was elected Vice President, Treasurer and Chief Financial
Officer of KMR upon its formation in February 2001, and served as Treasurer of
KMR from February 2001 to January 2004. He has served as Treasurer of KMI from
April 2000 to January 2004 and Vice President and Chief Financial Officer of KMI
since January 2000. Mr. Shaper was elected Vice President, Treasurer and Chief
Financial Officer of Kinder Morgan G.P., Inc. in January 2000, and served as
Treasurer of Kinder Morgan G.P., Inc. from January 2000 to January 2004. From
June 1999 to December 1999, Mr. Shaper was President and Director of Altair
Corporation, an enterprise focused on the distribution of web-based investment
research for the financial services industry. He

                                       75
<PAGE>

served as Vice President and Chief Financial Officer of First Data Analytics, a
wholly-owned subsidiary of First Data Corporation, from 1997 to June 1999. From
1995 to 1997, he was a consultant with The Boston Consulting Group. He received
a Masters in 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.

   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. Mr. Hultquist is a member of
the Board of Directors of netMercury, Inc., a supplier of automated supply chain
services, critical spare parts and consumables used in semiconductor
manufacturing. Previously, Mr. Hultquist practiced law in two San Francisco area
firms for over 15 years, specializing in business, intellectual property,
securities and venture capital litigation.

   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. Mr.
Waughtal is the Chairman, a limited partner and a 40% owner of Songy Partners
Limited, an Atlanta, Georgia based real estate investment company. Mr. Waughtal
advises Songy's management on real estate investments and has overall
responsibility for strategic planning, management and operations. He is also a
director of Prime Medical Services, Inc. Previously, Mr. Waughtal served for
over 30 years as Vice Chairman of Development and Operations and as Chief
Financial Officer for Hines Interests Limited Partnership, a real estate and
development entity based in Houston, Texas.

   Thomas A. Bannigan is 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 President, Products Pipelines of KMR upon its
formation in February 2001. He was elected 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. From
1985 to May 1998, Mr. Bannigan was Vice President, General Counsel and Secretary
of Plantation Pipe Line Company. 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.

   R. Tim Bradley is President, CO2 of KMR and of Kinder Morgan G.P., Inc. and
President of Kinder Morgan CO2 Company, L.P. Mr. Bradley was elected President,
CO2 of KMR and Vice President (President, CO2) of Kinder Morgan G.P., Inc. in
April 2001. Mr. Bradley has been President of Kinder Morgan CO2 Company, L.P.
(which name changed from Shell CO2 Company, Ltd. in April 2000) since March
1998. From May 1996 to March 1998, Mr. Bradley was Manager of CO2 Marketing for
Shell Western E&P, Inc. 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 of KMR, Kinder
Morgan G.P., Inc. and KMI. Mr. Kinder was elected Vice President, Corporate
Development of KMR, Kinder Morgan G.P., Inc. and KMI in October 2002. He served
as manager of corporate development for KMI and Kinder Morgan G.P., Inc. from
January 2000 to October 2002. He served as an associate in the corporate
development group of KMI and Kinder Morgan G.P., Inc. from February 1999 to
January 2000. From June 1996 to February 1999, Mr. Kinder was in the analyst and
associate program at Enron Corp. 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 KMI. 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

                                       76
<PAGE>

President, General Counsel and Secretary of KMI in October 1999. Mr. Listengart
was elected Kinder Morgan G.P., Inc.'s Secretary in November 1998 and became an
employee of Kinder Morgan G.P., Inc. in March 1998. 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.

   Deborah A. Macdonald is President, Natural Gas Pipelines of KMR, Kinder
Morgan G.P., Inc. and KMI. She was elected as President, Natural Gas Pipelines
in June 2002. Ms. Macdonald served as President of Natural Gas Pipeline Company
of America from October 1999 to March 2003. Prior to joining Kinder Morgan, Ms.
Macdonald worked as Senior Vice President of legal affairs for Aquila Energy
Company from January 1999 to October 1999, and was engaged in a private energy
consulting practice from June 1996 to December 1999. Ms. Macdonald received her
Juris Doctor, summa cum laude, from Creighton University in May 1980 and
received a Bachelors degree, magna cum laude, from Creighton University in
December 1972.

   Jeffrey R. Armstrong is President, Terminals of KMR and Kinder Morgan G.P.,
Inc. Mr. Armstrong became President of our Terminals Segment in July 2003. Prior
to that, he served as President, Kinder Morgan Liquids Terminals LLC from March
1, 2001, when the company was formed via the acquisition of GATX Terminals,
until 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 a MBA from
the University of Notre Dame.

   James E. Street is Vice President, Human Resources and Administration of KMR,
Kinder Morgan G.P., Inc. and KMI. 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 KMI in August 1999. From October 1996 to August 1999, Mr. Street
was Senior Vice President, Human Resources and Administration for Coral Energy,
a subsidiary of Shell Oil Company. 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

   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 is the equivalent of a board of directors for us.
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 the board of KMR as the delegate of our general
partner, acting as our board of directors, and references to committees mean
committees of the board of KMR as the delegate of our general partner, acting as
committees of our board of directors.

   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 and rules respectively. 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:

   o 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 or interim chief executive officer, such employment relationship
     ended by the date of determination);

                                       77
<PAGE>

   o If within the period of three years prior to the determination the director
     received no more than, and has no immediate family member that received
     more than, $100,000 per year 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 or interim chief executive officer, and (iii) compensation
     received by an immediate family member for service as a non-executive
     employee;

   o If the director is at the date of determination an executive officer or an
     employee, or has an immediate family member that is at the date of
     determination an executive officer, of another company that, within the
     last three full fiscal years prior to the date of determination made
     payments to, or received payments from, us and our affiliates for property
     or services in an amount which, in any single fiscal year, was less than
     the greater of $1.0 million or 2% of such other company's annual
     consolidated gross revenues. Charitable organizations are not considered
     "companies" for purposes of this determination;

   o 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

   o If the director beneficially owns less than 10% of each class of voting
     securities of us, our general partner, KMR or Kinder Morgan, Inc.

   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 regular board meetings, these three non-management directors
also meet in executive session without members of management. Mr. Waughtal has
been elected for a one year term expiring in October 2004 to serve as lead
director to develop the agendas for and moderate these executive sessions of
independent directors.

   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 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.

   We have not, nor has our general partner nor KMR made, within the preceding
three years, contributions to any charitable organization in which any of our or
KMR's directors serves as an executive officer in any single fiscal year that
exceeded the greater of $1 million or 2% of such charitable organization's
consolidated gross revenues.

   We make available free of charge within the "Investors" information section
of our Internet website, at www.kindermorgan.com and in print to any shareholder
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,
and any waiver from a provision of that code granted to our executive officers
or directors, on our Internet website within five 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.

   You may contact our lead director or the independent directors as a group by
mail to Kinder Morgan Management, LLC, 500 Dallas Street, Suite 1000, Houston,
Texas 77002, Attention: General Counsel, or by email within the "Contact Us"
section of our Internet website, at www.kindermorgan.com. Your communication
should specify the intended recipient.

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<PAGE>

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 2003.


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, including all of the named
officers below, also serve as executive officers of KMI. All information in this
report with respect to compensation of executive officers describes the total
compensation received by those persons in all capacities for Kinder Morgan G.P.,
Inc., KMR, KMI and their respective affiliates.

<TABLE>
<CAPTION>
                                                       Summary Compensation Table

                                                                                         Long-Term
                                                                                    Compensation Awards
                                                  Annual Compensation            Restricted     KMI Shares
                                                                                    Stock       Underlying        All Other
      Name and Principal Position            Year         Salary      Bonus(1)       Awards(2)      Options       Compensation(3)
    -----------------------------------------------  -----------   -----------  ------------- -------------   ----------------
<S>                                          <C>        <C>          <C>             <C>             <C>               <C>
    Richard D. Kinder...............         2003      $        1   $      --       $      --            --           $     --
      Director, Chairman and CEO             2002               1           --              --            --                 --
                                            2001               1           --              --            --                 --

    Michael C. Morgan...............         2003         200,000     875,000      5,380,000             --              9,815
      President                              2002         200,000     950,000             --             --              9,584
                                            2001         200,000     350,000        569,900             --              7,835

    C. Park Shaper..................         2003         200,000     875,000      5,918,000             --              8,378
      Director, Vice President and CFO       2002        200,000      950,000             --        100,000(4)           8,336
                                            2001         200,000     350,000        569,900             --              7,186

    Deborah A. Macdonald............         2003         200,000     875,000      5,380,000             --              8,966
      President,                             2002         200,000     950,000             --         50,000(5)           8,966
      Natural Gas Pipelines                  2001         200,000     350,000        569,900             --             32,816

    Joseph Listengart...............         2003         200,000     825,000      3,766,000             --              8,378
      Vice President,                        2002         200,000     950,000             --             --              8,336
      General Counsel and Secretary          2001         200,000     350,000        569,900             --              7,186
----------
</TABLE>


(1)  Amounts earned in year shown and paid the following year.

(2)  Represent shares of restricted KMI stock awarded in 2003 and 2001. The 2003
     and 2001 awards were issued under a shareholder approved plan. For the 2003
     awards, value computed as the number of shares awarded times the closing
     price on date of grant ($53.80 at July 16, 2003). 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. To vest, we and/or
     KMI must also achieve one of the following performance hurdles during the
     vesting period: (i) KMI must earn $3.70 per share in any fiscal year; (ii)
     we must distribute $2.72 over four consecutive quarters; (iii) we and KMI
     must fund at least one year's annual incentive program; or (iv) KMI's stock
     price must average over $60.00 per share during any consecutive 30-day
     period. One of these hurdles has already been met. The 2003 awards were
     long-term equity compensation for our current senior management

                                       79
<PAGE>

     through July 2008, and neither we nor KMI intend to make further restricted
     stock awards to them before that date. The 2001 awards were granted in 2002
     and relate to performance in 2001. Value for 2001 grants computed as the
     number of shares awarded (10,000) times the closing price on date of grant
     ($56.99 at January 16, 2002). Twenty-five percent of the shares in each
     grant vest on each of the first four anniversaries after the date of grant.
     The holders of the restricted stock awards are eligible to vote and to
     receive dividends declared on such shares.

(3)  For 2003 and 2002, amounts represent contributions to the Kinder Morgan
     Savings Plan (a 401(k) plan), value of group-term life insurance exceeding
     $50,000 and taxable parking subsidy. For 2001, amounts represent
     contributions to the Kinder Morgan Savings Plan, value of group-term life
     insurance exceeding $50,000, parking subsidy and a $50 cash payment. Ms.
     Macdonald's amounts include additions in 2001 resulting from relocation
     expenses.

(4)  The 100,000 options to purchase KMI shares were granted on January 16, 2002
     with an exercise price of $56.99 per share and vest at the rate of
     twenty-five percent on each of the first four anniversaries after the date
     of grant.

(5)  The 50,000 options to purchase KMI shares were granted on January 16, 2002
     with an exercise price of $56.99 per share and vest at the rate of
     twenty-five percent on each of the first four anniversaries after the date
     of grant.


   Kinder Morgan Savings Plan. Effective July 1, 1997, our general partner
established the Kinder Morgan Retirement Savings Plan, a defined contribution
401(k) plan. This plan was subsequently amended and merged to form the Kinder
Morgan Savings Plan. The plan now permits all full-time employees of Kinder
Morgan, Inc. and KMGP Services Company, Inc. to contribute between one percent
and fifty percent of base compensation, on a pre-tax basis, into participant
accounts. In addition to a mandatory contribution equal to four percent of base
compensation per year for most plan participants, our general partner may make
discretionary contributions in years when specific performance objectives are
met. Certain employees' contributions are based on collective bargaining
agreements. The mandatory contributions are made each pay period on behalf of
each eligible employee. Any discretionary contributions are made during the
first quarter following the performance year. All employer contributions,
including discretionary contributions, are in the form of KMI stock that is
immediately convertible into other available investment vehicles at the
employee's discretion. During the first quarter of 2004, we will not make any
discretionary contributions to individual accounts for 2003. All contributions,
together with earnings thereon, are immediately vested and not subject to
forfeiture. Participants may direct the investment of their contributions into a
variety of investments. Plan assets are held and distributed pursuant to a trust
agreement. Because levels of future compensation, participant contributions and
investment yields cannot be reliably predicted over the span of time
contemplated by a plan of this nature, it is impractical to estimate the annual
benefits payable at retirement to the individuals listed in the Summary
Compensation Table above.

   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. Either the
board of directors of our general partner or a committee of the board of
directors will administer the option plan. The option plan terminates on March
5, 2008.

   No individual employee may be granted options for more than 20,000 common
units in any year. Our board of directors or the committee referred to in the
prior paragraph will determine the duration and vesting of the options to
employees at the time of grant. As of December 31, 2003, outstanding options to
purchase 129,050 common units had been granted to 43 former Kinder Morgan G.P.,
Inc. employees who are now employees of Kinder Morgan, Inc. or KMGP Services
Company, Inc. Forty percent of such options will vest on the first anniversary
of the date of grant and twenty percent on each of the next three anniversaries.
The options expire seven years from the date of grant.

   The option plan also granted to each of our then non-employee directors as of
April 1, 1998, an option to purchase 10,000 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. In addition, each new non-employee director is granted options to
acquire 10,000 common units on the first day of the month following his or her
election. Under this provision, as of December 31, 2003, outstanding options to
purchase 20,000 common units had been granted to two of Kinder Morgan G.P.,
Inc.'s

                                       80
<PAGE>

three non-employee directors. Forty percent of all such options will vest on the
first anniversary of the date of grant and twenty percent on each of the next
three anniversaries. The non-employee director options will expire seven years
from the date of grant.

   No options to purchase common units were granted during 2003 to any of the
individuals named in the Summary Compensation Table above. The following table
sets forth certain information as of December 31, 2003 with respect to common
unit options previously granted to the individuals named in the Summary
Compensation Table above. Mr. Listengart is the only person named in the
Summary Compensation Table who was granted common unit options. No common unit
options were granted at an option price below the fair market value on the date
of grant.

<TABLE>
<CAPTION>
     Aggregated Common Unit Option Exercises in 2003 and 2003 Year-End Common Unit Option Values

                                                              Number of Units            Value of Unexercised
                                                          Underlying Unexercised         In-the-Money Options
                          Units Acquired     Value       Options at 2003 Year-End         At 2003 Year-End(1)
                                                      ---------------------------    -------------------------
        Name                 on Exercise    Realized     Exercisable   Unexercisable    Exercisable    Unexercisable
------------------       --------------    ---------  ------------- --------------  --------------   --------------
<S>                              <C>            <C>          <C>               <C>          <C>                    <C>
Joseph Listengart....          --             --           10,000            --           $ 319,888              --
</TABLE>


----------

(1) Calculated on the basis of the fair market value of the underlying common
    units at year-end 2003, minus the exercise price.


KMI Option Plan. Under KMI's stock option plan, employees of KMI and its
affiliates, including employees of KMI's direct and indirect subsidiaries, like
KMGP Services Company, Inc., are eligible to receive grants of options to
acquire shares of common stock of KMI. KMI's board of directors administers this
option plan. The primary purpose for granting stock options under this plan to
employees of KMI, KMGP Services Company, Inc. and our subsidiaries is to provide
them with an incentive to increase the value of common stock of KMI. A secondary
purpose of the grants is to provide compensation to those employees for services
rendered to our subsidiaries and us. During 2003, none of the persons named in
the Summary Compensation Table above were granted KMI stock options.

<TABLE>
<CAPTION>
              Aggregated KMI Stock Option Exercises in 2003 and 2003 Year-End KMI Stock Option Values

                                                                      Number of Shares            Value of Unexercised
                                                                   Underlying Unexercised         In-the-Money Options
                                                                   Options at 2003 Year-End        at 2003 Year-End(1)
                                     Shares Acquired    Value    --------------------------     -----------------------------
           Name                       on Exercise       Realized   Exercisable Unexercisable    Exercisable   Unexercisable
   --------------------            ---------------     ----------  ---------------------------   -------------- --------------
<S>                                    <C>             <C>              <C>           <C>            <C>             <C>
   Michael C. Morgan...........       140,000         $4,242,350       197,500             -        $5,572,406               -
   C. Park Shaper..............        30,000           $814,500       113,750      106,250        $2,473,188     $1,231,687
   Deborah A. Macdonald........        50,000         $1,194,249        62,500       37,500        $1,790,750     $    79,125
   Joseph Listengart...........        26,250           $691,264       106,300             -        $3,586,868               -
</TABLE>

----------

(1) Calculated on the basis of the fair market value of the underlying shares at
    year-end, minus the exercise price.

   Cash Balance Retirement Plan. Employees of KMGP Services Company, Inc. and
KMI are eligible to participate in a Cash Balance Retirement Plan that was put
into effect on January 1, 2001. 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 will accrue benefits through a personal retirement account in the Cash
Balance Retirement Plan. Employees with prior service and not grandfathered
converted to the Cash Balance Retirement Plan and were credited with the current
fair value of any benefits they had previously accrued through the defined
benefit plan. Under the plan, we make contributions on behalf of participating
employees equal to three percent of eligible compensation every pay period. In
addition, discretionary contributions are made to the plan based on our and
KMI's performance. No additional contributions were made for 2003 performance.
Interest will be credited to the personal retirement accounts at the 30-year
U.S. Treasury bond rate in effect each year. Employees will be fully vested in
the plan after five years, and they may take a lump sum distribution upon
termination of employment or retirement.

                                       81
<PAGE>

   The following table sets forth the estimated annual benefits payable as of
December 31, 2003, under normal retirement at age sixty-five, assuming current
remuneration levels without any salary projection, and participation until
normal retirement at age sixty-five, with respect to the named executive
officers under the provisions of the Kinder Morgan Cash Balance Retirement Plan.
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.

<TABLE>
<CAPTION>
                                              Estimated                        Current           Estimated
                                Current       Credited Yrs                   Compensation      Annual Benefit
                             Credited Yrs     of Service     Age as of       Covered by       Payable Upon
           Name                  Of Service     at Age 65    Jan. 1, 2004        Plans         Retirement (1)
           ----               -------------- --------------  ------------  --------------    --------------
<S>                                 <C>             <C>            <C>              <C>                 <C>
Richard D. Kinder.........         3               8.8            59.2             $       1            $     -
Michael C. Morgan.........         3              32.7            35.4              200,000             62,537
C. Park Shaper............         3              32.7            35.4              200,000             62,537
Joseph Listengart.........         3              32.5            35.6              200,000             61,780
Deborah A. MacDonald......         3              15.9            52.1              200,000             15,823
</TABLE>

----------

(1) The estimated annual benefits payable are based on the straight-life annuity
    form.

   Compensation Committee Interlocks and Insider Participation. We do not have a
separate 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 and Mr. James E. Street, who are
executive officers of KMR, participate in the deliberations of the KMR
compensation committee concerning executive officer compensation. Mr. Kinder
receives $1.00 annually in total compensation for services to KMI, KMR and our
general partner.

   Directors Fees. During 2003, each of the three non-employee members of the
boards of directors of KMR and our general partner received $10,000 in cash
compensation with respect to board service for the first quarter of 2003. In
addition, the director who served as chairman of KMR's audit committee was paid
an additional $2,500 for each quarter in 2003. In addition, directors are
reimbursed for reasonable expenses in connection with board meetings. In April
2003, we implemented the Directors' Unit Appreciation Rights Plan, as discussed
below, to serve as the sole compensation for non-employee directors for the
remainder of 2003. In October 2003, KMR appointed Mr. Perry M. Waughtal as Lead
Director, whose compensation is an additional $20,000 per year, paid $5,000 per
quarter, effective October 1, 2003.

   Directors' Unit Appreciation Rights Plan. On April 1, 2003, KMR's
compensation committee established the Directors' Unit Appreciation Rights Plan.
Pursuant to this plan, each of KMR's three non-employee directors is eligible to
receive common unit appreciation rights. The primary purpose of this plan is to
promote the interests of our unitholders by aligning the compensation of the
non-employee members of the board of directors of KMR with unitholders'
interests. Secondly, 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.

   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. Each unit appreciation right granted under the
plan will be exercisable only for cash 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. The plan is administered
by

                                       82
<PAGE>

KMR's compensation committee. The total number of unit appreciation rights
authorized under the plan is 500,000. KMR's board has sole discretion to
terminate the plan at any time with respect to unit appreciation rights which
have not previously been granted to participants.

   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 shall be granted to each of KMR's three
non-employee directors during the first meeting of the board each January.
Accordingly, each non-employee director received an additional 10,000 unit
appreciation rights on January 21, 2004. As of December 31, 2003, 52,500 unit
appreciation rights had been granted. No unit appreciation rights were exercised
during 2003.

   Employment Agreement. In April 2000, Mr. Michael C. Morgan entered into a
four-year employment agreement with KMI and our general partner. Under the
employment agreement, Mr. Morgan receives an annual base salary of $200,000 and
bonuses at the discretion of the compensation committee of KMR. Mr. Morgan is
prevented from competing with KMI and us for a period of four years from the
date of the agreement, provided Mr. Richard D. Kinder continues to serve as
chief executive officer of KMI or its successor.

   Retention Agreement. Effective January 17, 2002, KMI entered into a retention
agreement with Mr. C. Park Shaper, an officer of KMI, Kinder Morgan G.P., Inc.
(our general partner) and its delegate, KMR. Pursuant to the terms of the
agreement, Mr. Shaper obtained a $5 million personal loan guaranteed by KMI and
us. Mr. Shaper was required to purchase and did purchase KMI common stock and
our common units in the open market with the loan proceeds. The Sarbanes-Oxley
Act of 2002 does not allow companies to issue or guarantee new loans to
executives, but it "grandfathers" loans that were in existence prior to the act.
Regardless, Mr. Shaper, KMI and we agreed that in today's business
environment it would be prudent for him to repay the loan. In conjunction with
this decision, Mr. Shaper sold 37,000 of KMI shares and 82,000 of our common
units. He used the proceeds to repay the $5 million personal loan guaranteed by
KMI and us, thereby eliminating KMI's and our guarantee of this loan. Mr. Shaper
instead participates in KMI's restricted stock plan with other senior
executives. The retention agreement was terminated accordingly.

   Lines of Credit. As of December 31, 2002, we had agreed to guarantee
potential borrowings under lines of credit available from Wachovia Bank,
National Association, formerly known as First Union National Bank, to Messrs.
Thomas Bannigan, C. Park Shaper, Joseph Listengart, and James Street and Ms.
Deborah Macdonald. Each of these officers was primarily liable for any borrowing
on his or her line of credit, and if we made any payment with respect to an
outstanding loan, the officer on behalf of whom payment was made was required to
surrender a percentage of his or her options to purchase KMI common stock. Our
obligations under the guaranties, on an individual basis, generally did not
exceed $1.0 million and such obligations, in the aggregate, did not exceed $1.9
million. As of October 31, 2003, we had made no payments with respect to these
lines of credit and each line of credit was either terminated or refinanced
without a guarantee from us. We have no further guaranteed obligations with
respect to any borrowings by our officers.


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

   The following table sets forth information as of January 31, 2004, regarding
(a) the beneficial ownership of (i) our common and Class B units, (ii) the
common stock of KMI, the parent company of our general partner, and (iii) KMR
shares by all directors of our general partner and KMR, its delegate, by each of
the named executive officers and by all directors and executive officers as a
group and (b) 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 more than
five percent of our common and Class B units and KMR shares. 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.


                                       83
<PAGE>

<TABLE>
<CAPTION>
                                           Amount and Nature of Beneficial Ownership(1)

                                                                                        Kinder Morgan
                                         Common Units            Class B Units         Management Shares       KMI Voting Stock
                                   ----------------------   ---------------------  ----------------------  -----------------------
                                     Number        Percent    Number       Percent    Number        Percent    Number        Percent
                                   of Units(2)   of Class  of Units(3)  of Class  of Shares(4)  of Class  of Shares(5)   of Class
                                   -----------    --------  -----------  --------  ------------  --------   ------------   --------
<S>               <C>                   <C>            <C>     <C>            <C>      <C>              <C>       <C>
Richard D. Kinder(6)...........       316,079           *           --          --      34,901           *    23,995,415       19.40%
Michael C. Morgan(7)...........         6,000           *           --          --        4,053           *        427,503           *
C. Park Shaper(8)..............         4,000           *           --          --        2,368           *        301,002           *
Edward O. Gaylord..............        33,000           *           --          --           --          --          2,000           *
Gary L. Hultquist(9)...........        12,000           *           --          --           --          --             --          --
Perry M. Waughtal(10)..........        35,300           *           --          --      35,103           *         40,000           *
Joseph Listengart(11)..........        14,198           *           --          --           --          --        189,300           *
Deborah A. Macdonald(12).......             --          --           --          --           --          --        195,568           *
Directors and Executive Officers
   as a group (13 persons)(13).       437,236           *           --          --      79,096           *    25,629,120       20.72%
Kinder Morgan, Inc.(14)........    12,955,735        9.62%  5,313,400     100.00% 12,702,852      25.93%            --          --
Fayez Sarofim (15).............     7,266,921        5.39%          --          --           --          --             --          --
Capital Group                               --         --            --          --   6,751,430       13.78%            --          --
International,Inc.(16).........
OppenheimerFunds, Inc.(17).....             --         --            --          --   4,433,727        9.05%            --          --
</TABLE>

----------

*  Less than 1%.

(1)  Except as noted otherwise, all units and KMI shares involve sole voting
     power and sole investment power. For Kinder Morgan Management, see note
     (4).

(2)  As of January 31, 2004, we had 134,735,758 common units issued and
     outstanding.

(3)  As of January 31, 2004, we had 5,313,400 Class B units issued and
     outstanding.

(4)  Represent the limited liability company shares of KMR. As of January 31,
     2004, there were 48,996,465 issued and outstanding KMR shares. 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)  As of January 31, 2004, KMI had a total of 123,711,341 shares of issued and
     outstanding voting common stock, which excludes 8,892,884 shares held in
     treasury.

(6)  Includes (a) 7,979 common units owned by Mr. Kinder's spouse, (b) 5,173 KMI
     shares held by Mr. Kinder's spouse and (c) 250 KMI shares held by Mr.
     Kinder in a custodial account for his nephew. Mr. Kinder disclaims any and
     all beneficial or pecuniary interest in these units and shares.

(7)  Includes options to purchase 197,500 KMI shares exercisable within 60 days
     of January 31, 2004, and includes 107,500 shares of restricted KMI stock.

(8)  Includes options to purchase 170,000 KMI shares exercisable within 60 days
     of January 31, 2004, and includes 117,500 shares of restricted KMI stock.

(9)  Includes options to purchase 10,000 common units exercisable within 60 days
     of January 31, 2004.

(10) Includes options to purchase 8,000 common units exercisable within 60 days
     of January 31, 2004.

(11) Includes options to purchase 10,000 common units and 106,300 KMI shares
     exercisable within 60 days of January 31, 2004, and includes 77,500 shares
     of restricted KMI stock.

(12) Includes options to purchase 75,000 KMI shares exercisable within 60 days
     of January 31, 2004, and includes 107,500 shares of restricted KMI stock.

(13) Includes options to purchase 32,000 common units and 815,425 KMI shares
     exercisable within 60 days of January 31, 2004, and includes 597,800 shares
     of restricted KMI stock.

(14) Includes common units owned by KMI and its consolidated subsidiaries,
     including 1,724,000 common units owned by Kinder Morgan G.P., Inc.

(15) As reported on the Schedule 13G filed February 12, 2004 by Fayez Sarofim &
     Co. and Fayez Sarofim.  Mr. Sarofim reports that he has sole voting power
     over 2,000,000 common units, shared voting power over 3,990,712 common
     units, sole disposition power over 2,000,000 common units and shared
     disposition power over 7,266,921 common units.  Mr. Sarofim's address is
     2907 Two Houston Center, Houston, Texas 77010.

                                       84
<PAGE>

(16) As reported on the Schedule 13G/A filed February 13, 2004 by Capital Group
     International, Inc. and Capital Guardian Trust Company. Capital Group
     International, Inc. and Capital Guardian Trust Company report that in
     regard to KMR shares, they have sole voting power over 5,144,620 shares,
     shared voting power over 0 shares, sole disposition power over 6,751,430
     shares and shared disposition power over 0 shares. Capital Group
     International, Inc.'s and Capital Guardian Trust Company's address is 11100
     Santa Monica Blvd., Los Angeles, California 90025.

(17) As reported on the Schedule 13G filed February 11, 2004 by
     OppenheimerFunds, Inc. and Oppenheimer Capital Income Fund.
     OppenheimerFunds, Inc. reports that in regard to KMR shares, it has sole
     voting power over 0 shares, shared voting power over 0 shares, sole
     disposition power over 0 shares and shared disposition power over 4,433,727
     shares. Of these 4,433,727 KMR shares, Oppenheimer Capital Income Fund has
     sole voting power over 2,742,501 shares, shared voting power over 0 shares,
     sole disposition power over 0 shares and shared disposition power over
     2,742,501 shares. OppenheimerFunds, Inc.'s address is 225 Liberty Street,
     11th Floor, New York, New York 10281, and Oppenheimer Capital Income Fund's
     address is 6803 Tucson Way, Centennial, Colorado 80112.


                      Equity Compensation Plan Information

   The following table sets forth information regarding our equity compensation
plans as of January 31, 2004. Specifically, the table refers to information
regarding our Common Unit Option Plan described in Item 11. "Executive
Compensation" as of January 31, 2004.

<TABLE>
<CAPTION>
                                                                                                 Number of securities
                                                                                                remaining available for
                                        Number of securities          Weighted average        future issuance under equity
                                       to be issued upon exercise      exercise price              compensation plans
                                       of outstanding options,     of outstanding options,  (excluding securities reflected
                                         warrants and rights         warrants and rights             in column (a))
           Plan Category                           (a)                         (b)                           (c)
  ----------------------------------   --------------------------   -----------------------  -------------------------------
<S>                                              <C>                         <C>                           <C>
  Equity compensation plans
    approved by security holders                       -                          -                             -

  Equity compensation plans
    not approved by security holders             149,050                     $17.88                        55,400
                                                -------                                                  ------

  Total                                          149,050                                                  55,400
                                                =======                                                  ======
</TABLE>


   For information about our Common Unit Option Plan, see Item 11 "Executive
Compensation -- Common Unit Option Plan."


Item 13.  Certain Relationships and Related Transactions.

   Odessa Lateral

   As previously reported in our Annual Report on Form 10-K for the year ended
December 31, 2002, we have purchased a certain 13-mile, 6-inch diameter carbon
dioxide pipeline lateral, referred to herein as the Odessa Lateral, from Morgan
Associates Proprietary, L.P. for $0.7 million. The Odessa Lateral connects to
Kinder Morgan CO2 Company, L.P.'s Central Basin carbon dioxide pipeline and
serves, solely, the Emmons and South Cowden carbon dioxide flooding projects
located in the Permian Basin and operated by ConocoPhillips. Morgan Associates
is a limited partnership owned and controlled by Mr. William V. Morgan and his
wife, Sara. Mr. and Mrs. Morgan are the parents of Michael C. Morgan, the
president of our general partner and KMR. Mr. William V. Morgan was Director and
Vice Chairman of our general partner and its delegate, KMR, prior to his
retirement in January 2003.

   Mr. William V. Morgan, through Morgan Associates and otherwise, has been an
active investor in carbon dioxide pipeline infrastructure since the mid-1980s.
In 1996, prior to our current management's acquisition of our general partner in
February 1997, Morgan Associates constructed the Odessa Lateral for
approximately $1.3 million, entered into a long-term transportation agreement
with KMCO2's ultimate predecessor in interest to transport carbon dioxide via
the Odessa Lateral and entered into an operating agreement with KMCO2's ultimate
predecessor in interest. Subsidiaries of Shell Oil Company and Mobil Corporation
initially provided the carbon dioxide that was

                                       85
<PAGE>

ultimately sold to the South Cowden and Emmons projects. During 2002, KMCO2 was
selling carbon dioxide to ConocoPhillips for use in the Emmons and South Cowden
carbon dioxide flooding projects.

   In 1998, we contributed our Central Basin pipeline, our operator's interest
under the operating agreement and our rights and obligations under the
transportation agreement to Shell CO2 Company, Ltd., a joint venture owned 80%
by Shell Oil Company and 20% by us. In April 2000, Shell Oil Company elected to
sell its 80% interest in Shell CO2 Company, Ltd. and we successfully won the bid
and acquired such interest. We renamed Shell CO2 Company, Ltd. as Kinder Morgan
CO2 Company, L.P., and we own a 98.9899% limited partner interest in KMCO2 and
our general partner owns a direct 1.0101% general partner interest. KMCO2
operates and transports carbon dioxide via the Odessa Lateral, and following our
acquisition of Shell's joint-venture interest, our relationship with Morgan
Associates in respect of the Odessa Lateral has returned to the 1998 pre-joint
venture level.

   In late 2002, ConocoPhillips approached KMCO2 to discuss transferring some
volumes that it was obligated to take or pay for from KMCO2 at Emmons to another
carbon dioxide flooding project it had in the Permian Basin. KMCO2 was receptive
to the proposal. However, any such transfer of volumes required the approval of
Morgan Associates. In the first quarter of 2003, following Mr. Morgan's
retirement, KMCO2 approached Morgan Associates regarding such consent and the
need to compensate Morgan Associates for any volumes transferred off of the
Odessa Lateral. The two parties agreed to pursue compensating Morgan Associates
by having KMCO2 acquire the Odessa Lateral from Morgan Associates.

   The estimated purchase price was arrived at as follows: Pursuant to the
transportation agreement, KMCO2 was obligated to pay Morgan Associates a demand
fee, plus a fee on volumes transported (or a minimum transport or pay amount in
the event the fee to be received for transported volumes did not exceed such
minimum amount) through the Odessa Lateral to the Emmons and South Cowden carbon
dioxide flooding projects. Accordingly, the estimated purchase price was arrived
at by discounting back, using a commercially reasonable discount rate, the
remaining demand fees, plus the remaining minimum transport or pay amounts under
Morgan Associates' transportation contracts with KMCO2 on the Odessa Lateral.

   Mr. Michael C. Morgan abstained from all negotiations related to the Odessa
Lateral. The transaction was approved by the Boards of Directors of our general
partner and KMR and the transaction closed by the end of March 2003.

   For more information on our related party transactions, see Note 12 of the
Notes to the Consolidated Financial Statements included elsewhere in this
report.


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,
2003, and December 31, 2002 (in dollars):

                                      Year Ended December 31,
                                   -----------------------------
                                        2003             2002
                                   -------------    -------------
          Audit fees(1)............$    1,079,092   $     983,546
          Tax fees(2)..............     1,347,903       1,833,394
          All other fees(3).........            -           10,000
                                   -------------    -------------
            Total..................$    2,426,995   $   2,826,940
                                   =============    =============
----------

(1) Includes fees for audit of annual financial statements, reviews of the
    related quarterly financial statements, and reviews of documents filed with
    the Securities and Exchange Commission.

(2) Includes fees related to professional services for tax compliance, tax
    advice and tax planning.

(3) Consists of fees for services other than services reported above. Includes
    fees related to professional services for consultation on Environmental
    Protection Agency report.

                                       86
<PAGE>

        All services rendered by PricewaterhouseCoopers LLP are permissible
under applicable laws and regulations, and are 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:

   o to select, appoint, engage, oversee, retain, evaluate and terminate our
     external auditors;

   o 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

   o to establish the fees and other compensation to be paid to our external
     auditors.

   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):

   o the auditors' internal quality-control procedures;

   o any material issues raised by the most recent internal quality-control
     review, or peer review, of the external auditors;

   o the independence of the external auditors; and

   o the aggregate fees billed by our external auditors for each of the previous
     two fiscal years.

                                       87
<PAGE>

                                     PART IV

Item 15.  Exhibits, Financial Statement Schedules, and Reports on Form 8-K.

   (a)(1) and (2) Financial Statements and Financial Statement Schedules

   See "Index to Financial Statements" set forth on page 91.

   (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 for the quarter ended June 30, 2001,
          filed on August 9, 2001).
*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).
*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 for the quarter ended
          September 30, 1999 (the "1999 Third Quarter Form 10-Q")).
*4.5 --   Indenture dated March 22, 2000 between Kinder Morgan Energy Partners,
          L.P. and First Union National Bank, as Trustee (filed as Exhibit 4.1
          to Kinder Morgan Energy Partners, L.P. Registration Statement on Form
          S-4 (File No. 333-35112) filed on April 19, 2000 (the "April 2000 Form
          S-4")).
*4.6 --   Form of 8% Note (contained in the Indenture filed as Exhibit 4.1 to
          the April 2000 Form S-4).
*4.7 --   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).
*4.8 --   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 for 2001).
*4.9 --   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 for
          2000).
*4.10--   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 for 2000).
*4.11--   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, filed on
          March 14, 2001).
*4.12--   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, filed
          on March 14, 2001).
*4.13--   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, filed
          on March 14, 2001).
*4.14--   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
          for the quarter ended March 31, 2002, filed on May 10, 2002).

                                       88
<PAGE>

*4.15--   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 for
          the quarter ended March 31, 2002, filed on May 10, 2002).
*4.16--   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 for
          the quarter ended March 31, 2002, filed on May 10, 2002).
*4.17--   Form of 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.'s
          Registration Statement on Form S-4 (File No. 333-100346) filed on
          October 4, 2002 (the "October 4, 2002 Form S-4")).
*4.18--   Form of 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).
*4.19--   Form of 5.35% Note and Form of 7.30% Note (contained in the Indenture
          filed as Exhibit 4.1 to the October 4, 2002 Form S-4).
4.20--   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.
*4.21--   Form of Senior Indenture 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")).
*4.22--   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).
*4.23--   Form of Subordinated Indenture 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).
*4.24--   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).
4.25--   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.
4.26--   Specimen of 5.00% Notes due December 15, 2013 in book-entry form.

*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--   Kinder Morgan Energy Partners, L.P. Executive Compensation Plan (filed
          as Exhibit 10 to the Kinder Morgan Energy Partners, L.P. Form 10-Q for
          the quarter ended June 30, 1997, File No. 1-11234).

*10.3--   Employment Agreement dated April 20, 2000, by and among Kinder Morgan,
          Inc., Kinder Morgan G.P., Inc. and Michael C. Morgan (filed as Exhibit
          10(b) to Kinder Morgan, Inc.'s Form 10-Q for the quarter ended March
          31, 2000).

*10.4--   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).

10.5--   364-day Credit Agreement dated as of October 14, 2003 among Kinder
          Morgan Energy Partners, L.P., the lenders party thereto and Wachovia
          Bank, National Association as Administrative Agent.

10.6--   Kinder Morgan Energy Partners, L.P. Directors' Unit Appreciation
          Rights Plan.
10.7--   Amendment No. 1 to Kinder Morgan Energy Partners, L.P. Directors' Unit
          Appreciation Rights Plan.
11.1--   Statement re: computation of per share earnings.
21.1--   List of Subsidiaries.
23.1--   Consent of PricewaterhouseCoopers LLP.
31.1--   Certification by CEO pursuant to Rule 13A-14 or 15D 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 or 15D of the Securities
          Exchange Act of 1934, as adopted pursuant to Section 302 of the
          Sarbanes-Oxley Act of 2002.
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.

                                       89
<PAGE>

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.

   (b)Reports on Form 8-K

   Current report dated October 21, 2003 on Form 8-K was furnished on October
21, 2003, pursuant to Item 9 of that form. We provided notice that we, along
with Kinder Morgan, Inc., a subsidiary of which serves as our general partner,
and Kinder Morgan Management, LLC, a subsidiary of our general partner that
manages and controls our business and affairs, intended to discuss and answer
questions related to our carbon dioxide business in a live webcast. Interested
parties would be able to access the webcast by visiting:
http://www.firstcallevents.com/service/ ajwz391859932gf12.html. The webcast
began at 4:30 p.m. eastern daylight savings time on October 21, 2003, and is
archived at Kinder Morgan, Inc.'s website at: http://www.kindermorgan.com and
at: http://www.prnewswire.com.

   Current report dated December 8, 2003 on Form 8-K was furnished on December
8, 2003, pursuant to Item 9 of that form. We provided notice that we, along with
Kinder Morgan, Inc., a subsidiary of which serves as our general partner, and
Kinder Morgan Management, LLC, a subsidiary of our general partner that manages
and controls our business and affairs, intended to make presentations on
December 9, 2003, at the Wachovia Securities Pipeline Conference, to discuss the
financials, business plans and objectives of us, Kinder Morgan, Inc. and Kinder
Morgan Management, LLC. Interested parties would be able to view the materials
presented at the conference by visiting Kinder Morgan, Inc.'s website at:
http://www.kindermorgan.com/investor/presentations.

   Current report dated January 23, 2004 on Form 8-K was furnished on January
23, 2004, pursuant to Item 9 of that form. We provided notice that we, along
with Kinder Morgan, Inc., a subsidiary of which serves as our general partner,
and Kinder Morgan Management, LLC, a subsidiary of our general partner that
manages and controls our business and affairs, intended to make presentations on
January 23, 2004, at the Kinder Morgan 2004 Analyst Conference to address the
fiscal year 2003 results, the fiscal year 2004 outlook and other business
information about us, Kinder Morgan, Inc. and Kinder Morgan Management, LLC.
Interested parties would be able to view the materials presented at the
conference by visiting Kinder Morgan, Inc.'s website at:
http://www.kindermorgan.com/ investor/presentations. Interested parties would
also have access to the presentations by audio webcast, both live and on-demand.
The live presentation could be accessed at:
http://www.videonewswire.com/event.asp?id=19868. The conference began at 8:00
a.m. C.S.T. on January 23, 2004, and will be archived for 90 days on Kinder
Morgan, Inc.'s website at: http://www.kindermorgan.com.

   Current report dated January 21, 2004 on Form 8-K was furnished on January
29, 2004, pursuant to Items 7 and 12 of that form. In Item 12, we provided
notice that on January 21, 2004, we issued a press release regarding our
financial results for the quarter and year ended December 31, 2003 and held a
webcast conference call on January 21, 2004 discussing those results. A copy of
the earnings press release and an unedited transcript of the webcast conference
call, prepared by an outside vendor, were filed pursuant to Item 7 as exhibits.







                                       90
<PAGE>


                          INDEX TO FINANCIAL STATEMENTS


                                                                        Page
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

Report of Independent Auditors........................................   92


Consolidated  Statements of Income for the years ended
December 31, 2003, 2002, and 2001.....................................   93


Consolidated  Statements of  Comprehensive  Income for the
years ended December 31, 2003, 2002, and 2001.........................   94


Consolidated Balance Sheets as of December 31, 2003 and 2002..........   95


Consolidated  Statements  of Cash Flows for the years
ended  December 31, 2003, 2002, and 2001..............................   96


Consolidated  Statements of Partners'  Capital for the
years ended December 31, 2003, 2002, and 2001.........................   97


Notes to Consolidated Financial Statements............................   98



                                       91
<PAGE>



                         Report of Independent Auditors

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

In our opinion, the consolidated financial statements listed in the accompanying
index present fairly, in all material respects, the financial position of Kinder
Morgan Energy Partners, L.P. and its subsidiaries (the Partnership) at December
31, 2003 and 2002, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 2003 in conformity with
accounting principles generally accepted in the United States of America. These
financial statements are the responsibility of the Partnership's management; our
responsibility is to express an opinion on these financial statements based on
our audits. We conducted our audits of these statements in accordance with
auditing standards generally accepted in the United States of America, which
require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit
includes 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. We believe that our audits provide a
reasonable basis for our opinion.

As discussed in Note 4 to the consolidated financial statements, the Partnership
changed its method of accounting for asset retirement obligations effective
January 1, 2003.

As discussed in Note 8 to the consolidated financial statements, the Partnership
changed its method of accounting for goodwill and other intangible assets
effective January 1, 2002.

As discussed in Note 14 to the consolidated financial statements, the
Partnership changed its method of accounting for derivative instruments and
hedging activities effective January 1, 2001.


/s/ PricewaterhouseCoopers LLP

Houston, Texas
March 3, 2004

                                       92
<PAGE>


<TABLE>
<CAPTION>

                    KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

                        CONSOLIDATED STATEMENTS OF INCOME

                                                                       Year Ended December 31,
                                                               --------------------------------------
                                                                  2003           2002           2001
                                                               ----------     ----------    ----------
                                                               (In thousands except per unit amounts)
<S>                                                             <C>            <C>            <C>
   Revenues
     Natural gas sales.....................................     $4,889,235    $2,740,518    $1,627,037
     Services..............................................      1,377,745     1,272,640      1,161,643
     Product sales and other...............................        357,342       223,899        157,996
                                                               ----------     ----------    ----------
                                                                6,624,322      4,237,057     2,946,676
                                                               ----------     ----------    ----------
   Costs and Expenses
     Gas purchases and other costs of sales................      4,880,118     2,704,295      1,657,689
     Operations and maintenance............................        397,723       376,479        352,407
     Fuel and power........................................        108,112         86,413         73,188
     Depreciation and amortization.........................        219,032       172,041        142,077
     General and administrative............................        150,435       122,205        113,540
     Taxes, other than income taxes........................         62,213         51,326         43,947
                                                               ----------     ----------    ----------
                                                                5,817,633      3,512,759     2,382,848
                                                               ----------     ----------    ----------

   Operating Income........................................        806,689       724,298        563,828

   Other Income (Expense)
     Earnings from equity investments......................         92,199         89,258         84,834
     Amortization of excess cost of
       equity investments..................................         (5,575)        (5,575)       (9,011)
     Interest, net.........................................       (181,357)     (176,460)      (171,457)
     Other, net............................................          7,601          1,698          1,962
   Minority Interest.......................................         (9,054)        (9,559)      (11,440)
                                                               ----------     ----------    ----------

   Income Before Income Taxes and Cumulative
     Effect of a Change in Accounting Principle............        710,503       623,660        458,716

   Income Taxes............................................         16,631         15,283         16,373
                                                               ----------     ----------    ----------

   Income Before Cumulative Effect of a Change
   in Accounting Principle.................................        693,872       608,377        442,343

   Cumulative effect adjustment from change
     in accounting for asset retirement
     obligations...........................................          3,465              -              -
                                                               ----------     ----------    ----------

   Net Income..............................................    $   697,337    $  608,377    $  442,343
                                                               ==========     ==========    ==========

   Calculation of Limited Partners'
     Interest in Net Income:
   Income Before Cumulative Effect of a
     Change in Accounting Principle........................     $  693,872    $  608,377    $   442,343
   Less: General Partner's interest........................       (326,489)     (270,816)      (202,095)
                                                               ----------     ----------    ----------
   Limited Partners' interest..............................        367,383       337,561        240,248
   Add: Limited Partners' interest in
     Change in Accounting Principle........................          3,430              -              -
                                                               ----------     ----------    ----------
   Limited Partners' interest in Net Income................    $   370,813    $  337,561    $  240,248
                                                               ==========     ==========    ==========

   Basic and Diluted Limited Partners'
   Net Income per Unit:
   Income Before Cumulative Effect of a
     Change in Accounting Principle........................     $      1.98   $      1.96    $     1.56
   Cumulative effect adjustment from change
     in accounting for asset retirement obligations........            0.02             -              -
                                                               -----------    ----------    ----------
   Net Income..............................................    $       2.00   $     1.96     $     1.56
                                                               ===========    ==========    ==========

   Weighted average number of units used in
     computation of Limited Partners' Net
     Income per Unit:
   Basic...................................................        185,384       172,017        153,901
                                                               ==========     ==========    ==========

   Diluted.................................................        185,494       172,186        154,110
                                                               ==========     ==========    ==========
</TABLE>


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

                                       93
<PAGE>


<TABLE>
<CAPTION>

                    KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

                      CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

                                                                 Year Ended December 31,
                                                           ----------------------------------
                                                              2003         2002         2001
                                                           ---------    ---------    ---------
                                                                     (In thousands)
<S>                                                         <C>          <C>           <C>
   Net Income..........................................    $ 697,337   $ 608,377    $ 442,343
   Cumulative effect transition adjustment.............            --           --       (22,797)
   Change in fair value of derivatives
     used for hedging purposes.........................      (192,618)   (116,560)       35,162
   Reclassification of change in fair
     value of derivatives to net income................        82,065       7,477        51,461
                                                           ---------    ---------    ---------
   Comprehensive Income................................    $ 586,784   $ 499,294    $ 506,169
                                                           =========    =========    =========
</TABLE>


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



                                       94
<PAGE>

              KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

                           CONSOLIDATED BALANCE SHEETS

                                                              December 31,
                                                        -----------------------
                                                            2003         2002
                                                        ----------    ----------
                          ASSETS                          (Dollars in thousands)
Current Assets
   Cash and cash equivalents.........................    $   23,329   $   41,088
   Accounts and notes receivable
      Trade..........................................       562,974      457,583
      Related parties................................        27,587       17,907
   Inventories
      Products.......................................         7,214         4,722
      Materials and supplies.........................        10,783         7,094
   Gas imbalances
      Trade..........................................        36,449       21,595
      Related parties................................         9,084         3,893
   Gas in underground storage........................         8,160        11,029
   Other current assets..............................        19,942      104,479
                                                        ----------    ----------
                                                           705,522       669,390
Property, Plant and Equipment, net..................    7,091,558     6,244,242
Investments.........................................      404,345       451,374
Notes receivable....................................         2,422         3,823
Goodwill............................................      729,510       716,610
Other intangibles, net..............................        13,202       17,324
Deferred charges and other assets...................      192,623       250,813
                                                        ----------    ----------
Total Assets........................................   $9,139,182    $8,353,576
                                                        ==========    ==========
                     LIABILITIES AND PARTNERS' CAPITAL
Current Liabilities
   Accounts payable
      Trade..........................................     $ 477,783   $  373,368
      Related parties................................             -        43,742
   Current portion of long-term debt.................         2,248             -
   Accrued interest..................................        52,356       52,500
   Deferred revenues.................................        10,752         4,914
   Gas imbalances....................................        49,912       40,092
   Accrued other liabilities.........................       211,328      298,711
                                                        ----------    ----------
                                                           804,379       813,327
Long-Term Liabilities and Deferred Credits
   Long-term debt
      Outstanding....................................     4,316,678    3,659,533
      Market value of interest rate swaps............       121,464      166,956
                                                        ----------    ----------
                                                         4,438,142     3,826,489
   Deferred revenues.................................        20,975       25,740
   Deferred income taxes.............................        38,106       30,262
   Asset retirement obligations......................        34,898             -
   Other long-term liabilities and deferred credits..       251,691      199,796
                                                        ----------    ----------
                                                         4,783,812     4,082,287
Commitments and Contingencies (Notes 13 and 16)
Minority Interest...................................        40,064       42,033
                                                        ----------    ----------
Partners' Capital
   Common Units (134,729,258 and 129,943,218
     units issued and outstanding as of
     December 31, 2003 and 2002,
     respectively)...................................     1,946,116    1,844,553
   Class B Units (5,313,400 and 5,313,400
     units issued and outstanding as of
     December 31, 2003 and 2002,
     respectively)...................................       120,582      123,635
   i-Units (48,996,465 and 45,654,048
     units issued and outstanding as
     of December 31, 2003 and 2002,
     respectively)...................................     1,515,659    1,420,898
   General Partner...................................        84,380       72,100
   Accumulated other comprehensive loss..............      (155,810)     (45,257)
                                                        ----------    ----------
                                                         3,510,927     3,415,929
                                                        ----------    ----------
Total Liabilities and Partners' Capital.............   $9,139,182    $8,353,576
                                                        ==========    ==========

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

                                       95
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              KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

                      CONSOLIDATED STATEMENTS OF CASH FLOWS

                                                                                       Year Ended December 31,
                                                                               --------------------------------------
                                                                                  2003           2002           2001
                                                                              -----------    -----------   -----------
                                                                                           (In thousands)
<S>                                                                            <C>            <C>            <C>
Cash Flows From Operating Activities
Net income................................................................     $   697,337   $   608,377   $    442,343
Adjustments to reconcile net income to net cash provided by operating
activities:
  Cumulative effect adj. from change in accounting for asset retirement
    obligations...........................................................          (3,465)            --             --
  Depreciation, depletion and amortization................................         219,032        172,041       142,077
  Amortization of excess cost of equity investments.......................           5,575          5,575          9,011
  Earnings from equity investments........................................         (92,199)      (89,258)       (84,834)
Distributions from equity investments.....................................          83,000         77,735         68,832
Changes in components of working capital:
  Accounts receivable.....................................................        (180,632)     (177,240)       174,098
  Other current assets....................................................          (1,858)        (7,583)       22,033
  Inventories.............................................................          (2,945)        (1,713)       22,535
  Accounts payable........................................................          92,702        288,712      (183,179)
  Accrued liabilities.....................................................           9,740         26,132        (47,792)
  Accrued taxes...........................................................          (4,904)         2,379          8,679
FERC rate reparations and refunds.........................................         (44,944)            --             --
Other, net................................................................          (7,923)       (35,462)        7,358
                                                                              -----------    -----------   -----------
Net Cash Provided by Operating Activities.................................         768,516        869,695       581,161
                                                                              -----------    -----------   -----------

Cash Flows From Investing Activities
Acquisitions of assets....................................................        (349,867)     (908,511)    (1,523,454)
Additions to property, plant and equip. for expansion and maintenance
  projects................................................................        (576,979)     (542,235)      (295,088)
Sale of investments, property, plant and equipment, net of removal costs..           2,090         13,912          9,043
Acquisitions of investments...............................................         (10,000)        (1,785)