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, 2004

                                       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, 2004 was
approximately $5,153,909,088. As of January 31, 2005, the registrant had
147,555,658 Common Units outstanding.


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<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
                  History......................................   4
                  Business Strategy............................   4
                  Recent Developments..........................   7
                 Financial Information about Segments..........  10
                 Narrative Description of Business.............  10
                  Products Pipelines...........................  10
                  Natural Gas Pipelines........................  22
                  CO2..........................................  29
                  Terminals....................................  32
                 Major Customers...............................  39
                 Regulation....................................  39
                 Environmental Matters.........................  42
                 Risk Factors..................................  45
                 Other.........................................  50
                 Financial Information about Geographic Areas..  51
                 Available Information.........................  51
Item 3.         Legal Proceedings..............................  51
Item 4.         Submission of Matters to a Vote of Security
                 Holders.......................................  51

                PART II
Item 5.         Market for Registrant's Common Equity and
                 Related Stockholder Matters and Issuer
                 Purchases of Equity Securities................  52
Item 6.         Selected Financial Data........................  53
Item 7.         Management's Discussion and Analysis of
                 Financial Condition and Results
                 of Operations.................................  55
                 Critical Accounting Policies and Estimates....  55
                 Results of Operations.........................  57
                 Liquidity and Capital Resources...............  70
                 Recent Accounting Pronouncements..............  79
                 Information  Regarding  Forward-Looking
                  Statements...................................  79
Item 7A.        Quantitative  and  Qualitative   Disclosures
                 About Market Risk.............................  81
                 Energy Financial Instruments..................  81
                 Interest Rate Risk............................  82
Item 8.         Financial Statements and Supplementary Data....  83
Item 9.         Changes in and Disagreements with Accountants
                 on Accounting and Financial Disclosure........  83
Item 9A.        Controls and Procedures........................  83
Item 9B.        Other Information..............................  84

                PART III
Item 10.        Directors and Executive Officers of the
                 Registrant....................................  85
                 Directors  and  Executive  Officers  of
                  our General Partner and the Delegate.........  85
                  Corporate Governance.........................  87
                  Section  16(a)   Beneficial   Ownership
                   Reporting Compliance........................  88
Item 11.        Executive Compensation.........................  88
Item 12.        Security  Ownership  of  Certain  Beneficial
                 Owners and Management.........................  94
Item 13.        Certain Relationships and Related
                 Transactions..................................  96
Item 14.        Principal Accounting Fees and Services.........  96

                PART IV
Item 15.        Exhibits and Financial Statement Schedules.....  98
                Index to Financial Statements.................. 101
Signatures..................................................... 188


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                                     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 one
of the largest publicly-traded pipeline limited partnerships 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 subsidiary 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." 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 focus on providing fee-based services to customers and creating 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.

     Our operations are conducted through our subsidiary operating limited
partnerships and their subsidiaries. While we conduct these operations, we focus
on generally avoiding commodity price risks and maximizing the benefits of our
characterization as a partnership for federal income tax purposes. 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 gasoline, diesel fuel, jet fuel and
          natural gas liquids to various markets through over 10,000 miles of
          products pipelines and 60 associated terminals serving customers
          across the United States;

     o    Natural Gas Pipelines. Transports, stores and sells natural gas over
          approximately 14,000 miles of natural gas transmission pipelines and
          gathering lines, plus natural gas gathering and storage facilities;

     o    CO2. Produces, transports through pipelines and markets carbon
          dioxide, commonly called CO2, to oil fields that use CO2 to increase
          production of oil, owns interests in and/or operates six oil fields in
          West Texas, and owns and operates a crude oil pipeline system in West
          Texas; and

     o    Terminals. Composed of approximately 75 owned or operated liquid and
          bulk terminal facilities and more than 55 rail transloading and
          materials handling facilities located throughout the United States.


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<PAGE>


History

     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 $831.6 million for the year
ended December 31, 2004.

     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 in this report 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
135 terminals. As of December 31, 2004, KMI and its consolidated subsidiaries
owned, through its general and limited partner interests, an approximate 18.5%
interest in us.

     In addition to the distributions it receives from its limited and general
partner interests, KMI also receives an incentive distribution from us as a
result of its ownership of our general partner. This incentive distribution is
calculated in increments based on the amount by which quarterly distributions to
our unitholders exceed specified target levels as set forth in our partnership
agreement, reaching a maximum of 50% of distributions allocated to the general
partner for distributions above $0.23375 per limited partner unit per quarter.
Including both its general and limited partner interests in us, at the 2004
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 our limited partners determined in
accordance with our partnership agreement.

     In February 2001, Kinder Morgan Management, LLC, a Delaware limited
liability company referred to in this report 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, our limited partner units, consisting of i-units,
common units and Class B units (the Class B units are similar to our common
units except that they are not eligible for trading on the New York Stock
Exchange), will vote together as a single class, with each i-unit, common unit,
and Class B unit having one vote. We pay our quarterly distributions from
operations and from interim capital transactions to KMR in additional i-units
rather than in cash. As of December 31, 2004, KMR, through its ownership of our
i-units, owned approximately 26.2% of all of our outstanding limited partner
units.

Business Strategy

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

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


                                       4


<PAGE>


     o    increasing utilization of our assets while controlling costs by:

          o    operating classic fixed-cost businesses with relatively 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 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. Generally, as
utilization of our pipelines and terminals increases, our fee-based revenues
increase. We do not face significant risks relating directly to short-term
movements in commodity prices for two principal reasons. First, we primarily
transport and/or handle products for a fee and are not engaged in significant
unmatched purchases and resales of commodity products. Second, in those areas of
our business, 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.

     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 pipeline expansions 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
          Rocky Mountain natural gas pipeline systems, 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 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 opportunities on tribal
          lands. Overall, we will continue to explore expansion and storage
          opportunities to increase utilization levels throughout our natural
          gas pipeline operations;

     o    CO2. Our carbon dioxide sales and transportation business has two
          primary strategies. First, we seek to 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. As a service provider, our strategy is to offer
          customers "one-stop shopping" for carbon dioxide supply,
          transportation and technical support service. Second, we seek to
          increase the economic benefits from our oil and gas production
          activities by increasing oil field carbon dioxide flooding,
          efficiently managing oil field operating expenses, and capturing
          downstream value in assets which complement our oil field operations.
          In our oil and gas


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<PAGE>


          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. We intend
          to compete for new supply and transportation projects, both inside and
          outside the Permian Basin, 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 an 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 continue to seek greater productivity and cost
          savings by focusing on the efficiencies of our operations and the
          related incurrence of associated operating, maintenance, and general
          and administrative expenses. In addition, we have made reductions in
          the operating, maintenance, and general and administrative expenses of
          many of the businesses and assets that we have acquired. Generally,
          these reductions in expense have been achieved by eliminating
          duplicative functions that we and the acquired businesses each
          maintained prior to their combination;

     o    Internal Growth. We intend to grow income from our current assets both
          through increased utilization of existing assets, and through internal
          expansion projects. We primarily operate classic fixed cost businesses
          with relatively little variable costs. By controlling 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 we
          believe 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 regularly consider and enter into
          discussions regarding potential acquisitions, including those from KMI
          or its affiliates, and are currently contemplating potential
          acquisitions. 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. We anticipate financing acquisitions by borrowings under
          our bank credit facility or by issuing commercial paper, and
          subsequently reducing 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
          2004 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.

     Achieving success in implementing our strategy will depend partly 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


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          time, we focus 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 our employees, 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 the Kinder Morgan Savings Plan, a defined contribution 401(k)
          plan, all full-time employees of KMI and KMGP Services Company, Inc.
          (the entities that employ all persons necessary for the operation of
          our business) can contribute between 1% and 50% of base compensation,
          on a pre-tax basis, into participant accounts. In addition to a
          mandatory contribution equal to 4% of base compensation per year for
          most plan participants, our general partner may make discretionary
          contributions in years when specific performance objectives are met.
          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.
          Furthermore, KMI's ten most senior executives (excluding Mr. Kinder,
          who receives $1 per year in salary and receives no bonus) have their
          base salaries capped at $200,000 per year and 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 when KMI and we
          meet annual earnings per share and distributions per unit targets.

Recent Developments

     The following is a brief listing of significant developments since December
31, 2003. Additional information regarding most of these items may be found
elsewhere in this report.

     o    On February 9, 2004, we completed a 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 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;

     o    Effective March 9, 2004, we acquired seven refined petroleum products
          terminals in the southeastern United States from Exxon Mobil
          Corporation for an aggregate consideration of approximately $50.9
          million, consisting of $48.2 million in cash and the assumption of
          $2.7 million of liabilities. In addition, as part of the transaction,
          ExxonMobil entered into a long-term contract to store refined
          petroleum products at the terminals. As of our acquisition date, we
          expected to invest an additional $1.2 million in the facilities in the
          near-term following acquisition. 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;

     o    On March 26, 2004, the Federal Energy Regulatory Commission issued an
          order on the phase one initial decision that was issued on June 24,
          2003 by an administrative law judge hearing a case on the rates
          charged by our Pacific operations' interstate portion of its
          pipelines. We believe 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. The FERC's phase one order
          reversed the initial decision by finding that our Pacific operations'
          rates for its North and Oregon Lines should remain "grandfathered" and
          amended the initial decision by finding that SFPP's West Line rates
          (i) to Yuma and Tucson, Arizona and to our CALNEV Pipeline, as of
          1995, and (ii) to Phoenix, Arizona, as of 1997, should


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<PAGE>


          no longer be "grandfathered" and are not just and reasonable. If these
          rates are "ungrandfathered," they could be lowered prospectively and
          complaining shippers could be entitled to reparations for prior
          periods. Both SFPP and certain shippers have appealed the FERC's
          decision to the United States Court of Appeals for the District of
          Columbia;

     o    On June 1, 2004, we commenced service on our Kinder Morgan Interstate
          Gas Transmission LLC's Cheyenne Market Center. This $28.4 million
          project involved the construction of pipeline, compression and storage
          facilities to accommodate an additional six billion cubic feet of
          natural gas storage capacity, which has been fully subscribed under
          10-year contracts. The Cheyenne Market Center offers firm natural gas
          storage capabilities that allow for 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;

     o    On July 13, 2004, we announced that we had commenced service on our
          135-mile natural gas 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. The $30 million project
          included the December 2003 acquisition of the pipeline, the subsequent
          conversion of the pipeline from crude oil to natural gas service, and
          the construction of a 5-mile pipeline lateral to serve a municipal
          power plant located in Austin, Texas. The pipeline adds approximately
          170 dekatherms per day of natural gas to the Austin market and is
          supported by long-term contracts with local utilities;

     o    On August 18, 2004, we entered into a new five-year unsecured
          revolving credit facility with a total commitment of $1.25 billion.
          The new facility expires on August 18, 2009, and replaced our 364-day
          and three-year facilities, which had total commitments of $1.05
          billion. The five-year facility will result in benefits over our prior
          credit facilities, including lower annual fees, reduced pricing and
          rollover risk, and lower administrative costs. Our credit covenants
          remained substantially unchanged as compared to the previous
          facilities, with the only meaningful modification being the removal of
          any net worth restriction. The facility primarily serves as a backup
          to our commercial paper program, which had $416.9 million outstanding
          as of December 31, 2004;

     o    Effective August 31, 2004, we acquired all of the partnership
          interests in Kinder Morgan Wink Pipeline, L.P., formerly Kaston
          Pipeline Company, L.P., from KPL Pipeline Company, LLC and RHC
          Holdings, L.P. for an aggregate consideration of approximately $100.3
          million, consisting of $89.9 million in cash and the assumption of
          $10.4 million of liabilities. The acquisition included a 450-mile
          crude oil pipeline system, consisting of four mainline sections,
          numerous gathering systems and truck off-loading stations. The
          mainline sections, all in the State of Texas, have a total capacity of
          115,000 barrels of crude oil per day. As part of the transaction, we
          entered into a long-term throughput agreement with Western Refining
          Company, L.P. to transport crude oil into Western's 107,000 barrel per
          day refinery in El Paso, Texas. As of the acquisition date, we
          expected to invest approximately $11.0 million over the next five
          years to upgrade the assets;

     o    On September 9, 2004, a non-binding, phase two initial decision was
          issued by an administrative law judge hearing the FERC case on the
          rates charged by our Pacific operations' interstate portion of its
          pipelines. If affirmed by the FERC, the phase two initial decision
          would establish the basis for prospective rates and the calculation of
          reparations for complaining shippers with respect to our Pacific
          operations' West Line and East Line. However, as with the phase one
          initial decision, issued on June 24, 2003, the phase two initial
          decision has no force or effect and must be fully reviewed by the
          FERC, which may accept, reject or modify the decision. A FERC order on
          phase two of the case is not expected before the third quarter of
          2005. Furthermore, any such order may be subject to further FERC
          review, review by the United States Court of Appeals for the District
          of Columbia Circuit, or both;

     o    Effective October 1, 2004, we acquired an additional undivided 5%
          interest in the Cochin Pipeline System from a subsidiary of
          ConocoPhillips Corporation for approximately $10.9 million. We record
          our 49.8% proportionate share of the results of operations of the
          Cochin Pipeline System as part of our Products Pipelines business
          segment;


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<PAGE>


     o    Effective October 6, 2004, we acquired Kinder Morgan River Terminals
          LLC, formerly Global Materials Services LLC, from Mid-South Terminal
          Company, L.P. for an aggregate consideration of approximately $89.6
          million, consisting of $31.8 million in cash and $57.8 million of
          assumed liabilities. Kinder Morgan River Terminals LLC operates a
          network of 21 river terminals and two rail transloading facilities
          primarily located along the Mississippi River system. The network
          provides loading, storage and unloading points for various bulk
          commodity imports and exports. As of the acquisition date, we expected
          to invest an additional $9.4 million over the next two years to expand
          and upgrade the terminals, which are located in 11 Mid-Continent
          states;

     o    On October 13, 2004, we announced that Shell Trading (U.S.) Company
          had assumed ownership of the processing rights at our transmix
          facilities located in Richmond, Virginia; Indianola, Pennsylvania; and
          Wood River, Illinois. In a transaction that closed on September 30,
          2004, Shell Trading purchased the eastern transmix trading business
          formerly owned by Duke Energy Merchants LLC, which included a transmix
          processing agreement with us effective through March 16, 2011;

     o    Effective November 1, 2004, we acquired all of the partnership
          interests in TransColorado Gas Transmission Company from two
          wholly-owned subsidiaries of KMI. TransColorado Gas Transmission
          Company is a Colorado general partnership and, at the date of
          acquisition, owned assets of approximately $284.5 million. As
          consideration for TransColorado, we paid to KMI $211.2 million in cash
          and assumed liabilities of approximately $9.3 million. In addition, we
          issued 1,400,000 common units having a market value of approximately
          $64 million to KMI. TransColorado owns a 300-mile interstate natural
          gas pipeline that originates in the Piceance Basin of western Colorado
          and extends to the Blanco Hub in northwest New Mexico, providing a
          strategic link to the southwestern United States and other key
          markets;

     o    Effective November 5, 2004, we acquired ownership interests in nine
          refined petroleum products terminals in the southeastern United States
          from Charter Terminal Company and Charter-Triad Terminals, LLC for an
          aggregate consideration of approximately $75.2 million, consisting of
          $72.4 million in cash and $2.8 million of assumed liabilities. Three
          terminals are located in Selma, North Carolina, and the remaining
          facilities are located in Greensboro and Charlotte, North Carolina;
          Chesapeake and Richmond, Virginia; Athens, Georgia; and North Augusta,
          South Carolina. We fully own seven of the terminals and jointly own
          the remaining two. The nine facilities have a combined 3.2 million
          barrels of storage. As of the acquisition date, we expected to invest
          an additional $2 million over the next two years to upgrade the
          facilities. All of the terminals are connected to products pipelines
          owned by either Plantation Pipe Line Company or Colonial Pipeline
          Company, and the acquisition will increase our southeast terminal
          storage capacity 76% (to 7.7 million barrels) and terminal throughput
          capacity 62% (to over 340,000 barrels per day);

     o    On November 10, 2004, we completed a public offering of 5,500,000 of
          our common units at a price of $46.00 per unit, less commissions and
          underwriting expenses. On December 8, 2004, we issued an additional
          575,000 units upon the exercise by the underwriters of an
          over-allotment option. We received net proceeds of $268.3 million for
          the issuance of these 6,075,000 common units. At approximately the
          same time as our November public offering, KMR issued 1,300,000 of its
          shares at a price of $41.29 per share, less closing fees and
          commissions. The net proceeds from the offering were used by KMR to
          buy additional i-units from us, and we received net proceeds of $52.6
          million for the issuance of 1,300,000 i-units. We used the proceeds
          from each of these three issuances to reduce the borrowings under our
          commercial paper program;

     o    On November 12, 2004, we closed a public offering of $500 million in
          principal amount of 5.125% senior notes due November 15, 2014. The
          proceeds to us from the issuance of the notes, after underwriting
          discounts and commissions, were approximately $496.3 million, which we
          used to reduce commercial paper debt;

     o    Effective December 1, 2004, we acquired substantially all of the
          assets used to operate the major port distribution facility located at
          the Fairless Industrial Park in Bucks County, Pennsylvania. The
          aggregate cost of the acquisition was approximately $7.5 million,
          consisting of $7.2 million in cash and $0.3 million in assumed
          liabilities. The bulk terminal facility is located on the Delaware
          River and is the largest port on the East Coast for the handling of
          semi-finished steel slabs, which are used as feedstock by domestic
          steel mills. The facility, referred to as our Kinder Morgan Fairless
          Hills Terminal, was purchased from Novolog Bucks


                                       9


<PAGE>


          County, Inc. The port operations at Fairless Hills also include the
          handling of other types of steel and specialized cargo that caters to
          the construction industry and service centers that use steel sheet and
          plate. As of the acquisition date, we expected to invest an additional
          $8.3 million in the facility;

     o    On December 8, 2004, we announced that we expect to declare cash
          distributions of $3.13 per unit for 2005, a 9% increase over our cash
          distributions of $2.87 per unit for 2004. This expectation includes
          contributions from assets owned by us as of the announcement date and
          does not include any projected benefits from unidentified
          acquisitions;

     o    On December 15, 2004, we announced the start of service on our new $95
          million, 70-mile, 20-inch replacement common carrier refined petroleum
          products pipeline between Concord and Sacramento, California. This
          project included replacing an existing 14-inch diameter refined
          products pipeline with a new 20-inch diameter line and rerouting
          portions of the pipeline away from environmentally sensitive areas and
          residential neighborhoods. The capital expansion project significantly
          increases the capacity on the pipeline and provides the necessary
          infrastructure to help meet the region's growing demand for gasoline,
          diesel and jet fuel. Capacity on the new pipeline is approximately
          167,000 barrels per day, and with additional pumping capability,
          maximum capacity could increase to over 200,000 barrels per day;

     o    During 2004, we spent $747.3 million for additions to our property,
          plant and equipment, including both expansion ($628.0 million) and
          maintenance projects ($119.3 million). Our capital expenditures
          included the following:

          o    $302.9 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 and Yates oil field units in West Texas;

          o    $213.8 million in our Products Pipelines segment, mostly related
               to expansion work on our Pacific operations' Concord to
               Sacramento, California products pipeline, the expansion of our
               Pacific operations' East Line products pipeline, described above,
               and to a storage and expansion project at our combined Carson/Los
               Angeles Harbor terminal system in the State of California;

          o    $124.2 million in our Terminals segment, largely related to
               expanding the petroleum products storage capacity at our liquid
               terminal facility located in Carteret, New Jersey and the
               construction of a cement facility at our Dakota bulk terminal
               located in St. Paul, Minnesota, as well as other smaller
               projects; and

          o    $106.4 million in our Natural Gas Pipelines segment, mostly
               related to completing the construction and start up of our
               Cheyenne Market Center and our Katy to Austin, Texas intrastate
               natural gas pipeline project, both described above; and

     o    On February 24, 2005, we announced that we had received the necessary
          permits and approvals from the city of Carson, California, to
          construct new storage tanks as part of a major expansion of our West
          Coast petroleum products storage and transfer terminal located in
          Carson, California. The almost $40 million investment includes the
          addition of ten new tanks that will increase storage capacity at the
          facility by 800,000 barrels (16%) and help meet Southern California's
          growing demand for petroleum products.

(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:


                                       10


<PAGE>


     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 2,500 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 nine 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 six
               terminal facilities on the West Coast that transload and store
               refined petroleum products;

     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 system 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 Kinder Morgan Southeast Terminals LLC, comprised of 23 refined
          petroleum products terminals acquired between December 2003 and
          November 2004;

     o    our 49.8% 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 (a blend of dissimilar refined petroleum products
          that have become co-mingled in the pipeline transportation process)
          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 3,100 miles of refined petroleum products
pipeline and related terminal facilities.


                                       11





<PAGE>


     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, nine commercial airports and 15 military bases. For
2004, 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-Tucson, Arizona corridor. 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;

     o  San Diego Line; and

     o  CALNEV Line.

     The West Line consists of approximately 670 miles of primary pipeline and
currently transports products for 37 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 project also includes the construction
of a major origin pump station. The project is estimated to cost $210 million
and is scheduled to be completed in the first quarter of 2006.

     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


                                       12


<PAGE>


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.

     On December 15, 2004, we announced the start of service on our new $95
million, 70-mile, 20-inch replacement common carrier pipeline between Concord
and Sacramento, California. The project included replacing the existing 14-inch
diameter refined products pipeline with a new 20-inch diameter line and
rerouting portions of the pipeline away from environmentally sensitive areas and
residential neighborhoods. The capital expansion project increases the capacity
on the pipeline from 119,000 barrels per day to 167,000 barrels per day, and
with additional pumping capability, maximum capacity could increase to 200,000
barrels per day.

     The Bakersfield Line is a 100-mile, 8-inch diameter pipeline serving
Fresno, California. The Oregon Line is a 114-mile pipeline serving 13 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 and include:

     o    the Carson Terminal;

     o    the Los Angeles Harbor 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 52% of total
revenues at the facility.

     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


                                       13


<PAGE>


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:

     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 our 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 75 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 970,000 barrels
per day. The Arizona gasoline market is served primarily by us at a market
demand of approximately 121,000 barrels per day. Nevada's gasoline market is
approximately 50,000 barrels per day and Oregon's is approximately 96,000
barrels per day. The diesel


                                       14


<PAGE>


and jet fuel market is approximately 560,000 barrels per day in California,
73,000 barrels per day in Arizona, 40,000 barrels per day in Nevada and 63,000
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. MTBE-blended gasoline has been replaced by
ethanol-blended gasoline. Since ethanol cannot be shipped by pipeline, we are
realizing a reduction in gasoline volumes delivered in California; however, our
overall revenues were not adversely impacted as our terminals receive a fee to
blend ethanol.

     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.

     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 or expanded to
serve specific markets is a continuing competitive factor.

     The use of trucks for product distribution from either shipper-owned
proprietary terminals or from their refining centers continues to compete for
short haul movements by pipeline. The mandated elimination of MTBE and required
substitution of ethanol in California gasoline has 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 began
transporting refined products from refineries on the Gulf Coast to El Paso and
other destinations in Texas in late 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,
Orange County, Mission Valley, and San Diego, California and Phoenix and Tucson,
Arizona and Las Vegas, Nevada. Short haul trucking from the refinery centers is
also a competitive factor to close-in terminals.

     Competitors of our 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. Competition to our 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


                                       15


<PAGE>


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 facility
also has a truck rack that can load in excess of 200 trucks per day and a
railroad 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 control room for the pipeline is located
at the Tampa terminal. 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 2004, the pipeline transported
approximately 103,000 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 800,000 barrels per day. Gasoline is, by far, the
largest component of that demand at approximately 545,000 barrels per day. The
total refined petroleum products demand for the Central Florida region of the
state, which includes the Tampa and Orlando markets, is estimated to be
approximately 350,000 barrels per day, or 44% of the consumption of refined
products in the state. Our market share is approximately 140,000 barrels per
day, or 40% 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 in March and April during spring break and again in
the summer vacation season, and is also heavily influenced by tourism, with
Disney World and other 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 close to the marine
terminals on the east and west coasts of Florida. We are utilizing tariff
incentives to attract volumes to the pipeline that might otherwise enter the
Orlando market area by truck from Tampa or by marine vessel into Cape Canaveral.


                                       16




<PAGE>


     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 system 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.

     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 agricultural
                             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, which requires us to pay approximately $2.2 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 was completed in 1990 and is owned by the
Heartland Pipeline Company. We own a 50% equity interest in Heartland. The
pipeline 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.
Heartland leases 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


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<PAGE>


reserved pipeline capacity, is paid monthly, with an annual adjustment. The 2005
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 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.

     During the first quarter of 2003, and again in the first quarter of 2004,
the North System experienced a general decline in throughput volumes due to a
lack of product supplies caused by shippers (primarily propane shippers)
reducing their inventory levels at the close of the winter season. In addition
to the general decline in throughput volumes, shippers were unable to get all of
their product out of the system, as a significant volume was required to be held
as line-fill. Following numerous discussions and meetings with our shippers in
an attempt to remedy this situation, including a plan to require shippers to
carry a minimum line-fill in our system, the consensus was for us to purchase
product to be used as line-fill and pass the carrying cost on to the shippers
through a cost of service filing with the FERC. A cost of service filing was
made with the FERC to be effective on June 1, 2004, raising our tariff rates by
$0.12 per barrel on product transported north of the Bushton/Conway, Kansas
area. This rate went into effect without protest or intervention.

     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. An affiliate of
ExxonMobil owns the remaining 49% ownership interest. ExxonMobil is the largest
shipper on the Plantation system both in terms of volumes and revenues. We
operate the system pursuant to agreements with Plantation Services LLC and
Plantation 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.


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<PAGE>


     For the year 2004, Plantation delivered an average of 620,363 barrels per
day of refined petroleum products. These delivered volumes were comprised of
gasoline (65%), diesel/heating oil (22%) and jet fuel (13%). Average delivery
volumes for 2004 were 1.3% higher than the 612,451 barrels per day delivered
during 2003. The increase was driven by regional demand growth in all
transportation-related fuels: gasoline up 0.9%; low sulfur diesel up 4.9%; and
jet fuel up 2.8%.

     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 five 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
another pipeline company. These markets represent potential growth opportunities
for the Plantation system.

     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
1.5% (led by a 10% increase in shipments to Ronald Reagan National) in 2004. An
improving domestic economy should help improve jet fuel demand in 2005.

     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 in this report 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.

     On December 11, 2003, KMST acquired seven petroleum products terminals from
ConocoPhillips and Phillips Pipe Line Company for an aggregate consideration of
approximately $15.3 million, consisting of approximately $14.3 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.

     On March 9, 2004, KMST acquired seven additional refined petroleum products
terminals from Exxon Mobil Corporation for an aggregate consideration of
approximately $50.9 million, consisting of approximately $48.2 million in cash
and $2.7 million in assumed liabilities. The terminals are located 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. All seven
of these terminals are served by Plantation and two are also connected to
Colonial.

     On November 5, 2004, KMST acquired ownership interests in nine additional
refined petroleum products terminals from Charter Terminal Company and
Charter-Triad Terminals, LLC for an aggregate consideration of


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<PAGE>


approximately $75.2 million, consisting of approximately $72.4 million in cash
and $2.8 million in assumed liabilities. Three terminals are located in Selma,
North Carolina, and the remaining facilities are located in Greensboro and
Charlotte, North Carolina; Chesapeake and Richmond, Virginia; Athens, Georgia;
and North Augusta, South Carolina. The terminals have a combined storage
capacity of approximately 3.2 million barrels for gasoline, jet fuel and diesel
fuel. We fully own seven of the terminals and jointly own the remaining two. All
of the terminals are connected to products pipelines owned by either Plantation
Pipe Line Company or Colonial Pipeline Company. The acquisition increased our
southeast terminal storage capacity 76% (to 7.7 million barrels) and terminal
throughput 62% (to over 340,000 barrels per day).

     Markets. KMST acquisition and marketing activities are focused on the
Southeastern United States from Mississippi through Virginia, including
Tennessee and Florida. The primary marketing activity involves the receipt of
petroleum products from common carrier pipelines, short-term storage in terminal
tankage, and subsequent loading onto tank trucks. KMST has a physical presence
in markets representing almost 80% of the pipeline-supplied demand in the
Southeast and offers a competitive alternative to marketers seeking a
relationship with a truly independent truck terminal service provider.

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

     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 and TransMontaigne Product
Services represent the other independent terminal operators in this region.

     Cochin Pipeline System

     We own 49.8% of the Cochin pipeline system, a joint venture that operates
an approximate 1,900-mile, 12-inch diameter multi-product pipeline operating
between Fort Saskatchewan, Alberta and Sarnia, Ontario. Effective October 1,
2004, we acquired our most recent ownership interest (5%) from subsidiaries of
ConocoPhillips. An affiliate of BP owns the remaining 50.2% ownership interest
and is the operator of the pipeline.

     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. 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;


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<PAGE>


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

     Cypress Pipeline

     Our Cypress pipeline is an interstate common carrier 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.

     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 liquid 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. Effective September 30, 2004,
Shell Trading (U.S.) Company assumed ownership of the processing rights at our
transmix facilities located in Richmond, Virginia; Indianola, Pennsylvania; and
Wood River, Illinois. Shell Trading purchased the eastern transmix trading
business formerly owned by Duke Energy Merchants LLC, which included a transmix
processing agreement effective through March 16, 2011. At these locations, Shell
procures transmix supply from pipelines and other parties, pays a processing fee
to us, and then sells the processed gasoline and fuel oil through their
marketing and distribution networks. The arrangement includes a minimum
processing volume and fee to us, as well as an opportunity to extend the
processing agreement beyond the 2011 date.

     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 three 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, which is currently not in service,
with a capacity of 55,000 barrels located nearby in Richmond.


                                       21



<PAGE>


     Our Dorsey Junction processing facility is located near Baltimore, Maryland
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 the 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 Colton, and
Shell acquires transmix for processing at Indianola, Richmond and Wood River.
The Dorsey Junction facility is supplied by Colonial Pipeline Company.

     Competition. Placid Refining is our main competitor in the Gulf Coast area.
There are various processors in the Mid-Continent area, primarily
ConocoPhillips, Gladieux Refining and Williams Energy Services, who compete with
our expansion efforts in that market. 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 sales, transportation, storage,
gathering, processing and treating. Within this segment, we own approximately
14,000 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 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. Kinder
          Morgan Texas and Kinder Morgan Tejas are the two largest systems in
          this group, and combined, consist of approximately 5,800 miles of
          intrastate natural gas pipelines 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);


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<PAGE>


     o    our three Rocky Mountain interstate natural gas pipeline systems:
          Kinder Morgan Interstate Gas Transmission LLC, Trailblazer Pipeline
          Company and TransColorado Gas Transmission Company. KMIGT owns a
          4,562-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. TransColorado owns a 300-mile
          natural gas pipeline system that extends from the Western Slope of
          Colorado to northwestern New Mexico. As of December 31, 2004, the
          combined peak transport capacity for our Rocky Mountain pipeline
          systems was approximately 2.5 billion cubic feet per day of natural
          gas, and the combined storage capacity was approximately 10.0 billion
          cubic feet of natural gas;

     o    our Casper and Douglas natural gas gathering systems, which are
          comprised of over 1,500 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

     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
natural gas pipelines with a peak transport capacity of approximately five
billion cubic feet per day and approximately 120 billion cubic feet of natural
gas storage capacity. In addition, the system, through owned assets and
contractual arrangement with third parties, has the capability to process over
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 natural gas
pipeline that stretches from south Texas to Monterrey, Mexico and can transport
up to 375,000 dekatherms per day. The pipeline connects to a 1,000-megawatt
power plant complex and to the PEMEX natural gas transportation system. We have
entered into a 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


                                       23


<PAGE>


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 certain of these new generation facilities to our pipeline
systems in order to maintain our share of natural gas supply for power
generation.

     We serve the Mexico 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 150,000 to 200,000 dekatherms per day of natural gas and
deliveries to Monterrey generally range from 150,000 to 300,000 dekatherms per
day. We primarily provide transport service to these markets on a fee for
service basis, including a significant demand component, which is paid
regardless of actual throughput. Revenues earned from our activities in Mexico
are paid in U.S. dollar equivalent.

     Supply. We purchase our natural gas directly from producers attached to our
system in South Texas, East Texas 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 or third-party facilities. We own two processing plants: our
Texas City Plant in Galveston County, Texas and our Galveston Bay Plant in
Chambers County, Texas, which is currently idle. Combined, these plants can
process 115 million cubic feet per day of natural gas for liquids extraction. In
addition, we have contractual rights to process approximately 735 million 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 155 million cubic feet per day of
natural gas for carbon dioxide removal at our Fandango Complex in Zapata County,
Texas, 50 million cubic feet per day of natural gas at our Indian Rock Plant in
Upshur County, Texas and approximately 45 million cubic feet per day of natural
gas at our Thompsonville Facility located in Jim Hogg County, Texas.

     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 provide 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 4.2 billion cubic feet of
working natural gas capacity and up to 500 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.

     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 in this report
as KMIGT, owns approximately 4,562 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. KMIGT also has the authority to make gas purchases and sales, as
needed for system operations, pursuant to its currently


                                       24


<PAGE>


effective FERC gas tariff. 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 160,000 horsepower. The pipeline system provides storage
services to its customers from its Huntsman Storage Field in Cheyenne County,
Nebraska. On June 1, 2004, KMIGT implemented its Cheyenne Market Center service,
which provides nominated storage and transportation service between its Huntsman
Storage Field and multiple interconnecting pipelines at the Cheyenne Hub. This
service is fully subscribed for a period of ten years and added an incremental
withdrawal capacity of 68 million cubic feet of natural gas per day and
increased the working gas capacity by 3.5 billion cubic feet. The Huntsman
Storage facility now has approximately 39.5 billion cubic feet of total storage
capacity, 16 billion cubic feet of working gas capacity and can withdraw up to
169 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 of the local natural gas distribution companies
typically include residential, commercial, industrial and agricultural
customers. The pipelines interconnecting with KMIGT in turn deliver gas into
multiple markets including some of the largest population centers in the
Midwest. Natural gas demand to power pumps for crop irrigation during the summer
from time-to-time exceeds heating season demand and provides KMIGT relatively
consistent volumes throughout the year.

     Supply. Approximately 15%, by volume, of KMIGT's firm contracts expire
within one year and 39% expire within one to five years. Our affiliates are
responsible for approximately 21% 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.

     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 natural gas in interstate commerce. It does business in
the states of Wyoming, Colorado and Nebraska. 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 it 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


                                       25


<PAGE>


interconnection near Rockport in Weld County, Colorado.

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

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

     Supply. As of December 31, 2004, 6% of Trailblazer's firm contracts, by
volume, expire before one year and 40%, 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. 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. However, on
March 24, 2004, the FERC issued a certificate approving the Cheyenne Plains
pipeline project that was developed by Colorado Interstate Gas Company. This
project, which commenced service in December 2004, allows for the transportation
of 560,000 dekatherms per day of natural gas from Weld County, Colorado to
Greensburg, Kansas and competes with Trailblazer for natural gas pipeline
transportation demand from the Rocky Montitain area. In addition, Cheyenne
Plains received approval from the FERC to expand its facilities to provide an
additional 170,000 dekatherms per day of capacity for a total capacity of
730,000 dekatherms. The proposed expansion is anticipated to go into service in
early 2006. No assurance can be given that additional competing pipelines will
not be developed in the future.

     TransColorado Gas Transmission Company

     TransColorado Gas Transmission Company is a Colorado general partnership
that owns a 300-mile interstate natural gas pipeline that extends form the
Western Slope of Colorado to northwestern New Mexico. KMIGT manages, maintains
and operates TransColorado, for which it is reimbursed at cost. We acquired all
of the ownership interests in TransColorado from KMI effective November 1, 2004.
The TransColorado Pipeline, which extends from approximately 20 miles southwest
of Meeker, Colorado to Bloomfield, New Mexico, has 20 points of interconnection
with five interstate pipelines, one intrastate pipeline, eight gathering
systems, and two local distribution companies, thereby providing relatively
significant flexibility in the receipt and delivery of natural gas. The pipeline
system is powered by five compressor stations in mainline service having an
aggregate of approximately 26,500 horsepower.

     Gas flowing south through the pipeline moves onto the El Paso, Transwestern
and Southern Trail pipeline systems. TransColorado receives gas from two coal
seam natural gas treating plants located in the San Juan Basin of Colorado and
from pipeline and gathering system interconnections within the Paradox and
Piceance Basins of western Colorado. TransColorado provides transportation
services to third-party natural gas producers, marketers, gathering companies,
local distribution companies and other shippers. Pursuant to transportation
agreements and FERC tariff provisions, TransColorado offers its customers firm
and interruptible transportation and interruptible park and loan services. Under
TransColorado's tariffs, firm transportation customers pay reservation charges
each month plus a commodity charge based on actual volumes transported.
Interruptible transportation customers pay a commodity charge based upon actual
volumes transported. The underlying reservation and commodity charges are
assessed pursuant to a maximum recourse rate structure, which does not vary
based on the distance gas is transported. TransColorado has the authority to
negotiate rates with customers if it has first offered service to those
customers under its reservation and commodity charge rate structure.

     TransColorado's revenues and volumes have historically been higher during
the second and third quarters of the calendar year, resulting from two factors:
winter heating market loads to the north of TransColorado and summer air
conditioning market loads to the south of TransColorado.


                                       26




<PAGE>


     Markets. TransColorado acts principally as a feeder pipeline system from
the developing natural gas supply basins on the Western Slope of Colorado into
the interstate natural gas pipelines that lead away from the Blanco Hub area of
New Mexico. TransColorado is the largest transporter of natural gas from the
Western Slope supply basins of Colorado and provides a competitively attractive
outlet for that developing natural gas resource. In 2004, TransColorado
transported an average of 518,495 dekatherms per day of natural gas from these
supply basins. TransColorado provides a strategically important link between the
underdeveloped gas supply resources on the Western Slope of Colorado and the
greater southwestern United States marketplace.

     Supply. During 2004, 73% of TransColorado's transport business was with
producers or their own marketing affiliates, 4% was with third-party marketers
and the remaining 23% was primarily with gathering companies. Approximately 70%
of TransColorado's transport business in 2004 was conducted with its three
largest customers. All of TransColorado's pipeline capacity is committed under
firm transportation contracts that extend at least through year-end 2007.
TransColorado's pipeline capacity is 65% subscribed during 2007 through 2011 and
TransColorado is actively pursuing contract extensions and or replacement
contracts to increase firm subscription levels beyond 2007.

     On October 6, 2004, TransColorado announced an approximate $20 million
expansion project to add 300,000 dekatherms per day of incremental natural gas
transportation capacity. As a result of this expansion, natural gas on the
northern portion of TransColorado's pipeline will be able to flow northward as
well as southward. The expansion is supported by a long-term contract with an
undisclosed shipper and includes commitments for up to 280,000 dekatherms per
day of natural gas. The contract runs through 2015 with an option for a 5-year
extension.

     Competition. TransColorado competes with other transporters of natural gas
in each of the natural gas supply basins it serves. These competitors include
both interstate and intrastate natural gas pipelines and natural gas gathering
systems. TransColorado is the most recent interstate pipeline entrant into each
of the competitive supply markets of the Paradox, Piceance and San Juan Basins
of western Colorado. Notwithstanding this fact, we believe that TransColorado
generally is looked upon favorably by shippers because it provides distinct
advantages of larger system capacity and more direct access to market outlets
than its competitors.

     TransColorado's shippers compete for market share with shippers drawing
upon gas production facilities within the New Mexico portion of the San Juan
Basin. TransColorado has phased its past construction and expansion efforts to
coincide with the ability of the interstate pipeline grid at Blanco, New Mexico
to accommodate greater natural gas volumes. The overall San Juan Basin gas
production base had been a perennial factor restricting the growth pace of
TransColorado's transport from the central Rockies natural gas supply basins.
Natural gas production from the San Juan Basin peaked during the first quarter
of 2000 and has since declined on an overall basis by 10%. TransColorado's
transport concurrently ramped up over that period such that TransColorado now
enjoys a growing share of the outlet from the San Juan Basin to the southwestern
United States marketplace.

     Historically, the competition faced by TransColorado with respect to its
natural gas transportation services has generally been based upon the price
differential between the San Juan and Rocky Mountain basins. The Kern River Gas
Transmission expansion project, placed in service in May 2003, has had the
effect of reducing that price differential. However, given the increased number
of direct connections to production facilities in the Piceance and Paradox
basins and the aggressive gas supply development in each of those basins, we
believe that TransColorado's transport business will be less susceptible to
changes in the price differential in the future.

     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 26 million cubic feet
per day of natural gas from 650 active receipt points. Douglas Gathering has an
aggregate 20,650 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.


                                       27



<PAGE>


     The Casper gathering system is comprised of approximately 32 miles of
4-inch to 8-inch diameter pipeline gathering approximately four million cubic
feet per day of natural gas from four 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 upstream 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
Merit 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 report 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, 82,000 horsepower
of compression at 22 field compressor stations and two carbon dioxide treating
plants. A majority of the natural gas on the system moves through 8-inch to
16-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 in
this report as Coyote Gulch. Coyote Gulch is a joint venture that was organized
in December 1996. Enterprise Field Services LLC 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 in this report 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


                                       28


<PAGE>


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, 19,620 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
41 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 185
miles of 4-inch to 14-inch diameter gathering pipeline and 40,852 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 in this report as KMCO2. Carbon dioxide is
used in enhanced oil recovery projects as a flooding medium for recovering crude
oil from mature oil fields. Our carbon dioxide pipelines and related assets
allow us to market a complete package of carbon dioxide supply, transportation
and technical expertise to the customer. Together, our CO2 business segment
produces, transports and markets carbon dioxide for use in enhanced oil recovery
operations 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 321-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 lesser interests in the Sharon Ridge unit, the Reinecke
          unit and the MidCross unit, all of which are located in the Permian
          Basin of West Texas;

     o    our interests in gasoline plants, including an approximate 22% working
          interest 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; and

     o    our 450-mile Wink crude oil pipeline system located in West Texas and
          used to transport crude oil from the Permian Basin to Western Refining
          Company, L.P.'s crude oil refinery located in El Paso, Texas.

     Carbon Dioxide Reserves

     We own approximately 45% of, and operate, the McElmo Dome unit, which
contains more than 10 trillion cubic feet of 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 49
wells that produce at individual rates of up to 53 million cubic feet per day.


                                       29



<PAGE>


     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 307 million cubic feet per day, with production coming from more
than 350 wells in the Tubb Sandstone at 2,300 feet.

     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. 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 Trinity CO2,
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 300 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 of carbon dioxide 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 approximately 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 are currently
delivering through it approximately 70 million cubic feet per day of carbon
dioxide.

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

     Competition. Our ownership interests in the Central Basin, Cortez and Bravo
pipelines are in direct competition with other carbon dioxide pipelines. We also
compete with other interest owners in McElmo Dome and Bravo


                                       30


<PAGE>


Dome for transportation of carbon dioxide to the Denver City, Texas market area.

     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 56,000 acres located in the Permian Basin in Scurry County, Texas.
SACROC was discovered in 1948 and has produced over 1.27 billion barrels of oil
since inception. We have continued the development of the carbon 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 its partners in
accordance with its partnership agreement.

     As of December 2004, the SACROC unit had 332 producing wells, and the
purchased carbon dioxide injection rate was 339 million cubic feet per day, up
from an average of 317 million cubic feet per day as of December 2003. The oil
production rate as of December 2004 was approximately 33,000 barrels of oil per
day, up from approximately 23,000 barrels of oil per day as of December 2003.

     The Yates unit is also one of the largest oil fields ever discovered in the
United States. It is estimated that it originally held more than five billion
barrels of oil, of which about 28% has been produced. The field, discovered in
1926, is comprised of approximately 26,000 acres located about 90 miles south of
Midland, Texas. 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 also acquired the crude
oil gathering lines and equipment surrounding the Yates field. We now own a
nearly 50% ownership interest in the Yates field unit.

     As of December 2003, the Yates unit was producing about 18,000 barrels of
oil per day. Our plan has been 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. We are
implementing our plan and as of December 2004, the Yates unit was producing
approximately 22,000 barrels of oil per day. Unlike our operations at SACROC,
where we use carbon dioxide and water to drive oil to the producing wells, we
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.

     The following table sets forth productive wells, service wells and drilling
wells in the oil and gas fields in which we own interests as of December 31,
2004:


                  Productive Wells (a)   ServiceWells (b)  Drilling Wells (c)
                 ---------------------  -----------------  ------------------
                  Gross        Net       Gross      Net    Gross      Net
                 ---------  ---------   -------  --------  --------  --------
    Crude Oil...    2,509     1,520        975       723       2        2
    Natural Gas.        7         3          -         -       -        -
                 ---------  ---------   -------  --------  --------  --------
     Total Wells.   2,516     1,523        975       723       2        2
                 =========  =========   =======  ========  ========  ========

___________

(a)  Includes active wells and wells temporarily shut-in. As of December 31,
     2004, we did not operate any gross wells with multiple completions.

(b)  Consists of injection, water supply and disposal wells.

(c)  Consists of development wells in the process of being drilled as of
     December 31, 2004.


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<PAGE>


     The oil and gas producing fields in which we own interests are located in
the Permian Basin area of West Texas. The following table reflects our net
productive and dry wells that were completed in each of the three years ended
December 31, 2004, 2003 and 2002:

                                        2004    2003    2002
                                      -------  ------  -------
                Productive
                 Development.......       31      69      41
                 Exploratory.......        -       -       -
                Dry
                 Development.......        -       -       -
                 Exploratory.......        -       -       -
                                      -------  ------  -------
                Total Wells........       31      69       41
                                      =======  ======  =======

_________

Notes: The above table includes wells that were completed during each year
       regardless of the year in which drilling was initiated, and does not
       include any wells where drilling operations were not completed as of the
       end of the applicable year. Also, the table includes our previous 15%
       equity interest in MKM Partners, L.P. MKM Partners, L.P was dissolved on
       June 30, 2003. Development wells include wells drilled in the proved area
       of an oil or gas resevoir.


     The following table reflects the developed and undeveloped oil and gas
acreage that we held as of December 31, 2004:

                                       Gross            Net
                                    -----------     -----------
                Developed Acres.....   61,928          58,438
                Undeveloped Acres...    7,839           7,227
                                    -----------     -----------
                 Total..............   69,767          65,665
                                    ===========     ===========

     See Note 19 to our consolidated financial statements included in this
report for additional information with respect to our oil and gas producing
activities.

     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. Production of natural gas liquids
at the Snyder gasoline plant has increased from approximately 9,076 barrels per
day as of December 2003 to approximately 13,375 barrels per day as of December
2004.

     Crude Oil Pipeline

     Effective August 31, 2004, we acquired all of the partnership interests in
Kaston Pipeline Company, L.P., which we renamed Kinder Morgan Wink Pipeline,
L.P. The acquisition included a 450-mile crude oil pipeline system, consisting
of four mainline sections, numerous gathering systems and truck off-loading
stations. The mainline sections are all located within the State of Texas, and
the 20-inch diameter segment that runs from Wink to El Paso has a total capacity
of 115,000 barrels of crude oil per day.

     As part of the transaction, we entered into a long-term throughput
agreement with Western Refining Company, L.P. to transport crude oil into
Western's 107,000 barrel per day refinery in El Paso. The acquisition allows us
to better manage crude oil deliveries from our oil field interests in West
Texas.

Terminals

     Our Terminals segment includes the operations of our coal and dry-bulk
material services, including all transload, engineering and other in-plant
services, as well as all of the operations of our petroleum and
petrochemical-related liquids terminal facilities. Combined, the segment is
composed of approximately 75 owned or


                                       32


<PAGE>


operated liquids and bulk terminal facilities, and more than 55 rail
transloading and materials handling facilities located throughout the United
States.

     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. As
part of our bulk terminal operations, we own or operate 18 petroleum coke or
coal 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. In
2004, we handled approximately 6.5 million tons of petroleum coke and
approximately 27.2 million tons of coal. Combined, our dry-bulk and material
transloading facilities handled approximately 67.7 million tons of coal,
petroleum coke and other dry-bulk materials in 2004, and our transloading
operations handled approximately 75,000 rail cars.

     Our liquids terminal operations primarily store refined petroleum products,
petrochemicals, industrial chemicals, and vegetable oil products, in aboveground
storage tanks and transfer products to and from pipelines, tank trucks, tank
barges, and tank rail cars. Combined, our liquids terminal facilities possess
liquids storage capacity of approximately 36.7 million barrels, and in 2004,
these terminals handled approximately 556 million barrels of clean petroleum,
petrochemical and vegetable oil products for approximately 250 different
customers.

     We group our bulk and liquids terminal operations into nine regions. This
structure allows management to organize and evaluate segment performance and to
help make operating decisions and allocate resources. The following is a listing
of our nine regions and a summary of the competition faced by our Terminals
segment.

     Terminals Segment - Regions

     o Midwest             o Northeast                   o Mid-Atlantic
     o Southeast           o Lower Mississippi River     o Gulf Coast
     o West Coast          o Materials Services          o Ferro Alloys


     Midwest Region

   o Argo          o Chicago            o Cincinnati River   o Cincinnati Bulk
   o Queen City    o Dravosburg         o Milwaukee          o Dakota
   o Pinney Dock   o Owensboro Gateway  o Evansville         o Ghent
   o Louisville    o Nebraska City      o Omaha              o St. Joe

     The Midwest region includes facilities that service industry in the Chicago
area and provide products to end-user markets in high population areas along the
Ohio River. The facilities handle a wide variety of liquid products, including
clean petroleum products, asphalt and residual oil, commodity chemicals, special
chemicals and food grade liquids. The services provided at these facilities
include receiving and discharging products via pipelines, vessels, tank cars and
tank trucks; storing productrs; transferring products; performing specialty
handling services (heating, cooling, nitrogen, etc.); and performing drumming
services.

     The region includes two facilities in the Chicago area: one facility is in
Argo, Illinois, approximately 14 miles southwest of downtown Chicago. The other
facility is located in the Port of Chicago along the Calumet River. The Argo
facility is a large throughput fuel ethanol facility and a major break bulk
facility for large chemical manufacturers and distributors. It 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, and has a direct connection to Midway Airport. The Canadian
National railroad services this facility. The Port of Chicago facility handles a
wide variety of liquids chemicals with a working capacity of approximately
741,000 barrels in tanks ranging from 12,000 gallons to 55,000 barrels. The
facility provides access to a full slate of transportation options, including a
deep water barge/ship berth on Lake Calumet, and offers services including truck
loading and off-loading, iso-container


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<PAGE>


handling and drumming. There are two ship docks and four barge docks, and the
facility is served by the Norfolk Southern railroad.

     The Midwest Region also includes two facilities along the Ohio River in
Cincinnati, Ohio. The total storage is approximately 905,000 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. The facilities provide storage for
asphalt, heavy oils, and commodity and specialty chemicals. They also offer
warehouse services and serve dry bulk handling needs, including salt, coal, soda
ash, and agricultural commodities.

     We also own a bulk terminal located in Dravosburg, Pennsylvania, just south
of Pittsburgh along the Monongahela River. There are approximately 242,000
barrels of storage in tanks ranging from 1,200 barrels to 38,000 barrels. There
are two barge docks and NS railroad provides rail service. The facility
primarily stores asphalt, distillates, wax and other commodities, and offers
handling services.

     Our Midwest region also includes our Milwaukee and Dakota dry-bulk
commodity facilities, located in Milwaukee, Wisconsin and St. Paul, Minnesota,
respectively. The Milwaukee terminal is located on 34 acres of property leased
from the Port of Milwaukee. Its major cargoes are coal and bulk de-icing salt.
The Dakota terminal is on 55 acres in St. Paul and primarily handles salt and
grain products. In the fourth quarter of 2004, we completed the construction of
a new cement loading facility at the Dakota terminal. The project's cost was
approximately $20 million, and the facility covers nearly nine acres and
includes an unloading system, seven storage silos, a loading and weighing
system, and electrical and compressed air systems to move the cement.

     Included among the remaining Midwest terminals are our Pinney Dock and
Owensboro Gateway terminals. Our Pinney Dock terminal is located in Ashtabula,
Ohio along Lake Erie. It handles iron ore, titanium ore, magnetite and other
aggregates. Pinney Dock has six docks with 15,000 feet of vessel berthing space,
200 acres of outside storage space, 400,000 feet of warehouse space and two
45-ton gantry cranes. The Owensboro Gateway terminal, located near 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.

     As a result of our acquisition of Kinder Morgan River Terminals LLC,
formerly Global Material Services LLC, in October 2004, we added to our Midwest
network of terminals, acquiring terminals located in Evansville, Indiana; Ghent,
Kentucky; Louisville, Kentucky; Nebraska City, Nebraska; Omaha, Nebraska; and
St. Joseph, Missouri. These facilities handle a wide range of products including
steel, aluminum, scrap, grain, gypsum, coal, pig iron, fertilizer, silicon
metals, stainless slabs, iron, feeds, and lumber.

     Northeast Region

     o Carteret        o Perth Amboy      o Newark        o Camden

     The Northeast region services the northeastern part of the United States
from the Port of Philadelphia to the New York Harbor. The facilities in the
Northeast region handle a wide variety of liquids products ranging from
petroleum products to specialty chemicals. The services provided at these
facilities include storing products, and receiving and discharging products via
pipelines, vessels, tank cars, tank trucks and inter-modal transfers, utilizing
a wide array of automated systems for special product handling.

     The region includes our two liquids facilities in the New York Harbor area:
one in Carteret, New Jersey and the other in Perth Amboy, New Jersey. The
Carteret facility is located along the Arthur Kill River just south of New York
City and has a capacity of approximately 7.7 million barrels of petroleum and
petrochemical products, of which 1.1 million barrels have been added since our
acquisition of the Carteret terminal in January 2001. In addition, in October
2003, we completed the construction of a new 16-inch diameter pipeline at
Carteret that connects to the Buckeye pipeline system, a major products pipeline
serving the East Coast. Our Carteret 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 the CSX and Norfolk Southern
railroads service the facility. The Perth Amboy facility is also located along
the Arthur Kill River and has a capacity of approximately 2.3 million barrels of
petroleum and petrochemical products. Tank sizes range from 2,000 barrels to
300,000 barrels. The Perth Amboy terminal provides chemical and petroleum
storage and handling, as well as dry-bulk handling of salt and aggregates.


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In addition to providing product movement via vessel, truck and rail, Perth
Amboy has direct access to the Buckeye and Colonial pipelines. The facility has
one ship dock and one barge dock, and is connected to the CSX and Norfolk
Southern railroads.

     Our two New Jersey facilities offer a viable alternative for moving
petroleum products between the refineries and terminals throughout the New York
Harbor and both are New York Mercantile Exchange delivery points for gasoline
and heating oil. Both facilities are connected to the Intra Harbor Transfer
Service, an operation that offers direct outbound pipeline connections that
allow product to be moved from over 20 Harbor delivery points to destinations
north and west of New York City.

     The Northeast region also includes the assets of our Port Newark bulk
terminal located at Port Newark, New Jersey and our Camden bulk terminal,
located along the Delaware River in Camden, New Jersey. Our Port Newark facility
offers almost 13 acres of outdoor storage for both de-icing and industrial salt,
vermiculite and other bulk products. Its assets include three floating cranes,
nine wheel loaders and three track bulldozers. The facility allows us to offer
ship, truck and rail storage, ship load out to trucks or rail, or truck and rail
load out to ships. Our Camden facility transfers scrap metal, vermiculite and
other mineral products.

     Mid-Atlantic Region

     o Pier IX         o Shipyard River   o Philadelphia   o Chesapeake Bay
     o Fairless Hills  o Cora             o Grand Rivers   o North Charleston

     This region includes our Pier IX Terminal 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. For coal, the terminal offers
blending services and rail to storage or direct transfer to ship; for other dry
bulk products, the terminal offers ship to storage to rail or truck. In
addition, the Pier IX Terminal operates a cement facility, which has the
capacity to transload over 400,000 tons of cement annually. Since late 2002,
Pier IX has operated 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 2004
were 3.1 million tons. Our Pier IX Terminal exports coal to foreign markets,
serves power plants on the eastern seaboard of the United States, and imports
cement pursuant to a long-term contract. 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.

     Also included in the Mid-Atlantic region is our Shipyard River Terminal,
located in Charleston, South Carolina. Shipyard is able to unload, store and
reload coal imported from various foreign countries. The imported coal is often
a cleaner-burning, low-sulfur coal and it is used by local utilities to comply
with the U.S. Clean Air Act. Shipyard River Terminal has the capacity to handle
approximately 2.5 million tons of coal and petroleum coke per year and offers
approximately 300,000 tons of total storage of which 50,000 tons are under roof.

     Situated approximately four miles north of Shipyard, is our North
Charleston Terminal, which we acquired in April 2004. This facility sits on 30
acres of land and has the potential to handle dry bulk as well as liquids. In
aggregate terms, the facility can store 430,000 barrels of liquids in seven
tanks. Both CSX and NS have railroad service nearby.

     Our Philadelphia, Pennsylvania liquids terminal is located on the Delaware
River and offers a storage capacity of over 1.2 million barrels. A variety of
tank system configurations are available including stainless steel and pressure
vessels for the storage of specialty chemicals. The storage and handling of
petroleum and petroleum based products are also strong components in
Philadelphia's base service.

     Our Chesapeake Bay bulk terminal facility located at Sparrows Point,
Maryland, offers stevedoring services, storage, and rail, ground, or water
transportation for products such as coal, petroleum coke, iron and steel slag,
and other mineral products. It offers both warehouse and approximately 100 acres
of open storage.

     Effective December 1, 2004, we acquired substantially all of the assets
used to operate the major port distribution facility located at the Fairless
Industrial Park in Bucks County, Pennsylvania. Opened in 1997 and


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<PAGE>


recognized as a major steel distribution facility, the terminal is referred to
as our Kinder Morgan Fairless Hills Terminal. It is located on the bend of the
Delaware River below Trenton, New Jersey and is the largest port on the East
Coast for the handling of semi-finished steel slabs. The port operations at
Fairless Hills also include the handling of other types of steel and specialized
cargo that caters to the construction industry and service centers that use
steel sheet and plate. The port has four ship berths with a total length of
2,200 feet and a maximum draft of 38.5 feet. It contains two mobile harbor
cranes and is served by connections to two Class I rail lines: CSX and Norfolk
Southern.

     The region also includes two large coal terminals: our Cora terminal and
our Grand Rivers terminal. 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 and is currently 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. Our Cora terminal sits on the mainline of the Union Pacific
Railroad and is strategically positioned to receive coal shipments from the
western United States.

     Our Grand Rivers terminal is a coal transloading and storage facility
located along the Tennessee River just above the Kentucky Dam. The terminal is
operated on land under easements with an initial expiration of July 2014 and has
current annual throughput capacity of approximately 12 million tons with a
storage capacity of approximately one million tons. 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.

     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 increased
use of western low sulfur coal originating in Wyoming, Colorado and Utah. 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 and Grand Rivers terminals 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 2004, four
major customers accounted for approximately 90% of all the coal loaded through
our Cora Terminal.

     Southeast Region

     o Tampaplex             o Port Sutton          o Port Manatee
     o Hartford Street       o Elizabeth River      o Nassau
     o Blackpoint

     This region includes our Kinder Morgan Tampaplex terminal, a marine
terminal acquired in December 2003 and located in Tampa, Florida. 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 terminal also includes an inland bulk storage
warehouse facility used for overflow cargoes from our Port Sutton import
terminal, which is also located in Tampa. Port Sutton sits on 16 acres of land
and offers 200,000 tons of covered storage. Primary products handled in 2004
included fertilizers, salt, ores, and liquid chemicals. Also in the Tampa Bay
area are our Port Manatee and Hartford Street terminals. Port Manatee has four
warehouses which can store 130,000 tons of bulk products. Products handled at
Port Manatee include fertilizers, ores and other general cargo. At our


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Hartford Street terminal, anhydrous ammonia and fertilizers are handled and
stored in two warehouses with an aggregate capacity of 23,000 net tons.

     The Southeast region also includes our Elizabeth River bulk terminal,
located in Chesapeake, Virginia, and our Nassau bulk terminal, located in
Fernandina Beach, Florida. The Elizabeth River terminal offers over 500,000
square feet of covered storage and approximately ten acres of outdoor storage
for products such as fertilizers, ores and minerals and various feeds and
grains. Nassau offers approximately 180,000 square feet of warehouse storage and
ten acres of container yard storage, and provides stevedoring services and
containerized cargo services for various forest products.

   Lower Mississippi River (Louisiana) Region

   o Harvey            o St. Gabriel          o IMT                o Gramercy
   o Barge Canal Dock  o BR Liquid Dock       o Chalmette          o Amory Bulk
   o Belle Helene      o Ft. Smith Warehouse  o W. Memphis Reload  o W. Memphis
                                                                     Terminal
   o Decatur           o Vicksburg            o Delisle            o Ft. Smith
                                                                     Terminal
   o Globalplex        o Great Lakes Carbon   o Guntersville       o Helena
   o Memphis Terminal  o Pine Bluff           o Port Arthur        o P.C.S.


     The region consists of various bulk and liquid terminal facilities and
related assets located primarily on the southern edge of the lower Mississippi
River. These terminals serve customers in the alumina, cement, salt, soda ash,
ilmenite, fertilizer, ore and other industries seeking specialists who can
build, own and operate terminals.

     Two of the region's largest liquids facilities in South Louisiana are: our
Port of New Orleans facility located in Harvey, Louisiana, and our St. Gabriel
terminal, located near a major petrochemical complex in Geismar, Louisiana. The
New Orleans facility handles a variety of liquids products such as chemicals,
vegetable oils, animal fats, alcohols and oil field products. It has
approximately three 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 can be accessed
by vessel, barge, tank truck, or rail, and also provides ancillary services
including drumming, packaging, warehousing, and cold storage services. Our St.
Gabriel 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 340,000 barrels of tank
capacity and the tanks vary in sizes ranging from 1,500 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.

     The region also includes our 66 2/3% ownership interest in the
International Marine Terminals Partnership. IMT operates a bulk commodity
transfer terminal facility located in Port Sulphur, Louisiana. In 2004, the
facility handled approximately 11.9 million tons of iron ore, coal, petroleum
coke and barite. The Port Sulphur location is a multi-purpose import and export
facility that utilizes land and a dock facility. It contains storage capacity of
approximately 50 acres that can handle 1.3 million tons of coal and/or petroleum
coke. An additional 100 acres is currently undeveloped.

     The Lower Mississippi Region also has in-plant operations, where we staff
and operate the loading and unloading equipment for specific customers. For
example, at our Chalmette, Louisiana facility, we load barges with petroleum
coke; at our Gramercy bulk terminal, located in Mt. Airy, Louisiana, we provide
rail switching services and we transfer alumina from railcars to barges.

     Gulf Coast Region

     o Pasadena                          o Galena Park

     This region includes our Houston, Texas terminal complex, located in
Pasadena and Galena Park, Texas, along the Houston Ship Channel. Recognized as a
distribution hub for Houston's refineries situated on or near the Houston Ship
Channel, the Pasadena and Galena Park terminals are the western Gulf Coast
refining community's central interchange point. The complex has approximately
17.7 million barrels of capacity and is connected via pipeline to 14 refineries,
four petrochemical plants and ten major outbound pipelines.


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     Since our acquisition of the terminal complex in January 2001, we have
added more than one million barrels of new storage capacity, as refinery outputs
along the Gulf Coast have continued to increase. We have also upgraded our
pipeline manifold connection with the Colonial pipeline system, added pipeline
connections to new refineries and expanded our truck rack. In addition, the
facilities have four ship docks and seven barge docks for inbound and outbound
movement of products. The terminals are served by the Union Pacific railroad.

     West Region

     o Benicia          o LAXT           o Longview       o Portland
     o Vancouver

     We own or operate five bulk terminals located primarily on the West Coast.
These terminals serve customers in the alumina, petroleum coke, salt, soda ash,
fertilizer, and other dry bulk product industries.

     The West region includes our Portland Bulk Terminal #4 facility and our
Benicia Coke terminal. Portland Bulk Terminal #4 is located in Portland, Oregon
and exports approximately two million tons of soda ash per year to markets in
southeast Asia. It has an annual capacity of approximately 3.6 million tons. The
Benicia Coke terminal, located in Benicia, California, takes fluid bed green
petroleum coke from railcars to storage silos and from storage to ship. It has
an annual capacity of approximately 350,000 tons.

     Also included in the West region is the Los Angeles Export Terminal, where
operations primary consist of loading vessels carrying coal and petroleum coke.
LAXT, which is served by the Union Pacific railroad, has two million tons of
outdoor storage space and 100,000 tons of covered storage space.

     Materials Services (rail transloading) Region

     o Transloading (55) o Brooklyn Junction  o Moundsville  o New Johnsonville

     This region primarily includes the rail-transloading operations owned by
Kinder Morgan Materials Services LLC, referred to in this report as KMMS. KMMS
operates approximately 55 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 these terminal
facilities. Approximately 50% of the products handled by KMMS are liquids,
including an entire spectrum of liquid chemicals, and 50% are dry bulk products.
Many of the facilities are equipped for bi-modal operation (rail-to-truck, and
truck-to-rail). KMMS also designs and builds transloading facilities, performs
inventory management services, and provides value-added services such as
blending, heating and sparging.

     Ferro Alloys Region

     o Chicago               o Decatur              o Houston
     o Industry              o Mingo Junction       o Netherlands

     The terminal operations included in our Ferro Alloys region were acquired
as part of our acquisition of Kinder Morgan River Terminals LLC in October 2004.
The region includes six terminal facilities or locations that specialize in the
handling of ferro alloys, pig iron and other bulk supplies for the metals
industries. Each terminal provides general commodity or alloy services as needed
by local markets.

     Engineering and Other

     This segment includes the engineering operations of RCI Holdings, Inc., a
major engineering and construction management company. RCI is a wholly-owned
subsidiary that specializes in providing design and construction services for
dry bulk material handling terminals. Their offices are located in Metairie,
Louisiana, and Columbus, Ohio.


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<PAGE>


   Competition

     We are one of the largest independent operators of liquids and bulk
terminals in North America. Our primary competitors are Magellan, Kaneb, IMTT,
Vopak, Oil Tanking, TransMontaigne, and Savage Industries.

     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. 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.

     Two new coal terminals that compete with our Cora terminal and our Grand
Rivers terminal were completed in 2003. While our Cora and Grand Rivers
terminals are modern high capacity coal terminals, in 2004, some volume was
diverted to the new terminals by the Tennessee Valley Authority in order to
promote increased competition. Our Pier IX terminal competes primarily with two
modern coal terminals located in the same Virginian port complex as our Pier IX
terminal.

Major Customers

     Our total operating revenues are derived from a wide customer base. For
each of the years ended December 31, 2004, 2003 and 2002, only one customer
accounted for more than 10% of our total consolidated revenues. Total
transactions with CenterPoint Energy accounted for 14.3% of our total
consolidated revenues during 2004, 16.8% of our total consolidated revenues
during 2003 and 15.6% of our total consolidated revenues during 2002. 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 Tejas on January 31, 2002. Due to this acquisition
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 the beginning of 2002 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 from the previous year. A pipeline must, as a general rule, utilize the
indexing methodology to change its rates. The FERC, however, uses
cost-of-service ratemaking, market-based rates and settlement rates as
alternatives to the indexing approach in certain specified circumstances.

     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 filed for
indexed rate adjustments on a number of our petroleum products pipelines and
realized benefits from the new index beginning in the second quarter of 2003.
Rate adjustments pursuant to the index were made on a number of pipeline systems
in 2004.


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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 Note 16
to our consolidated financial statements included elsewhere in this report.

     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 No. 436 (1985) requiring open-access, nondiscriminatory
          transportation of natural gas;

     o    Order No. 497 (1988) which set forth new standards and guidelines
          imposing certain constraints on the interaction between interstate
          natural gas pipelines and their marketing affiliates and imposing
          certain disclosure requirements regarding that interaction; and

     o    Order No. 636 (1992) which required interstate natural gas pipelines
          that perform open-access transportation under blanket certificates to
          "unbundle" or separate their traditional merchant sales services from
          their transportation and storage services and to provide comparable
          transportation and storage services with respect to all natural gas
          supplies whether purchased from the pipeline or from other merchants
          such as marketers or producers.

     Natural gas pipelines must now separately state the applicable rates for
each unbundled service they provide (i.e., for the natural gas commodity,
transportation and storage). Order 636 contains a number of procedures designed
to increase competition in the interstate natural gas industry, including:

     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>


     On November 25, 2003, the Federal Energy Regulatory Commission issued Order
No. 2004, adopting revised Standards of Conduct that apply uniformly to
interstate natural gas pipelines and public utilities. In light of the changing
structure of the energy industry, these Standards of Conduct govern
relationships between regulated interstate natural gas pipelines and all of
their energy affiliates. These new Standards of Conduct were designed to
eliminate the loophole in the previous regulations that did not cover an
interstate natural gas pipeline's relationship with energy affiliates that are
not marketers. The rule is designed to prevent interstate natural gas pipelines
from giving an undue preference to any of their energy affiliates and to ensure
that transmission is provided on a nondiscriminatory basis. In addition, unlike
the prior regulations, these requirements apply even if the energy affiliate is
not a customer of its affiliated interstate pipeline. The effective date of
Order No. 2004 was September 22, 2004. Our interstate natural gas pipelines have
implemented compliance with these Standards of Conduct. Please refer to Note 16
to our consolidated financial statements included elsewhere in this report for
additional information regarding FERC Order No. 2004 and other Standards of
Conduct Rulemaking.

     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 Note 16 to our consolidated financial
statements.

     Safety Regulation

     Our interstate pipelines are subject to regulation by the United States
Department of Transportation and our intrastate pipelines and other operations
are subject to comparable state regulations with respect to their design,
installation, testing, construction, operation, replacement and management. 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, governing 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, and the U.S. DOT has approved our qualification program. We believe
that we are in substantial compliance with this law's requirements and have
integrated appropriate aspects of this pipeline safety law into our Operator
Qualification Program, which is already 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.

     Certain of our products pipelines and natural gas pipelines have been
issued orders and civil penalties by the U.S. DOT's Office of Pipeline Safety
concerning alleged violations of certain federal regulations concerning our
pipeline Integrity Management Program. However, we dispute some of the findings,
disagree that civil penalties are


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<PAGE>


appropriate for them, and have requested an administrative hearing on these
matters according to the U.S. DOT regulations. Information on these matters is
more fully described in Note 16 to our consolidated financial statements.

     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.

     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 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
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 35 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 and safety or the environment.
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


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<PAGE>


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 accrued an environmental reserve in the amount of $40.9 million as of
December 31, 2004. Our reserve estimates range in value from approximately $40.9
million to approximately $77.6 million, and we have recorded a liability equal
to the low end of the range. 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. Virtually all of these
properties were owned by others before us. 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. Virtuallly all 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 the facilities 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 or "CERCLA," and analogous state laws, impose
joint and several liability, without regard to fault or the legality of the
original conduct, on certain classes of "potentially responsible persons" for
releases of "hazardous substances" into the environment. These persons include
the owner or operator of a site and companies that disposed 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 natural resource damages, if any. Although "petroleum" is excluded from
CERCLA's definition of a "hazardous substance," in the course of our ordinary
operations, we have and will generate materials that may fall within the
definition of "hazardous substance." By operation of law, if we are determined
to be a potentially responsible person, we may be responsible under CERCLA for
all or part of the costs required to clean up sites at which such materials are
present, in addition to compensation for natural resource damages, if any.

     Clean Air Act

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


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<PAGE>


     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. Depending on the nature of those
requirements and any additional requirements that may be imposed by state and
local regulatory authorities, we may be required to incur certain capital
expenditures over the next several years for air pollution control equipment in
connection with maintaining or obtaining operating permits and approvals and
addressing other air emission-related issues.

     Due to the broad scope and complexity of the issues involved and the
resultant complexity and nature of the regulations, full development and
implementation of many Clean Air Act regulations have been delayed. Until such
time as the new Clean Air Act requirements are implemented, we are unable to
fully estimate the effect on earnings or operations or the amount and timing of
such required capital expenditures. At this time, however, we do not believe
that we will be materially adversely affected by any such requirements.

     Clean Water Act

     Our operations can result in the discharge of pollutants. The Federal Water
Pollution Control Act of 1972, as amended, also known as the Clean Water Act,
and analogous state laws impose restrictions and controls regarding the
discharge of pollutants into state waters or waters of the United States. The
discharge of pollutants into regulated waters is prohibited, except in
accordance with the terms of a permit issued by applicable federal or state
authorities. The Oil Pollution Act was enacted in 1990 and amends provisions of
the Clean Water Act as they pertain to prevention and response to oil spills.
Spill prevention control and countermeasure requirements of the Clean Water Act
and some state laws require 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 Fuel Specifications/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 portions of our liquid pipeline
systems, for example, 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.
That service continues, and we also provide transportation and storage of butane
from the Chicago area back to Bushton during the summer 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 United States House of Representatives and the United States Senate
have introduced legislation that would gradually phase out the use of MTBE as a
gasoline blendstock and bar the use of MTBE within four years of enactment. We
cannot provide assurances regarding the likelihood of the passage of such
legislation.

     In California, MTBE-blended gasoline has been replaced by an ethanol blend.
However, ethanol cannot be shipped through pipelines and therefore, we have
realized some reduction in California gasoline volumes transported by our
Pacific operations' pipelines. However, the conversion from MTBE to ethanol in
California has resulted in


                                       44


<PAGE>


an increase in ethanol blending services at many of our refined petroleum
product terminal facilities, and the fees we earn for new ethanol-related
services at our terminals more than offsets the 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 escalating
employee health and benefit costs, environmental issues and rising legal fees.
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 2005. 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 are as follows:

     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. Some shippers on our
pipelines have filed complaints with the Federal Energy Regulatory Commission
and California Public Utilities Commission that seek substantial refunds for
alleged overcharges during the years in question and prospective reductions in
the tariff rates on our Pacific operations' pipeline system.

     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' interstate rates and found most of our
Pacific operations' rates at issue to be unjust and unreasonable. On March 26,
2004, the FERC issued an order on the phase one initial decision that reversed
the initial decision by finding that our Pacific operations' rates for its North
and Oregon Lines should remain "grandfathered" and amended the initial decision
by finding that SFPP's West Line rates (i) to Yuma and Tucson, Arizona and to
our CALNEV Pipeline, as of 1995, and (ii) to Phoenix, Arizona, as of 1997,
should no longer be "grandfathered" and are not just and reasonable. If these
rates are "ungrandfathered," they could be lowered prospectively and complaining
shippers could be entitled to reparations for prior periods.


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<PAGE>


     On September 9, 2004, a non-binding, phase two initial decision was issued
by an administrative law judge hearing the FERC case on the rates charged by our
Pacific operations' interstate portion of its pipelines. If affirmed by the
FERC, the phase two initial decision would establish the basis for prospective
rates and the calculation of reparations for complaining shippers with respect
to our Pacific operations' West Line and East Line. However, as with the phase
one initial decision, the phase two initial decision has no force or effect and
must be fully reviewed by the FERC, which may accept, reject or modify the
decision. A FERC order on phase two of the case is not expected before the third
quarter of 2005. Furthermore, any such order may be subject to further FERC
review, review by the United States Court of Appeals for the District of
Columbia Circuit, or both.

     We estimated, as of December 31, 2003, that shippers' claims for
reparations totaled approximately $154 million and that prospective rate
reductions would have an aggregate average annual impact of approximately $45
million. As the timing for implementation of rate reductions and the payment of
reparations is extended, total estimated reparations and the interest accruing
on the reparations increase. For each calendar quarter of delay in the
implementation of rate reductions sought, we estimate that reparations and
accrued interest accumulates by approximately $9 million. We now assume that any
potential rate reductions will be implemented no earlier than the third quarter
of 2005 and that reparations and accrued interest thereon will be paid no
earlier than the third quarter of 2006; however, the timing, and nature, of any
rate reductions and reparations that may be ordered will likely be affected by
the FERC's income tax allowance inquiry in Docket No. PL05-5 and the FERC's
disposition of issues remanded by the D.C. Circuit in the BP West Coast
decision. If the phase two initial decision were to be largely adopted by the
FERC, the estimated reparations and rate reductions would be larger than noted
above; however, we continue to estimate the combined annual impact of the rate
reductions and the capital costs associated with financing the payment of
reparations sought by shippers and accrued interest thereon to be approximately
15 cents of distributable cash flow per unit. We believe, however, that the
ultimate resolution of these complaints will be for amounts substantially less
than the amounts sought. For more information on our Pacific operations'
regulatory proceedings, see Note 16 to our consolidated financial statements
included elsewhere in this report.

     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.

     Proposed rulemaking by the Federal Energy Regulatory Commission or other
regulatory agencies having jurisdiction could adversely impact our income and
operations. New laws or regulations or different interpretations of existing
laws or regulations applicable to our assets could have a negative impact on our
business, financial condition and results of operations.

     Increased regulatory requirements relating to the integrity of our
pipelines will require us to spend additional money to comply with these
requirements. Through our regulated pipeline subsidiaries, we are subject to
extensive laws and regulations related to pipeline integrity. 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 not 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;


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<PAGE>


     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 have achieved or might achieve separately. Successful
integration of each of their operations will depend upon our ability to manage
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, 2004, we made a significant number of acquisitions that
increased our asset base over 34 times and increased our net income over 69
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 long-term 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
reduced 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 also reduced
the maximum tax rate for an individual to 35% and the maximum tax rate
applicable to net long term capital gains of an individual to 15%. 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, release or spill of liquid petroleum products, chemicals or other products
occurs from our pipelines or at our storage facilities, we may have to pay a
significant amount to clean up the leak, release 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. In
addition, our oil and gas exploration and production activities are subject to
certain federal, state and local laws and regulations relating to environmental
quality and pollution control. These laws and regulations increase the costs of
these activities and may prevent or delay the commencement or continuance of a
given operation. Specifically, we are subject to laws and regulations regarding
the acquisition of permits before drilling, restrictions on drilling activities
in restricted areas, emissions into the environment, water discharges, and
storage and disposition of hazardous wastes. In addition, legislation has been
enacted which requires well and facility sites to be abandoned and reclaimed to
the satisfaction of state authorities. The costs of environmental regulation are
already significant, and additional or more stringent regulation could increase
these costs or could otherwise negatively affect our business.

     Our future success depends in part upon our ability to develop additional
oil and gas reserves that are economically recoverable. The rate of production
from oil and natural gas properties declines as reserves are depleted. Without
successful development activities, the reserves and revenues of our CO2 business
segment will


                                       47


<PAGE>


decline. We may not be able to develop or acquire additional reserves at an
acceptable cost or have necessary financing for these activities in the future.

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

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

     A sharp decline in the price of natural gas or oil prices would result in a
commensurate reduction in our revenues, income and cash flows from the
production of oil and gas and could have a material adverse effect on the
carrying value of our proved reserves. In the event prices fall substantially,
we may not be able to realize a profit from our production and would operate at
a loss. In recent decades, there have been periods of both worldwide
overproduction and underproduction of hydrocarbons and periods of both increased
and relaxed energy conservation efforts. Such conditions have resulted in
periods of excess supply of, and reduced demand for, crude oil on a worldwide
basis and for natural gas on a domestic basis. These periods have been followed
by periods of short supply of, and increased demand for, crude oil and natural
gas. The excess or short supply of crude oil has placed pressures on prices and
has resulted in dramatic price fluctuations even during relatively short periods
of seasonal market demand.

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

     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 or
be required to relocate our pipelines, our business could be affected
negatively.


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<PAGE>


     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.

     Whether we have the power of eminent domain for our pipelines varies from
state to state depending upon the type of pipeline--petroleum liquids, natural
gas or carbon dioxide--and the laws of the particular state. Our inability to
exercise the power of eminent domain could negatively affect our business if we
were to lose the right to use or occupy the property on which our pipelines are
located. For the year ended December 31, 2004, all of our right-of-way related
expenses totaled $16.7 million.

     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.

     In addition, because of widespread state budget deficits, several states
are evaluating ways to subject partnerships to entity-level taxation through the
imposition of state income, franchise or other forms of taxation. If any state
were to impose a tax upon us as an entity, the cash available for distribution
to our unitholders would be reduced.

     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.


                                       49



<PAGE>


     If interest rates increase, our earnings could be adversely affected. As of
December 31, 2004, we had approximately $2.6 billion of debt, excluding market
value of interest rate swaps, subject to variable interest rates. This amount
included $2.2 billion of 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, and other customers may experience severe financial problems in the
future. 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, or may experience in
the future, 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
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, 2004, KMGP Services Company,
Inc. and Kinder Morgan, Inc. had, in the aggregate, approximately 6,072
employees. Approximately 1,206 hourly personnel at certain terminals and
pipelines are represented by labor unions under collective bargaining agreements
that expire between 2005 and 2009. 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 our
consolidated financial statements included elsewhere in this report.


                                       50



<PAGE>


     Substantially all of our pipelines are constructed on rights-of-way granted
by the apparent record owners of such property. In many instances, lands over
which rights-of-way have been obtained are subject to prior liens which have not
been subordinated to the right-of-way grants. In some cases, not all of the
apparent record owners have joined in the right-of-way grants, but in
substantially all such cases, signatures of the owners of majority interests
have been obtained. Permits have been obtained from public authorities to cross
over or under, or to lay facilities in or along, water courses, county roads,
municipal streets and state highways, and in some instances, such permits are
revocable at the election of the grantor, or, the pipeline may be required to
move its facilities at its own expense. Permits have also been obtained from
railroad companies to cross over or under lands or rights-of-way, many of which
are also revocable at the grantor's election. Some such permits require annual
or other periodic payments. In a few minor cases, property for pipeline purposes
was purchased in fee.

     We believe that we have generally satisfactory title to the properties we
own and use in our businesses, subject to liens for current taxes, liens
incident to minor encumbrances, and easements and restrictions which do not
materially detract from the value of such property or the interests in those
properties or the use of such properties in our businesses. We generally do not
own the land on which our pipelines are constructed. Instead, we obtain the
right to construct and operate the pipelines on other people's land for a period
of time. Amounts we have spent during 2004, 2003 and 2002 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.


Item 3.  Legal Proceedings.

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


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

     There were no matters submitted to a vote of our unitholders during the
fourth quarter of 2004.


                                       51


<PAGE>


                                     PART II

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

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

                         Price Range
                       ----------=-----
                                               Cash              i-unit
                        High     Low        Distributions    Distributions
                       ------ ---------     -------------    -------------
        2004
        First Quarter   $49.12  $43.50       $0.6900           0.017412
        Second Quarter   45.39   37.65        0.7100           0.018039
        Third Quarter    46.85   40.60        0.7300           0.017892
        Fourth Quarter   47.70   42.75        0.7400           0.017651

        2003
        First Quarter   $37.23  $33.51       $0.6400           0.018488
        Second Quarter   40.34   35.00        0.6500           0.017138
        Third Quarter    43.06   38.65        0.6600           0.016844
        Fourth Quarter   49.95   42.63        0.6800           0.015885

     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 January 31, 2005, there were approximately 153,000 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--Equity Compensation Plan
Information".

     We did not repurchase any units during the fourth quarter of 2004.


                                       52



<PAGE>



Item 6.  Selected Financial Data

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

<TABLE>
<CAPTION>

                                                              Year Ended December 31,
                                       -------------------------------------------------------------
                                         2004(4)      2003(5)     2002(6)      2001(7)       2000(8)
                                       ----------  -----------  ----------  ------------  ----------
                                                      (In thousands, except per unit data)
<S>                                   <C>           <C>          <C>          <C>          <C>
Income and Cash Flow Data:
Revenues..........................    $ 7,932,861   $6,624,322   $4,237,057   $2,946,676   $  816,442
Cost of product sold..............      5,767,169    4,880,118    2,704,295    1,657,689      124,641
Operating expense.................        581,083      459,936      427,805      396,354      182,445
Fuel and power....................        151,480      108,112       86,413       73,188       43,216
Depreciation, depletion and
 amortization.....................        288,626      219,032      172,041      142,077       82,630

General and administrative........        170,507      150,435      122,205      113,540       67,949
                                      -----------   ----------   ----------   ----------   ----------
Operating income..................        973,996      806,689      724,298     563,828       315,561
Earnings from equity investments..         83,190       92,199       89,258      84,834        71,603
Amortization of excess cost of
 equity investments...............         (5,575)      (5,575)      (5,575)     (9,011)       (8,195)
Interest expense..................       (196,172)    (182,777)    (178,279)   (175,930)      (97,102)
Interest income and other, net....         (4,135)         (33)      (6,042)     (5,005)       10,415
Income tax provision..............        (19,726)     (16,631)     (15,283)    (16,373)      (13,934)
                                      -----------   ----------   ----------   ----------   -----------
Income before cumulative effect of a
 change in accounting principle.          831,578      693,872      608,377     442,343       278,348
Cumulative effect of a change
 in accounting principle..........             --        3,465           --          --            --
                                      -----------   ----------   ----------   ----------   -----------
Net income........................    $   831,578   $  697,337   $  608,377   $ 442,343    $  278,348
General Partner's interest in
 net income.......................        395,092      326,524      270,816     202,095       109,470
Limited Partners' interest in
 net income.......................    $   436,486   $  370,813   $  337,561   $ 240,248    $  168,878

Basic and Diluted Limited Partners'
 Net Income per unit:
Income before cumulative effect
 of a change in accounting
 principle(1).....................    $      2.22   $     1.98   $     1.96   $    1.56    $     1.34
Cumulative effect of a change
 in accounting principle..........             --         0.02           --          --            --
                                      -----------   ----------   ----------   ----------   -----------
Net income........................    $      2.22   $     2.00   $     1.96   $    1.56    $     1.34

Per unit cash distribution
 declared(2)......................    $      2.87   $     2.63   $     2.435  $    2.15    $    1.712
Additions to property, plant
 and equipment....................    $   747,262   $  576,979   $  542,235   $ 295,088    $  125,523

Balance Sheet Data (at end of period):
Net property, plant and equipment.    $ 8,168,680   $7,091,558   $6,244,242   $5,082,612   $3,306,305
Total assets......................    $10,552,942   $9,139,182   $8,353,576   $6,732,666   $4,625,210
Long-term debt(3).................    $ 4,722,410   $4,316,678   $3,659,533   $2,237,015   $1,255,453
Partners' capital.................    $ 3,896,520   $3,510,927   $3,415,929   $3,159,034   $2,117,067

</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)  Represents the amount of cash distributions declared with respect to that
     year. Amounts have been adjusted for the two-for-one split of common units
     that occurred on August 31, 2001.

(3)  Excludes market value of interest rate swaps.

(4)  Includes results of operations for the seven refined petroleum products
     terminals acquired from ExxonMobil, Kinder Morgan Wink Pipeline, L.P., an
     additional 5% interest in the Cochin Pipeline System, Kinder Morgan River
     Terminals LLC & Consolidated Subsidiaries, TransColorado Gas Transmission
     Company, interests in nine refined petroleum products terminals acquired
     from Charter Terminal Company and Charter-Triad Terminals, LLC, and the
     Kinder Morgan Fairless


                                       53


<PAGE>


     Hills terminal since effective dates of acquisition. We acquired the seven
     refined petroleum products terminals from ExxonMobil effective March 9,
     2004. We acquired Kinder Morgan Wink Pipeline, L.P. effective August 31,
     2004. The additional interest in Cochin was acquired effective October 1,
     2004. We acquired Kinder Morgan River Terminals LLC & Consolidated
     Subsidiaries effective October 6, 2004. We acquired TransColorado effective
     November 1, 2004, the interests in the nine Charter Terminal Company and
     Charter-Triad Terminals, LLC refined petroleum products terminals effective
     November 5, 2004, and the Kinder Morgan Fairless Hills terminal effective
     December 1, 2004.

(5)  Includes results of operations for the bulk terminal operations acquired
     from M.J. Rudolph Corporation, the additional 12.75% interest in the SACROC
     unit, the five refined petroleum products terminals acquired from Shell,
     the additional 42.5% interest in the Yates field unit, the crude oil
     gathering operations surrounding the Yates field unit, an additional 65%
     interest in the Pecos Carbon Dioxide Company, the remaining approximate 32%
     interest in MidTex Gas Storage Company, LLP, the seven refined petroleum
     products terminals acquired from ConocoPhillips and two bulk terminal
     facilities located in Tampa, Florida since dates of acquisition. We
     acquired certain bulk terminal operations from M.J. Rudolph effective
     January 1, 2003. The additional 12.75% interest in SACROC was acquired
     effective June 1, 2003. The five refined petroleum products terminals were
     acquired effective October 1, 2003. The additional 42.5% interest in the
     Yates field unit, the Yates gathering system and the additional 65%
     interest in Pecos Carbon Dioxide Company were acquired effective November
     1, 2003. The additional 32% ownership interest in MidTex was acquired
     November 1, 2003. The seven refined petroleum products terminals were
     acquired December 11, 2003, and the two bulk terminal facilities located in
     Tampa, Florida were acquired effective December 10 and 23, 2003.

(6)  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
     effective December 31, 2001. Kinder Morgan Materials Services LLC was
     acquired effective January 1, 2002. We acquired a 33 1/3% interest in
     International Marine Terminals effective January 1, 2002 and an additional
     33 1/3% interest effective February 1, 2002. Tejas Gas, LLC was acquired
     effective January 31, 2002. The Milwaukee Bagging Operations were acquired
     effective May 1, 2002. The remaining interest in Trailblazer was acquired
     effective May 6, 2002. The Owensboro Gateway Terminal and IC Terminal
     Holdings Company and Subsidiaries were acquired effective September 1,
     2002.

(7)  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 effective 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
     effective June 20, 2001. Vopak terminal LLCs were acquired July 10, 2001.
     Boswell terminals were acquired August 31, 2001. Stolt-Nielsen terminals
     were acquired effective November 8 and 29, 2001, and our additional
     interests in the Snyder Gasoline Plant and the Diamond M Gas Plant were
     acquired effective November 14, 2001.

(8)  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 effective December 31, 1999. Milwaukee
     Bulk Terminals, Inc. and Dakota Bulk Terminal, Inc. were acquired effective
     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 effective October 25, 2000. Our 32.5% interest in Cochin was
     acquired effective November 3, 2000, and Delta Terminal Services LLC was
     acquired effective December 1, 2000.


                                       54



<PAGE>

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

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

  Additional sections in this report which should be helpful to your reading of
our discussion and analysis 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 developments during 2004, found in Items 1 and 2 "Business
    and Properties-Recent Developments"; and

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

   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 are of more significance in our financial statement
preparation process than others, which policies are discussed following.

  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.

  We routinely conduct reviews of potential environmental issues and claims that
could impact our assets or operations. In December 2004, we recognized a $0.2
million increase in environmental expenses and an associated $0.1 million
increase in deferred income tax expense resulting from changes to previous
estimates. The adjustment included an $18.9 million increase in our estimated
environmental receivables and reimbursables and a $19.1 million increase in our
overall accrued environmental and related claim liabilities. We included the
additional $0.2 million environmental expense within "Other, net" in our
accompanying consolidated statement of income for 2004. The $0.3 million expense
item, including taxes, is the net impact of a $30.6 increase in expense in our
Products Pipelines business segment, a $7.6

                                       55
<PAGE>


million decrease in expense in our Natural Gas Pipelines segment, a $4.1 million
decrease in expense in our CO2 segment, and an $18.6 million decrease in expense
in our Terminals business segment.

  In December 2002, 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 our accompanying consolidated statement of income
for 2002. The $0.3 million reduction in environmental expense resulted from a
$15.7 million increase in expense in our Products Pipelines business segment and
a $16.0 million decrease in expense in our Terminals business segment. For more
information on our environmental disclosures, see Note 16 to our consolidated
financial statements included elsewhere in this report.

  Legal Matters

   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 our
estimates, or additional facts and circumstances cause us to revise our
estimates, our earnings will be affected. We expense legal costs as incurred and
all recorded legal liabilities are 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 estimated, as of December 31, 2003, that shippers' claims for reparations
totaled approximately $154 million and that prospective rate reductions would
have an aggregate average annual impact of approximately $45 million. As the
timing for implementation of rate reductions and the payment of reparations is
extended, total estimated reparations and the interest accruing on the
reparations increase. For each calendar quarter of delay in the implementation
of rate reductions sought, we estimate that reparations and accrued interest
accumulates by approximately $9 million. We now assume that any potential rate
reductions will be implemented no earlier than the third quarter of 2005 and
that reparations and accrued interest thereon will be paid no earlier than the
third quarter of 2006; however, the timing, and nature, of any rate reductions
and reparations that may be ordered will likely be affected by the FERC's income
tax allowance inquiry in Docket No. PL05-5 and the FERC's disposition of issues
remanded by the D.C. Circuit in the BP West Coast decision. If the phase two
initial decision were to be largely adopted by the FERC, the estimated
reparations and rate reductions would be larger than noted above; however, we
continue to estimate the combined annual impact of the rate reductions and the
capital costs associated with financing the payment of reparations sought by
shippers and accrued interest thereon to be approximately 15 cents of
distributable cash flow per unit. We believe, however, that the ultimate
resolution of these complaints will be for amounts substantially less than the
amounts sought. For more information on our Pacific operations' regulatory
proceedings, see Note 16 to our consolidated financial statements included
elsewhere in this report.

  Intangible Assets

  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. These 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

                                       56
<PAGE>


must be tested for impairment annually or on an interim basis if events or
circumstances indicate that the fair value of the asset has decreased below its
carrying value. We 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, 2005. As
of January 1, 2005, our goodwill was $732.8 million.

Estimated Net Recoverable Quantities of Oil and Gas

  We use the successful efforts method of accounting for our oil and gas
producing activities. The successful efforts method inherently relies on the
estimation of proved reserves, both developed and undeveloped. The existence and
the estimated amount of proved reserves affect, among other things, whether
certain costs are capitalized or expensed, the amount and timing of costs
depleted or amortized into income and the presentation of supplemental
information on oil and gas producing activities. The expected future cash flows
to be generated by oil and gas producing properties used in testing for
impairment of such properties also rely in part on estimates of net recoverable
quantities of oil and gas.

  Our estimation of net recoverable quantities of oil and gas is a highly
technical process performed primarily by in-house reservoir engineers and
geoscience professionals. Independent oil and gas consultants have reviewed the
estimates of proved reserves of crude oil, natural gas and natural gas liquids
that we have attributed to our net interest in oil and gas properties as of
December 31, 2004.

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

Results of Operations
<TABLE>
<CAPTION>
                                                               Year Ended December 31,
                                                      ------------------------------------
                                                         2004         2003          2002
                                                      ----------   ----------   ----------
                                                                   (In  thousands)
<S>                                                   <C>          <C>          <C>
Earnings before depreciation, depletion and
 amortization expense and amortization of excess
 cost of equity investments
  Products Pipelines................................  $   444,865  $   441,600  $   411,604
  Natural Gas Pipelines.............................      418,261      373,350      325,454
  CO2...............................................      357,636      203,599      132,196
  Terminals.........................................      281,738      240,776      224,963
                                                      -----------  -----------  -----------
    Segment earnings before depreciation, depletion
     and amortization of excess cost of equity
     investments(a)................................     1,502,500    1,259,325    1,094,217

  Depreciation, depletion and amortization expense..     (288,626)    (219,032)    (172,041)
  Amortization of excess cost of investments........       (5,575)      (5,575)      (5,575)
  Interest and corporate administrative expenses(b).     (376,721)    (337,381)    (308,224)
                                                      -----------  -----------  -----------
    Net income......................................  $   831,578  $   697,337  $   608,377
                                                      ===========  ===========  ===========
</TABLE>

----------

(a)  Includes revenues, earnings from equity investments, income taxes,
     allocable interest income and other, net, less operating expenses. 2004
     amounts include environmental expense adjustments resulting in a
     $30,611expense to our Products Pipelines business segment, a $7,602
     reduction in expense to our Natural Gas Pipelines business segment, a
     $4,126 reduction in expense to our CO2 business segment and an $18,571
     reduction in expense to our Terminals business segment. 2002 amounts
     include environmental expense adjustments resulting in a $15,700 expense to
     our Products Pipelines business segment and a $16,000 reduction in expense
     to our Terminals business segment.
(b)  Includes unallocated interest income, interest and debt expense, general
     and administrative expenses, minority interest expense, loss from early
     extinguishment of debt (2004 only) and cumulative effect adjustment from a
     change in accounting principle (2003 only).

   In 2004, we earned net income of $831.6 million ($2.22 per diluted unit) on
revenues of $7,932.9 million, compared to net income of $697.3 million ($2.00
per diluted unit) on revenues of $6,624.3 million in 2003, and net income of
$608.4 million ($1.96 per diluted unit) on revenues of $4,237.1 million in 2002.
We benefited from a growing demand for energy products, overall higher energy
prices and our management's continued commitment to its business strategy,
designed to increase financial performance through a combination of internal
asset expansions and external acquisitions.

   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.

   Because our partnership agreement requires us to distribute 100% of our
available cash to our partners on a quarterly basis (available cash consists
primarily of all our cash receipts, less cash disbursements and changes in
reserves), we consider each period's earnings before all non-cash depreciation,
depletion and amortization expenses, including amortization of excess cost of
equity investments, to be an important measure of our success in maximizing
returns to our partners. In each of the years 2004 and 2003, all four of our
reportable business segments reported year-over-year increases in earnings
before depreciation, depletion and amortization, with the strongest growth
coming from our CO2 (carbon dioxide) and Natural Gas Pipelines business
segments.

   The year-over-year increases in our segment earnings before depreciation,
depletion and amortization in 2004 and 2003 were attributable both to internal
growth and to contributions from acquired assets; more specifically:

                                       57
<PAGE>


  o higher earnings from our CO2 segment, where we benifited from higher oil and
    gas prices, acquisitions of additional oil reserve interests and related
    assets, and internal capital spending that both increased and expanded asset
    infrastructure in order to accommodate growing customer demand within the
    Permian Basin area of West Texas;

  o higher earnings from our Natural Gas Pipelines segment, largely due to
    improved margins on natural gas sales activities, higher natural gas
    operational sales, and the further optimization of the large natural gas
    sourcing and transportation operations we conduct within the State of Texas;

  o higher earnings from our Products Pipelines segment, mainly due to higher
    revenues from refined product terminal operations, higher deliveries of
    refined petroleum products and natural gas liquids resulting from increased
    military and industrial demand, and the acquisition of our Southeast
    terminal operations, which consist of 23 refined petroleum products
    terminals that were acquired since December 2003; and

  o higher earnings from our Terminals segment, primarily due to higher revenues
    earned by transporting and storing petroleum and petrochemical-related
    liquids, transloading higher volumes of dry-bulk material products,
    completed expansion projects at existing liquids and bulk terminal
    facilities, and the terminal acquisitions we have made since the end of
    2002.

   We declared a record cash distribution of $0.74 per unit for the fourth
quarter of 2004 (an annualized rate of $2.96). This distribution was 9% higher
than the $0.68 per unit distribution we made for the fourth quarter of 2003, and
18% higher than the $0.625 per unit distribution we made for the fourth quarter
of 2002. We expect to declare cash distributions of at least $3.13 per unit for
2005; however, no assurance can be given that we will be able to achieve this
level of distribution. 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.

  Products Pipelines
<TABLE>
<CAPTION>
                                                                                  Year Ended December 31,
                                                               ---------------------------------------------
                                                                    2004            2003             2002
                                                               -------------    -------------   ------------
                                                                 (In thousands, except operating statistics)
<S>                                                             <C>             <C>             <C>
  Revenues..................................................    $    645,249    $    585,376    $    576,542
  Operating expenses(a).....................................        (191,425)       (169,526)       (169,782)
  Earnings from equity investments..........................          29,050          30,948          28,998
  Interest income and Other, net- income (expense)(b).......         (25,934)          6,471         (14,000)
  Income taxes..............................................    $    (12,075)        (11,669)        (10,154)
                                                                ------------    -------------   ------------
    Earnings before depreciation, depletion and amortization
     expense and amortization of excess cost of equity               444,865         441,600         411,604
investments.................................................

  Depreciation, depletion and amortization expense..........         (71,263)        (67,345)        (64,388)
  Amortization of excess cost of equity investments.........          (3,281)         (3,281)         (3,281)
                                                                ------------    -------------   ------------
    Segment earnings........................................    $    370,321    $    370,974    $    343,935
                                                                ============    ============    ============

  Gasoline (MMBbl)..........................................           459.1           451.0           465.2
  Diesel fuel (MMBbl).......................................           161.7           161.4           152.7
  Jet fuel (MMBbl)..........................................           117.8           111.3           115.1
                                                                ------------    ------------    ------------
    Total refined product volumes (MMBbl)...................           738.6           723.7           733.0
  Natural gas liquids (MMBbl)...............................            43.9            42.2            44.4
                                                                ------------    ------------    ------------
    Total delivery volumes (MMBbl)(c).......................           782.5           765.9           777.4
                                                                ============    ============    ============
</TABLE>

----------

(a) Includes costs of sales, operations and maintenance expenses, fuel and power
   expenses and taxes, other than income taxes.
(b) Includes expense of $30,611 and $15,700 in 2004 and 2002, respectively,
   associated with environmental expense adjustments.
(c) Includes Pacific, Plantation, North System, CALNEV, Central Florida, Cypress
   and Heartland pipeline volumes.


                                       58
<PAGE>


   Our Products Pipelines segment's primary businesses include transporting
refined petroleum products and natural gas liquids through pipelines and
operating high-quality liquid petroleum products terminals and transmix
processing facilities. The segment reported earnings before depreciation,
depletion and amortization of $444.9 million on revenues of $645.2 million in
2004. This compared to earnings before depreciation, depletion and amortization
of $441.6 million on revenues of $585.4 million in 2003 and earnings before
depreciation, depletion and amortization of $411.6 million on revenues of $576.5
million in 2002.

   As noted in the table above, the segment's 2004 and 2002 earnings included
charges of $30.6 million and $15.7 million, respectively, from the adjustment
of our environmental liabilities referred to in "Critical Accounting Policies
and Estimates--Environmental Matters." Excluding these environmental charges,
segment earnings before depreciation, depletion and amortization totaled $475.5
million in 2004 and $427.3 million in 2002.

   The $33.9 million (8%) increase in earnings before depreciation, depletion
and amortization in 2004 compared to 2003 (excluding the 2004 environmental
charge) was driven primarily by higher earnings from our Southeast terminals,
our Pacific operations, earnings from our proportionate ownership interest in
the Cochin pipeline system, and to a lesser extent by higher earnings from our
West Coast terminal operations, our Central Florida and Cypress pipelines, and
our transmix operations.

   Our Southeast terminals, which include the operations of 23 refined products
terminals located in the southeastern United States that we acquired in December
2003, March 2004, and November 2004, reported earnings before depreciation,
depletion and amortization of $14.0 million in 2004. Our Pacific operations
reported a $9.5 million (4%) increase in earnings before depreciation, depletion
and amortization in 2004, compared to the prior year. The increase was primarily
due to incremental fees earned from ethanol-related services, higher refined
product delivery revenues, and incremental revenues related to the refined
products terminal operations we acquired from Shell Oil Products in October
2003.

    Effective October 1, 2004, we acquired an additional undivided 5% interest
in the Cochin pipeline system for approximately $10.9 million and we now own
approximately 49.8% of Cochin, an approximate 1,900-mile pipeline that
transports natural gas liquids to the Midwestern United States and eastern
Canada petrochemical and fuel markets. Cochin's earnings before depreciation,
depletion and amortization increased $8.9 million (64%) in 2004 compared to
2003. The increase was primarily driven by higher revenues from pipeline
throughput deliveries as well as our additional ownership interest. Earnings
before depreciation, depletion and amortization from our West Coast terminals
increased $2.8 million (7%) in 2004 compared to 2003. The increase was largely
attributable to higher fees from ethanol blending services, primarily driven by
revenue increases across all service activities performed at our Carson,
California and our connected Los Angeles Harbor product terminals.

  The increases in segment earnings before depreciation, depletion and
amortization in 2004 compared to 2003 were partly offset by lower earnings from
our CALNEV Pipeline and North System natural gas liquids pipeline. CALNEV and
the North System reported decreases of $2.4 million (5%) and $2.1 million (8%),
respectively, in earnings before depreciation, depletion and amortization in
2004 versus 2003. For CALNEV, the decrease was driven by higher 2004 fuel and
power expenses, higher operating expenses, and lower miscellaneous revenues. For
our North System, the decrease was primarily due to higher 2004 leased storage
expenses, due to higher fees, and lower transport revenues, related to a 6%
decrease in 2004 throughput delivery volumes. The decline in North System
delivery volumes was primarily due to a lack of propane supplies in February
through April of 2004, caused by shippers reducing line-fill and storage volume
to lower levels than last year. In April 2004, we filed a plan with the Federal
Energy Regulatory Commission to provide a line-fill service, which we expect
will mitigate the supply problems we experienced on our North System in the
first half of 2004. Pursuant to this plan, we purchased $23.0 million of
line-fill during 2004.

   The $14.3 million (3%) increase in segment earnings before depreciation,
depletion and amortization in 2003 compared to 2002 (excluding the 2002
environmental charge) resulted from higher earnings from our Pacific operations,
North System, CALNEV Pipeline, transmix operations, Central Florida Pipeline,
our approximate 51% ownership interest in Plantation Pipe Line Company and our
West Coast terminal operations. 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 from higher product delivery revenues
related to overall strong demand for diesel fuel. The overall increase was
partially offset by lower earnings before depreciation, depletion and

                                       59
<PAGE>


amortization from both our proportionate interest in the Cochin pipeline system
and our Cypress Pipeline, mainly due to lower operating revenues. In addition,
due to the continued 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. Since the end of 2002, 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.

  The $59.8 million (10%) increase in segment revenues in 2004 compared to 2003
was driven by $23.2 million of incremental revenues attributable to the
acquisition of our Southeast terminals. In addition, revenues from our Pacific
operations increased $16.6 million (5%) and revenues from our proportionate
share of Cochin increased $13.1 million (53%). Our Pacific operations'
year-over-year increase was due to both the higher terminal revenues, discussed
above, and higher transport revenues, due largely to an almost 2% increase in
mainline delivery volumes. Cochin's increase in revenues was mainly due to a 30%
increase in delivery volumes and to higher average tariff rates. The increase in
delivery volumes in 2004 versus 2003 was partly related to lower product
inventory levels in western Canada in the first half of 2003, caused by a drop
in propane production. The drop in propane production was a reaction to lower
profit margins from the extraction and sale of natural gas liquids caused by a
rise in natural gas prices since the end of 2002. Revenues from our Central
Florida Pipeline increased $2.7 million (8%) in 2004 compared to 2003. The
increase was due to an almost 8% increase in product delivery volumes. Combined,
the segment benefited from a 2% increase in the volume of refined products
delivered during 2004 compared to 2003.

   Combining all of the segment's operations, total throughput delivery of
refined petroleum products, consisting of gasoline, diesel fuel and jet fuel,
increased 2% in 2004 compared to 2003. Jet fuel delivery volumes, boosted by
strong military and solid commercial demand, were up nearly 6% in 2004 compared
to 2003, and gasoline delivery volumes increased 2%. Deliveries of diesel fuel
were essentially flat across both 2004 and 2003, but both gasoline and diesel
volumes were impacted in the fourth quarter of 2004 by the shut-down of a
refinery connected to the Plantation Pipeline following Hurricane Ivan.

   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 transported, due
mostly to an increase in transportation of longer-haul, higher margin barrels.
Revenues from our combined 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 2002 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 addition to the impact of lower propane production
described above, Cochin's 2003 earnings and revenues were negatively impacted by
a pipeline rupture and fire in July 2003 that 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.

   For the segment as a whole, total throughput delivery of refined petroleum
products decreased 1% in 2003 compared to 2002. The decrease resulted from 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 2%
in 2003 versus 2002, mainly due to a 6% increase in diesel delivery volumes and
to improvement in jet fuel delivery volumes in the fourth quarter of 2003.

                                       60
<PAGE>

   The segment's operating expenses increased $21.9 million (13%) in 2004
compared to 2003. The increase was mainly due to incremental expenses of $9.3
million from our Southeast terminals and to a $3.8 million (5%) increase in
expenses from our Pacific operations, largely the result of higher 2004 fuel and
power expenses associated with higher utility rates and higher delivery volumes.
The segment also reported $1.6 million year-over-year increases in expenses in
2004 from each of the Cochin Pipeline, North System, CALNEV Pipeline and
Plantation Pipeline. Cochin's increase was related to higher expenses associated
with the increased delivery volumes and our additional ownership interest. The
North System's increase was primarily due to higher natural gas liquids storage
expenses. CALNEV's increase was mostly due to higher fuel and power expenses due
to favorable credit adjustments to electricity access and surcharge reserves
taken in the first nine months of 2003. Plantation's increase was primarily
related to higher 2004 labor, testing and maintenance expenses. The segment's
operating expenses remained relatively flat in 2003, compared to 2002.

  Earnings from our Products Pipelines' equity investments were $29.1 million in
2004, $30.9 million in 2003 and $29.0 million in 2002. 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.

   The $1.8 million (6%) decrease in equity earnings in 2004 compared to 2003
was mainly due to a $2.4 million (8%) decrease in equity earnings from
Plantation, mainly due to a $3.2 million expense recorded in the first quarter
of 2004 for our share of an environmental litigation settlement reached between
Plantation and various plaintiffs. In 2005, we expect to recover the cost of the
settlement under various insurance policies. 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.

   Excluding the 2004 and 2002 environmental charges, interest and other income
items decreased $1.8 million in 2004 versus 2003, and increased $4.8 million in
2003 versus 2002. Both changes were largely due to higher gains realized from
sales of property, plant and equipment by our Pacific operations during 2003.

   Non-cash depreciation, depletion and amortization charges, including
amortization of excess cost of investments, were $74.5 million, $70.6 million
and $67.7 million in each of the years ended December 31, 2004, 2003 and 2002,
respectively. The $3.9 million (6%) increase in 2004 versus 2003 was primarily
due to incremental depreciation charges from our Southeast terminals and to
higher depreciation expenses from our Pacific operations. 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. Excluding the incremental depreciation expenses related to the
acquisition of our Southeast terminals, the year-over-year increases in
depreciation expenses in both 2004 and 2003 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.

  For 2005, we currently expect that our Products Pipelines segment will report
earnings before depreciation, depletion and amortization expense of
approximately $535 million, a 13% increase over 2004 (excluding the 2004
environmental charge). The earnings increase is expected to be driven by
continued improvement in gasoline and jet fuel delivery volumes, planned capital
improvements and expansions (including our Pacific operations' North Line
expansion completed in December 2004), and a full year of operations from
products terminals acquired in March and November 2004.




                                       61
<PAGE>


  Natural Gas Pipelines
<TABLE>
<CAPTION>
                                                                       Year Ended December 31,
                                                                   2004         2003           2002
                                                               -----------   -----------   -----------
                                                             (In thousands, except operating statistics)
<S>                                                            <C>           <C>           <C>
  Revenues..................................................   $ 6,252,921   $ 5,316,853   $ 3,086,187
  Operating expenses(a).....................................    (5,862,159)   (4,967,531)   (2,784,278)
  Earnings from equity investments..........................        19,960        24,012        23,887
  Other, net - income(b)....................................         9,434         1,082            36
  Income taxes..............................................        (1,895)       (1,066)         (378)
                                                               -----------   -----------   -----------
    Earnings before depreciation, depletion and amortization
     expense and amortization of excess cost of equity
     investments............................................       418,261       373,350       325,454

  Depreciation, depletion and amortization expense..........       (53,112)      (53,785)      (48,411)
  Amortization of excess cost of equity investments.........          (277)         (277)         (277)
                                                               -----------   -----------   -----------
    Segment earnings........................................   $   364,872   $   319,288   $   276,766
                                                               ===========   ===========   ===========

  Natural gas transport volumes (Trillion Btus)(c)..........       1,353.0       1,364.1       1,261.1
                                                               ===========   ===========   ===========
  Natural gas sales volumes (Trillion Btus)(d)..............         992.4         906.0         882.8
                                                               ===========   ===========   ===========
</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 income of $7,602 in 2004 associated with environmental expense
    adjustments.
(c) Includes Kinder Morgan Interstate Gas Transmission, Texas intrastate natural
    gas pipeline group, Trailblazer and TransColorado pipeline volumes.
    TransColorado annual volumes are included for all three years (acquisition
    date November 1, 2004).
(d) Represents Texas intrastate natural gas pipeline group. Kinder Morgan Tejas
    sales volumes are included for all three years (acquisition date January 31,
    2002).

   Our Natural Gas Pipelines segment's primary businesses involve marketing,
transporting and storing natural gas through both intrastate and interstate
pipeline systems. In 2004, the segment reported earnings before depreciation,
depletion and amortization of $418.3 million on revenues of $6,252.9 million.
This compared to earnings before depreciation, depletion and amortization of
$373.4 million on revenues of $5,316.9 million in 2003 and earnings before
depreciation, depletion and amortization of $325.5 million on revenues of
$3,086.2 million in 2002.

   As noted in the table above, the segment's 2004 earnings include a $7.6
million increase from the adjustment of our environmental liabilities referred
to in "Critical Accounting Policies and Estimates--Environmental Matters."
Excluding this environmental adjustment, segment earnings before depreciation,
depletion and amortization increased $37.3 million (10%) in 2004 compared to
2003. This increase, along with the $47.9 million (15%) increase in earnings
before depreciation, depletion and amortization in 2003 versus 2002, was
primarily attributable to higher earnings from our Texas intrastate natural gas
pipeline group, which includes the operations of the following four natural gas
pipeline systems: Kinder Morgan Tejas, Kinder Morgan Texas Pipeline, North Texas
Pipeline and Mier-Monterrey Mexico Pipeline.

   The year-over-year increases in earnings before depreciation, depletion and
amortization from our Texas intrastate natural gas pipeline group were mainly
due to improved margins and higher volumes from natural gas sales activities,
strong returns from capital investments made since the end of 2002, and
incremental earnings from value added services, including storage, blending and
other services. Since our acquisition of Kinder Morgan Tejas on January 31,
2002, we have increased the interconnection capability between its system and
Kinder Morgan Texas Pipeline, improved system processes and controls and further
refined the management of risk associated with the sale and transmission of
natural gas. 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 the State of Texas; Kinder Morgan Texas Pipeline's operations include
approximately 2,500 miles of pipelines, supply and gathering lines, laterals and
related facilities principally located in the Texas Gulf Coast area. These two
systems comprise the major components of our Texas intrastate group and together
reported a $41.1 million (24%) increase in earnings before depreciation,
depletion and amortization in 2004 compared to 2003. In 2003, the two systems
combined reported a $30.7 million (22%) increase in earnings before
depreciation, depletion and amortization compared to 2002.

                                       62
<PAGE>


   Furthermore, we have continued to grow internally and have developed and
built new natural gas pipeline systems to transport gas from expanding
production areas and to serve new market areas. Contributions from the two
remaining Texas intrastate systems, our North Texas Pipeline, completed in
August 2002, and our Mier-Monterrey Pipeline, completed in March 2003, accounted
for $3.5 million (9%) of the segment's total increase in earnings before
depreciation, depletion and amortization in 2004 compared to 2003, and $14.9
million (31%) of the segment's total increase in earnings before depreciation,
depletion and amortization in 2003 compared to 2002. The increases were driven
by higher transportation revenues linked to growing demand for natural gas in
both Texas and the Monterrey, Mexico region.

   Our Rocky Mountain interstate natural gas pipeline operations consist of the
following three natural gas pipeline systems: Kinder Morgan Interstate Gas
Transmission, Trailblazer Pipeline and TransColorado Pipeline. We acquired
TransColorado Gas Transmission Company from KMI effective November 1, 2004. The
TransColorado system includes a 300-mile interstate natural gas pipeline that
originates in the Piceance Basin of western Colorado and runs to the Blanco Hub
in northwest New Mexico. All three pipelines charge a transportation fee for gas
transmission service and have the authority to initiate natural gas sales
primarily for operational purposes, but none engage in significant gas purchases
for resale. Operational natural gas sales are primarily made possible by
collection of fuel in kind pursuant to each pipeline's natural gas
transportation tariff.

  Together, our Rocky Mountain pipelines reported a $3.8 million (3%) decrease
in earnings before depreciation, depletion and amortization in 2004 compared to
2003. The decrease was due to lower earnings from our Trailblazer Pipeline,
mainly due to lower revenues as a result of timing on imbalance cashouts and
lower transportation revenues. The decreases in transportation revenues were due
to lower tariff rates that became effective January 1, 2004, pursuant to a rate
case settlement. In 2003, KMIGT and Trailblazer accounted for $4.6 million (10%)
of the segment's total increase in earnings before depreciation, depletion and
amortization compared to 2002. The increase in 2003 over 2002 was mainly due to
the benefits resulting from an expansion of our Trailblazer Pipeline system. 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 provided new firm long-term transportation
service. As a result, Trailblazer realized a 12% increase in natural gas
transportation volumes in 2003 compared to 2002.

  In each of the years 2004 and 2003, the segment reported significant increases
in both revenues and operating expenses when compared to the year-earlier
period. Revenues earned by our Natural Gas Pipelines segment increased $936.0
million (18%) in 2004 versus 2003, and $2,230.7 million (72%) in 2003 versus
2002. Operating expenses, including natural gas purchase costs, increased $894.6
million (18%) in 2004 compared to 2003, and $2,183.3 million (78%) in 2003
compared to 2002.

  The year-over-year increases in revenues and operating expenses were primarily
attributable to the internal growth and integration of our Kinder Morgan Tejas
and Kinder Morgan Texas Pipeline systems since the end of 2002. Both pipeline
systems buy and sell significant volumes of natural gas, which is also
transported on their pipelines, and our objective is to match purchases and
sales, thus locking-in the equivalent of a transportation fee. We manage
remaining price risk by the use of energy financial instruments. Combined, the
two systems reported increases in natural gas sales revenues of $912.2 million
(19%) in 2004 compared to 2003, and $2,117.6 million (78%) in 2003 compared to
2002. Both increases were due to higher average sale prices and higher sales
volumes; the increase in 2004 compared to 2003 resulted from an almost 9%
increase in average gas prices (from $5.32 per dekatherm in 2003 to $5.78 per
dekatherm in 2004) and an almost 10% increase in gas sales volumes. Revenues
from our recently acquired TransColorado Pipeline totaled $6.7 million in 2004.

   Kinder Morgan Tejas and Kinder Morgan Texas Pipeline together reported
combined increases in costs of sales of $870.7 million (18%) in 2004 compared to
2003, and $2,123.3 million (80%) in 2003 compared to 2002. Both increases were
due to higher average costs of natural gas sold and higher volumes of gas
purchased for sale; the increase in 2004 compared to 2003 resulted from an 8%
increase in the average price of purchased gas (from $5.22 per dekatherm in 2003
to $5.66 per dekatherm in 2004) and a 9% increase in gas purchase volumes. Due
to the offsetting nature of gas sales and cost of gas sold, we believe that
earnings before depreciation, depletion and amortization or a similar measure of
margin, defined as revenues less cost of gas sold, is a better comparative
performance indicator than revenues because the mix of utility volumes between
sales and transportation service affects revenues but not margin.

                                       63
<PAGE>


   We account for the 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. In 2004, equity earnings from these three investees
decreased $4.1 million (17%) compared to 2003. The decrease was chiefly due to
lower earnings from our 49% investment in Red Cedar, mainly due to higher
operational sales of natural gas by Red Cedar in 2003. Earnings from equity
investments were relatively flat across 2003 and 2002; higher earnings in 2003
from our 25% investment in Thunder Creek were largely offset by lower earnings
from our investment in Red Cedar.

   The segment's non-cash depreciation, depletion and amortization charges,
including amortization of excess cost of investments decreased a slight $0.7
million (1%) in 2004 compared to 2003, primarily due to lower year-to-year
depreciation expense on our Trailblazer Pipeline. The decrease was due to the
rate case settlement which became effective January 1, 2004. The $5.4 million
(11%) increase in depreciation, depletion and amortization charges in 2003 over
2002 was primarily due to incremental depreciation charges related to the
completed North Texas and Mier-Monterrey pipeline systems.

  For 2005, we currently expect that our Natural Gas Pipelines segment will
report earnings before depreciation, depletion and amortization expense of
approximately $439 million, a 7% increase over 2004 (excluding the 2004
environmental expense adjustment). The earnings increase is expected to be
driven by additional earnings realized from the sale of natural gas at higher
margins, increases in storage and transportation services, the benefits of
reaching new markets and customers by planned capital spending, and a full year
of operations from our TransColorado Pipeline.

  CO2
<TABLE>
<CAPTION>

                                                         Year Ended December 31,
                                                      2004         2003         2002
                                                   ---------    --------    --------
                                              (In thousands, except operating statistics)
<S>                                                <C>          <C>         <C>
  Revenues.......................................  $ 492,834    $248,535    $146,280
  Operating expenses(a)..........................   (173,382)    (82,055)    (50,524)
  Earnings from equity investments...............     34,179      37,198      36,328
  Other, net - income (expense)(b)...............      4,152         (40)        112
  Income taxes...................................       (147)        (39)          -
                                                   ---------    --------    --------
    Earnings before depreciation, depletion and
     amortization expense and amortization of
     excess cost of equity investments...........    357,636     203,599     132,196

  Depreciation, depletion and amortization
   expense(c)....................................   (121,361)    (60,827)    (29,196)
  Amortization of excess cost of equity
   investments...................................     (2,017)     (2,017)     (2,017)
                                                   ---------    --------    --------
    Segment earnings.............................  $ 234,258    $140,755    $100,983
                                                   =========    ========    ========

Carbon dioxide delivery volumes (Bcf)(d).........      640.8       504.7       431.7
                                                   =========    ========    ========
SACROC oil production (MBbl/d)(e)................       28.3        20.2        13.0
                                                   =========    ========    ========
Yates oil production (MBbl/d)(e).................       19.5        18.9        18.3
                                                   =========    ========    ========
Natural gas liquids sales volumes (MBbl/d)(f)....        7.7         3.7         2.1
                                                   =========    ========    ========
Realized weighted average oil price per Bbl(g)(h)  $   25.72    $  23.73    $  22.45
                                                   =========    ========    ========
Realized weighted average natural gas liquids
price per Bbl(h)(i)..............................  $   31.33    $  21.77    $  24.60
                                                   =========    ========    ========
</TABLE>
----------

(a) Includes costs of sales, operations and maintenance expenses, fuel and power
    expenses and taxes, other than income taxes.
(b) Includes income of $4,126 in 2004 associated with environmental reserve
    adjustments.
(c) Includes expenses associated with oil and gas production activities and gas
    processing activities in the amount of $105,890 for 2004, $49,039 for 2003,
    and $19,337 for 2002. Includes expenses associated with sales and
    transportation services activities in the amount of $15,471 for 2004,
    $11,788 for 2003, and $9,859 for 2002.
(d) Includes Cortez, Central Basin, Canyon Reef Carriers, Centerline and Pecos
    pipeline volumes.
(e) Represents 100% of the production from the field.
(f) Net to Kinder Morgan.
(g) Includes all Kinder Morgan crude oil production properties.
(h) Hedge gains/losses for oil and natural gas liquids are included with
    crude oil.
(i) Includes production attributable to leasehold ownership and production
    attributable to our ownership in processing plants and third party
    processing agreements.

                                       64
<PAGE>


   Our CO2 segment consists of Kinder Morgan CO2 Company, L.P. and its
consolidated affiliates. The segment's primary businesses involve the
production, transportation and marketing of carbon dioxide, commonly called CO2,
and the production and marketing of crude oil and natural gas. In 2004, our CO2
segment reported earnings before depreciation, depletion and amortization of
$357.6 million on revenues of $492.8 million. This compared to earnings before
depreciation, depletion and amortization of $203.6 million on revenues of $248.5
million in 2003 and earnings before depreciation, depletion and amortization of
$132.2 million on revenues of $146.3 million in 2002.

   As noted in the table above, the segment's 2004 earnings include a $4.1
million increase from the adjustment of our environmental liabilities referred
to in "Critical Accounting Policies and Estimates--Environmental Matters."
Excluding the increase from this environmental adjustment, segment earnings
before depreciation, depletion and amortization increased $149.9 million (74%)
in 2004 compared to 2003. This increase, along with the $71.4 million (54%)
increase in earnings before depreciation, depletion and amortization in 2003
over 2002, was driven by higher earnings from oil and gas producing activities
and gas processing activities, higher deliveries of carbon dioxide, and
strategic acquisitions of additional working interests in the SACROC and Yates
oil field units since the end of 2002.

  Excluding earnings attributable to the 2004 environmental liability
adjustment, our CO2 segment's oil and gas producing activities and gas
processing activities reported earnings before depreciation, depletion and
amortization of $220.4 million in 2004, $103.6 million in 2003 and $51.5 million
in 2002. These increases of $116.8 million (113%) and $52.1 million (101%) from
2003 to 2004 and from 2002 to 2003, respectively, were primarily attributable to
increased oil production volumes, increases in the realized weighted average
price of oil per barrel, and acquisitions of additional ownership 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 in cash 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 $230.2
     million in cash and the assumption of $29.7 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
     unit and Marathon's 65% ownership interest in the Pecos Carbon Dioxide
     Pipeline Company. This transaction increased our ownership interest in the
     Yates oil field unit to nearly 50% and allowed us to become operator of the
     field.

  Excluding earnings attributable to the 2004 environmental liability
adjustment, our CO2 segment's carbon dioxide sales and carbon dioxide and crude
oil transportation activities reported earnings before depreciation, depletion
and amortization of $133.1 million in 2004, $100.0 million in 2003 and $80.7
million in 2002. The increase of $33.1 million (33%) in 2004 compared to 2003
was driven by higher revenues from carbon dioxide sales and deliveries, mainly
due to higher average carbon dioxide sale prices and higher transportation
volumes related to infrastructure expansions at the SACROC and Yates oil field
units. The increase of $19.3 million (24%) in earnings before depreciation,
depletion and amortization in 2003 compared to 2002 was chiefly due to higher
revenues from carbon dioxide pipeline delivery volumes, including the operations
of our Centerline carbon dioxide pipeline, which was completed and began
operations in May 2003.

   Capacity and deliverability of carbon dioxide in and around the Permian Basin
has expanded since the end of 2002 in order to accommodate growing customer
demand. In 2004, capital expenditures for our CO2 business segment totaled
$302.9 million, 11% higher than the $272.2 million of capital expenditures made
during 2003, and 86% higher than the $163.2 million of expenditures in 2002. The
year-over-year increases largely represented incremental spending for new well
and injection compression facilities at the SACROC and, to a much lesser extent,
Yates oil field units in order to enhance oil recovery from carbon dioxide
injection.

  In 2004, we also benefited from the acquisition of the Kinder Morgan Wink
Pipeline, a 450-mile crude oil pipeline located in West Texas. Effective August
31, 2004, we acquired all of the partnership interests in Kinder Morgan Wink
Pipeline, L.P. for $89.9 million in cash and the assumption of $10.4 million in
liabilities. The

                                       65
<PAGE>


acquisition of the pipeline and associated storage facilities allows us to
better manage crude oil deliveries from our oil field interests in West Texas.
The Wink Pipeline contributed $6.0 million in earnings before depreciation,
depletion and amortization during the last four months of 2004.

  Revenues earned by our CO2 business segment increased $244.3 million (98%) in
2004 compared to 2003, and $102.2 million (70%) in 2003 compared to 2002. The
increases were mainly due to higher crude oil and gasoline plant product sales
revenues, driven by higher oil production volumes, higher average crude oil and
gasoline product prices, and the additional working interest in the Yates oil
field that we acquired in November 2003. Combined, the assets we acquired on
November 1, 2003 contributed incremental revenues of approximately $96.3 million
in 2004.

  Daily oil production at the SACROC and Yates field units, both located in the
Permian Basin of West Texas, increased 40% and 3%, respectively, in 2004
compared to 2003, and 55% and 3%, respectively, in 2003 compared to 2002. We
also benefited from increases of 8% and 44%, respectively, in our realized
weighted average price of oil and natural gas liquids per barrel in 2004
compared to 2003, and a 6% increase in our realized weighted average price of
oil per barrel in 2003 compared to 2002. As a result of our carbon dioxide and
oil reserve ownership interests, we are exposed to commodity price risk
associated with physical crude oil and carbon dioxide sales that have pricing
tied to crude oil prices, 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.

  Additionally, in both 2004 and 2003, we realized higher revenues from carbon
dioxide transportation services. The year-over-year increases were mainly due to
higher transportation volumes, due to continued strong demand for carbon dioxide
throughout the Permian Basin. Combined deliveries of carbon dioxide on our
Central Basin Pipeline, our majority-owned Canyon Reef Carriers and Pecos
Pipelines, our Centerline Pipeline, and our 50% owned Cortez Pipeline, which is
accounted for under the equity method of accounting, increased 27% in 2004 and
17% in 2003. In 2004, we also realized higher revenues from carbon dioxide
sales, due to higher average prices; however, revenues from the sales of carbon
dioxide were lower in 2003 compared to 2002 due to a larger elimination of
intercompany profit, in 2003, related to an increase in the volumes of our
carbon dioxide utilized in our own operations. We do not recognize profits on
carbon dioxide sales to ourselves. Incremental revenues earned by our Kinder
Morgan Wink Pipeline totaled $7.8 million in 2004.

  As discussed in Note 2 to our consolidated financial statements included
elsewhere in this report, the cost of carbon dioxide that is associated with
enhanced recovery is capitalized as part of our development costs when it is
injected. The carbon dioxide costs incurred and capitalized as development costs
for our CO2 segment were $70.6 million, $45.9 million and $31.0 million for the
years ended December 31, 2004, 2003 and 2002, respectively. We estimate that
such costs will be approximately $44.1 million, $55.8 million and $59.2 million
in 2005, 2006 and 2007, respectively. It is expected that, due to the nature of
this enhanced recovery process and the characteristics of the underlying
reservoir, the capitalized cost for carbon dioxide in 2007 will represent a peak
and is expected to decline thereafter. In addition, as of December 31, 2004, our
projected expenditures for developing our proved undeveloped reserves will be
approximately $183.4 million in 2005, $121.7 million in 2006, and $68.6 million
in 2007.

   Both the $91.3 million (111%) increase in operating expenses in 2004 versus
2003, and the $31.5 million (62%) increase in operating expenses in 2003 versus
2002, were primarily related to higher operating and maintenance expenses,
higher fuel and power costs, and higher production taxes, all as a result of
higher oil production volumes, higher carbon dioxide delivery volumes, and
increases in oil reserve ownership interests and segment assets.

   Earnings from equity investments decreased $3.0 million (8%) in 2004 compared
to 2003. The decrease resulted from the absence of equity earnings, in 2004,
from our previous 15% ownership interest in MKM Partners, L.P. Following our
June 1, 2003 acquisition of its 12.75% interest in the SACROC unit, MKM Partners
was dissolved effective June 30, 2003, and the lack of equity earnings in 2004
more than offset a $2.0 million (6%) increase in equity earnings from our 50%
investment in the Cortez Pipeline Company. The increase in equity earnings from
Cortez was mainly due to higher carbon dioxide delivery volumes in 2004 versus
2003. 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

                                       66
<PAGE>

from our equity interest in Cortez was mainly due to higher carbon dioxide
delivery volumes, lower average debt balances and slightly lower borrowing
rates.

   Non-cash depreciation, depletion and amortization charges, including
amortization of excess cost of equity investments, were up $60.5 million (96%)
in 2004 compared to 2003 and $31.6 million (101%) in 2003 compared to 2002. The
increases were primarily due to year-over-year increases in production volumes,
capital investments, and acquisitions of property interests. In addition, the
capital additions we have made since the end of 2002 have increased the
unit-of-production depletion rates.

  For 2005, we currently expect that our CO2 segment will report earnings before
depreciation, depletion and amortization expense of approximately $474 million,
a 34% increase over 2004 (excluding the 2004 environmental expense adjustment).
The earnings increase is expected to be driven by the continuing development of
the SACROC and Yates oil field units.

  Terminals
<TABLE>
<CAPTION>
                                                                     Year Ended December 31,
                                                               ---------------------------------
                                                                  2004        2003        2002
                                                               ---------   ---------   ---------
                                                          (In thousands, except operating statistics)
<S>                                                            <C>         <C>         <C>
  Revenues..................................................   $ 541,857   $ 473,558   $ 428,048
  Operating expenses(a).....................................    (272,766)   (229,054)   (213,929)
  Earnings from equity investments..........................           1          41          45
  Other, net - income(b)....................................      18,255          88      15,550
  Income taxes(c)...........................................      (5,609)     (3,857)     (4,751)
                                                               ---------   ---------   ---------
    Earnings before depreciation, depletion and amortization
     expense and amortization of excess cost of equity
     investments............................................     281,738     240,776     224,963

  Depreciation, depletion and amortization expense..........     (42,890)    (37,075)    (30,046)
  Amortization of excess cost of equity investments.........           -           -           -
                                                               ---------   ---------   ---------
    Segment earnings........................................   $ 238,848   $ 203,701   $ 194,917
                                                               =========   =========   =========

  Bulk transload tonnage (MMtons)(d)........................        67.7        61.2        58.7
                                                               =========   =========   =========
  Liquids leaseable capacity (MMBbl)........................        36.8        36.2        35.3
                                                               =========   =========   =========
  Liquids utilization %.....................................        96.6%       96.0%       97.0%
                                                               =========   =========   =========
</TABLE>
----------

(a) Includes costs of sales, operations and maintenance expenses, fuel and power
    expenses and taxes, other than income taxes.
(b) Includes income of $18,651 and $16,000 in 2004 and 2002, respectively,
    associated with adjustments to environmental liabilities.
(c) Includes expense of $80 in 2004 associated with adjustments to environmental
    liabilities.
(d) 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 our coal, petroleum coke,
steel and other dry-bulk material terminals, as well as all the operations of
our petroleum and petrochemical-related liquids terminal facilities. The segment
reported earnings before depreciation, depletion and amortization of $281.7
million on revenues of $541.9 million in 2004. This compared to earnings before
depreciation, depletion and amortization of $240.8 million on revenues of $473.6
million in 2003 and earnings before depreciation, depletion and amortization of
$225.0 million on revenues of $428.0 million in 2002.

   As noted in the table above, the segment's 2004 and 2002 earnings included
earnings of $18.6 million and $16.0 million, respectively, from the adjustment
of our environmental liabilities referred to in "Critical Accounting Policies
and Estimates--Environmental Matters." Excluding these environmental
adjustments, segment earnings before depreciation, depletion and amortization
increased $22.3 million (9%) in 2004 compared to 2003, and increased $31.8
million (15%) in 2003 compared to 2002.

  The $22.3 million increase in earnings before depreciation, depletion and
amortization in 2004 over 2003 was driven by higher revenues from both our bulk
and liquids terminal businesses, due to (i) higher transfer volumes of bulk
products; (ii) higher demand for storage and distribution services offered for
petroleum and liquid chemical

                                       67
<PAGE>


products; and (iii) additional storage and throughput capacity due to both
terminal acquisitions and the completion of capital projects since the end of
2003. Combined, our bulk terminal facilities reported an almost 11% increase in
total bulk tonnage volumes transloaded during 2004, as compared to 2003. In
turn, completed capital expansions and betterments at our liquids facilities
since the end of 2003, which included the construction of additional petroleum
products storage tanks, have increased our liquids storage capacity by
approximately 600,000 barrels (2%), and at the same time, we have increased our
liquids utilization capacity.

  For terminal operations owned during both 2004 and 2003, growth in both
segment earnings before depreciation, depletion and amortization charges and
segment revenues were primarily attributable to record throughput at our Gulf
Coast liquids terminals, and to higher coal, bulk and synfuel volumes from
certain of our Mid-Atlantic terminals, which include our Chesapeake Bay,
Maryland bulk terminal and our Pier IX bulk terminal located in Newport News,
Virginia. Our two Gulf Coast liquids terminals, located on the Houston, Texas
Ship Channel, reported a combined $3.8 million increase in earnings before
depreciation, depletion and amortization in 2004 compared to 2003. The increase
was driven by a $7.1 million increase in revenues resulting from higher
throughput volumes, contract price escalations, additional service contracts and
new pipeline connections.

  Our Chesapeake Bay facility reported a $2.7 million increase in earnings
before depreciation, depletion and amortization in 2004 compared to 2003. The
increase was driven by a $7.5 million increase in revenues, earned by providing
additional stevedoring services and storage and transportation for products such
as coal, petroleum coke, pig iron and steel slag. Our Pier IX terminal, which
transloads both coal and cement and operates a synfuel plant on site, reported a
$4.0 million increase in earnings before depreciation, depletion and
amortization in 2004 compared to 2003. The increase was driven by a $6.3 million
increase in revenues resulting from higher synfuel revenues and coal activity.
In February 2004, Pier IX began to operate a second synfuel plant on site.

   Approximately half of the $31.8 million increase in earnings before
depreciation, depletion and amortization in 2003 over 2002 was attributable to
expansion projects at existing liquids terminals, and the remainder was
attributable to contributions from the bulk and liquid terminal businesses we
acquired since September 1, 2002. Terminal acquisitions completed since the
fourth quarter of 2003 helped increase both segment earnings before
depreciation, depletion and amortization and segment revenues in 2004 versus
2003. These acquisitions primarily consisted of the following:

  o the Kinder Morgan Tampaplex marine terminal and inland bulk storage
    warehouse facility, both located in Tampa, Florida and acquired in December
    2003;

  o the terminals owned and operated by Kinder Morgan River Terminals LLC and
    its consolidated subsidiaries, acquired effective October 6, 2004; and

  o the Kinder Morgan Fairless Hills bulk terminal facility, acquired effective
    December 1, 2004.

  Combined, these businesses, in 2004, contributed incremental earnings before
depreciation, depletion and amortization of $9.7 million and incremental
revenues of $26.7 million.

  Excluding earnings attributable to the 2002 environmental adjustments, $15.1
million (47%) of the segment's $31.8 million increase in earnings before
depreciation, depletion and amortization, and $14.9 million (33%) of the total
$45.6 million (11%) increase in revenues in 2003 versus 2002 was attributable to
internal growth, largely resulting from the expansion projects undertaken to
increase leaseable liquids capacity at our liquids terminal facility located in
Carteret, New Jersey on the New York Harbor, and at our two Gulf Coast liquids
terminals. We 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. Combined, these expansion projects contributed to an almost 3%
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 in 2003. Over half of the decline in utilization during 2003 was
associated with tank maintenance.

  In addition to the contributions to earnings and revenues that were
attributable to capital expansions, we benefited from additional liquids storage
contracts, escalations in annual contract provisions at many of our liquids
facilities, and higher returns from our 66 2/3% ownership interest in the
International Marine Terminals Partnership.

                                       68
<PAGE>


IMT, which operates a bulk commodity transfer terminal facility located in Port
Sulphur, Louisiana, reported increases of $1.5 million in earnings before
depreciation, depletion and amortization, and $5.1 million in revenues in 2003
versus 2002. The increases were driven by an almost 10% increase in bulk tonnage
transfer volume, primarily coal and iron ore, and by higher dockage revenues.

  The remaining $16.7 million (53%) of the segment's year-to-year increase in
earnings before depreciation, depletion and amortization and $30.7 million (67%)
of the year-to-year increase in revenues in 2003 versus 2002 was attributable to
strategic acquisitions of new terminal businesses acquired since September 1,
2002, including 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

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

  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.

  Both the $43.7 million (19%) increase in operating expenses in 2004 compared
to 2003 and the $15.1 million (7%) increase in operating expenses in 2003
compared to 2002, were due to the year-over-year increases in bulk tonnage
transfer volumes, liquids throughput and storage capacity, and the terminal
acquisitions described above. The increases were primarily reflected as higher
operating, maintenance, fuel and electricity expenses, including payroll,
trucking, equipment rental and docking expenses, all related to increased
dry-bulk and liquids product transfers and ship conveyance activities.

  Income tax expenses totaled $5.5 million in 2004 (excluding the $0.1 million
tax expense on earnings attributable to adjustments to the environmental
liabilities recorded by taxable entities), $3.9 million in 2003 and $4.8 million
in 2002. The $1.6 million (41%) increase in income tax expense in 2004 compared
to 2003 was primarily due to incremental expense related to the taxable income
of certain subsidiaries of Kinder Morgan River Terminals LLC. The $0.9 million
(19%) decrease in income tax expense in 2003 compared to 2002 was 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 $42.9 million,
$37.1 million and $30.0 million in each of the years ended December 31, 2004,
2003 and 2002, respectively. Both the $5.8 million (16%) increase in 2004 versus
2003 and the $7.1 million (24%) increase in 2003 versus 2002 were primarily due
to property acquisitions and capital spending, and to adjustments made to the
estimated remaining useful lives of depreciable property since the end of 2002.

  For 2005, we currently expect that our Terminals segment will report earnings
before depreciation, depletion and amortization expense of approximately $288
million, a 9% increase over 2004 (excluding the 2004 environmental expense
adjustment, net of taxes). The earnings increase is expected to be driven by
on-going capital expansion projects, by expected increases in bulk tonnage
transfer volumes, and by incremental earnings from the inclusion of a full year
of operations from Kinder Morgan River Terminals LLC and the Kinder Morgan
Fairless Hills terminal.

                                       69
<PAGE>

  Other
<TABLE>
<CAPTION>
                                                             Year Ended December 31,
                                                    --------------------------------------
                                                        2004         2003          2002
                                                    -----------  -----------   -----------
                                                       (In thousands - income/(expense))
<S>                                                 <C>          <C>           <C>
General and administrative expenses...............  $  (170,507) $  (150,435)  $  (122,205)
Unallocable interest, net.........................     (194,973)    (181,357)     (176,460)
Minority interest.................................       (9,679)      (9,054)       (9,559)
Loss from early extinguishment of debt............       (1,562)           -             -
Cumulative effect adjustment from change in
 accounting principle.............................            -        3,465             -
                                                    -----------  -----------   -----------
  Interest and corporate administrative expenses..  $  (376,721) $  (337,381)  $  (308,224)
                                                    ===========  ===========   ===========
</TABLE>

   Items not attributable to any segment include general and administrative
expenses, unallocable interest income, interest expense and minority interest.
We also included both the $1.6 million loss from our early extinguishment of
debt in 2004 and the $3.4 million benefit from the cumulative effect adjustment
of a change in accounting for asset retirement obligations as of January 1, 2003
(discussed above), as items not attributable to any business segment. The loss
from the early extinguishment of debt represented the excess of the price we
paid to repurchase and retire the principal amount of $87.9 million of
tax-exempt industrial revenue bonds over the bonds' carrying value. We assumed
these industrial revenue bonds as part of our January 2001 acquisition of Kinder
Morgan Liquids Terminals LLC. Pursuant to certain provisions that gave us the
right to call and retire the bonds prior to maturity, we took advantage of the
opportunity to refinance at lower rates. For more information on our early
extinguishment of debt, see Note 9 to our consolidated financial statements,
included elsewhere in this report.

   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 $170.5
million in 2004, compared to $150.4 million in 2003 and $122.2 million in 2002.
The $20.1 million (13%) increase in general and administrative expenses in 2004
compared to 2003 was principally due to higher employee bonus and benefit
expenses, higher corporate and employee-related insurance expenses, and higher
corporate service expenses, including legal, internal audit and human resources.
The $28.2 million (23%) increase in general and administrative expenses in 2003
compared to 2002 was primarily due to higher legal expenses, higher employee
benefit and pension costs and higher overall corporate and employee-related
insurance expenses. We continue to aggressively manage our infrastructure
expense and to focus on our productivity and expense controls.

  Interest expense, net of interest income, totaled $195.0 million in 2004,
$181.4 million in 2003 and $176.5 million in 2002. Although our average
borrowing rates were essentially flat across both 2003 and 2004, we incurred a
$13.6 million (7%) increase in net interest charges in 2004 as a result of
higher average borrowings. The increase in average borrowings was primarily due
to higher capital spending related to internal expansions and improvements, and
to incremental borrowings made in connection with acquisition expenditures. For
more information on our capital expansion and acquisition expenditures, see
"Liquidity and Capital Resources - Investing Activities". The $4.9 million (3%)
increase in net interest items in 2003 compared to 2002 reflects higher average
borrowings since the end of 2002, partially offset by decreases in average
borrowing rates.

   Minority interest, which includes the 1.0101% general partner interest in our
five operating limited partnerships, totaled $9.7 million in 2004, compared to
$9.1 million in 2003 and $9.6 million in 2002. The $0.6 million (7%) increase in
2004 versus 2003 resulted mainly from higher overall partnership income, partly
offset by our November 2003 acquisition of the remaining approximate 32%
ownership interest in MidTex Gas Storage Company, LLP that we did not already
own, thereby eliminating the associated minority interest. The $0.5 million (5%)
decrease in 2003 compared to 2002 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 associated minority
interest.

Liquidity and Capital Resources

  We attempt to maintain a conservative overall capital structure, with a
long-term target mix of approximately 60% equity and 40% debt. The following
table illustrates the sources of our invested capital (dollars in thousands). In
addition to our results of operations, these balances are affected by our
financing activities as discussed below:

                                       70
<PAGE>


<TABLE>
<CAPTION>
                                                                  December 31,
                                                       ----------------------------------
                                                          2004        2003        2002
                                                       ----------  ----------  ----------
<S>                                                    <C>         <C>         <C>
Long-term debt, excluding market value of interest     $4,722,410  $4,316,678  $3,659,533
rate swaps...........................................
Minority interest....................................      45,646      40,064      42,033
Partners' capital, excluding accumulated other
comprehensive loss...................................   4,353,863   3,666,737   3,461,186
                                                       ----------  ----------  ----------
  Total capitalization...............................   9,121,919   8,023,479   7,162,752
Short-term debt, less cash and cash equivalents......           -     (21,081)    (41,088)
                                                       ----------  ----------  ----------
  Total invested capital.............................  $9,121,919  $8,002,398  $7,121,664
                                                       ==========  ==========  ==========
Capitalization:
  Long-term debt, excluding market value of interest
   rate swaps........................................        51.8%       53.8%       51.1%
  Minority interest..................................         0.5%        0.5%        0.6%
  Partners' capital, excluding accumulated other
comprehensive loss...................................        47.7%       45.7%       48.3%
                                                       ----------  ----------  ----------
                                                            100.0%      100.0%      100.0%
                                                       ==========  ==========  ==========
Invested Capital:
  Total debt, less cash and cash equivalents and
       excluding market value of interest
       rate swaps....................................        51.8%       53.7%       50.8%
  Partners' capital and minority interest, excluding
       accumulated other comprehensive loss ........         48.2%       46.3%       49.2%
                                                       ----------  ----------  ----------
                                                            100.0%      100.0%      100.0%
                                                       ==========  ==========  ==========
</TABLE>

  We employ a centralized cash management program that essentially concentrates
the cash assets of our operating partnerships and their subsidiaries in joint
accounts for the purpose of providing financial flexibility and lowering the
cost of borrowing. Our centralized cash management program provides that funds
in excess of the daily needs of our operating partnerships and their
subsidiaries are concentrated, consolidated, or otherwise made available for use
by other entities within our consolidated group. We place no restrictions on the
ability to move cash between entities, payment of inter-company balances or the
ability to upstream dividends to parent companies.

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

  Our 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 facility, 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 retained
    cash (resulting from including i-units in the determination of cash
    distributions per unit but paying quarterly distributions on i-units in
    additional i-units rather than cash), additional borrowings, the issuance of
    additional common units or the 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 that some institutional
investors prefer shares of KMR over our common units due to tax and other
regulatory considerations. We are able to access this segment of the capital
market through KMR's purchases of i-units issued by us with the proceeds from
the sale of KMR shares to institutional investors.

                                       71
<PAGE>

  Short-term Liquidity

  Our principal sources of short-term liquidity are our revolving bank credit
facility, our $1.25 billion short-term commercial paper program (which is
supported by our revolving bank credit facility, with the amount available for
borrowing under our credit facility being reduced by our outstanding commercial
paper borrowings) and cash provided by operations.

  In August 2004, we replaced our previous 364-day and three-year credit
facilities, which had a combined borrowing capacity of $1.05 billion, with a
five-year senior unsecured revolving credit facility that has a borrowing
capacity of $1.25 billion. Our five-year bank facility is due August 18, 2009,
and can be used for general corporate purposes and as a backup for our
commercial paper program. There were no borrowings under our credit facility as
of December 31, 2004. After inclusion of our outstanding commercial paper
borrowings and letters of credit, the remaining available borrowing capacity
under our bank facility was $733.0 million as of December 31, 2004.

  For the year ended December 31, 2004, we continued to generate strong cash
flow from operations, and we provided for additional liquidity by maintaining a
sizable amount of excess borrowing capacity related to our commercial paper
program and long-term revolving credit facility. As of December 31, 2004, our
outstanding short-term debt was $621.2 million. We intended and had the ability
to refinance all of our short-term debt on a long-term basis under our unsecured
long-term credit facility. Accordingly, such amounts have 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
facility, see Note 9 to our consolidated financial statements included elsewhere
in this report.

  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 premiums. All of our outstanding debt securities
are unsecured obligations that rank equally with all of our other senior debt
obligations. A modest amount of secured debt has been incurred by some of our
subsidiaries. Our fixed rate notes provide that we may redeem the notes at any
time at a price equal to 100% of the principal amount of the notes plus accrued
interest to the redemption date plus a make-whole premium.

  On November 12, 2004, we closed a public offering of $500 million in principal
amount of 5.125% senior notes due November 15, 2014 at a price to the public of
99.914%. In the offering, we received proceeds, net of underwriting discounts
and commissions, of approximately $496.3 million. We used the proceeds to reduce
the then outstanding balance on our commercial paper borrowings. As of December
31, 2004, our total liability balance due on the various series of our senior
notes was approximately $4,189.6 million. For more information on our senior
notes, see Note 9 to our consolidated financial statements included elsewhere in
this report.

  Equity Financing

  On February 9, 2004, we issued, in a public offering, an additional 5,300,000
of our common units at a price of $46.80 per unit, less commissions and
underwriting expenses. After commissions and underwriting expenses, we received
net proceeds of $237.8 million for the issuance of these common units. We used
the proceeds to reduce the borrowings under our commercial paper program.

  On November 10, 2004, we issued, in a public offering, an additional 5,500,000
of our common units at a price of $46.00 per unit, less commissions and
underwriting expenses. On December 8, 2004, we issued an additional 575,000
units upon the exercise by the underwriters of an over-allotment option. After
commissions and underwriting expenses, we received net proceeds of $268.3
million for the issuance of these 6,075,000 common units. We used the proceeds
to reduce the borrowings under our commercial paper program.

  On March 25, 2004, KMR issued an additional 360,664 of its
shares at a price of $41.59 per share, less closing fees and
commissions.  The net proceeds from the offering were used to buy
additional i-units from us.  After

                                       72
<PAGE>

closing and commission expenses, we received net proceeds of $14.9 million for
the issuance of 360,664 i-units. We used the proceeds from the i-unit issuance
to reduce the borrowings under our commercial paper program.

  On November 10, 2004, KMR issued an additional 1,300,000 of its shares at a
price of $41.29 per share, less closing fees and commissions. The net proceeds
from the offering were used to buy additional i-units from us. We received
proceeds of $52.6 million for the issuance of 1,300,000 i-units. We used the
proceeds from the i-unit issuance to reduce the borrowings under our commercial
paper program.

  Capital Requirements for Recent Transactions

   During 2004, our cash outlays for the acquisitions of assets and equity
investments totaled $479.9 million. With the exception of our acquisition of
TransColorado, which was partially acquired by the issuance of additional common
units to KMI, we utilized our commercial paper program to fund these
acquisitions and then reduced our short-term borrowings with the proceeds from
our February and November 2004 issuances of common units, our March and November
2004 issuances of i-units, and our November 2004 issuance 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 2005 through a combination of
long-term debt, equity and the issuance of additional commercial paper to
replace maturing commercial paper borrowings.

   In February 2005, a shelf registration statement became effective that will
allow us to issue up to a total of $2 billion in debt and/or equity securities.
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. For more information on our capital requirements during
2004 in regard to our acquisition expenditures, see Note 3 to our consolidated
financial statements included elsewhere in this report.

  Summary of Off Balance Sheet Arrangements

   We have invested in entities that are not consolidated in our financial
statements. As of December 31, 2004, 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)             $114         $202          $101 (2)
Cortez Pipeline Company........     Partner

Red Cedar Gas Gathering             General          49%          Southern Ute       $187         $47            $47
    Company....................     Partner                       Indian Tribe

Nassau County,                          N/A          N/A          Nassau County,     N/A          N/A            $25
    Florida Ocean Highway                                         Florida Ocean
    and Port Authority (3).....                                   Highway and
                                                                  Port Authority
</TABLE>
---------

(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 partners of Cortez Pipeline Company are required to
    contribute capital to Cortez in the event of a cash deficiency. The
    agreement contractually supports the financings of Cortez Capital
    Corporation, a wholly-owned subsidiary of Cortez Pipeline Company, by
    obligating the partners of Cortez Pipeline to fund cash deficiencies at
    Cortez Pipeline, including anticipated deficiencies and cash deficiencies
    relating to the repayment of principal and interest on the debt of Cortez
    Capital Corporation. The partners' respective parent or other companies
    further severally guarantee the obligations of the Cortez Pipeline owners
    under this agreement.

                                       73
<PAGE>

(3) Arose from our Vopak terminal acquisition in July 2001. Nassau County,
    Florida Ocean Highway and Port Authority is a political subdivision of the
    State of Florida. During 1990, Ocean Highway and Port Authority issued its
    Adjustable Demand Revenue Bonds in the aggregate principal amount of $38.5
    million for the purpose of constructing certain port improvements located in
    Fernandino Beach, Nassau County, Florida. A letter of credit was issued as
    security for the Adjustable Demand Revenue Bonds and was guaranteed by the
    parent company of Nassau Terminals LLC, the operator of the port facilities.
    In July 2002, we acquired Nassau Terminals LLC and became guarantor under
    the letter of credit agreement. In December 2002, we issued a $28 million
    letter of credit under our credit facilities and the former letter of credit
    guarantee was terminated. As of December 31, 2004, the value of this letter
    of credit outstanding under our credit facility was $25 million. Principal
    payments on the bonds are made on the first of December each year and
    reductions are made to the letter of credit.

(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.

   We account for our investments in the Red Cedar Gas Gathering Company and
Cortez Pipeline Company under the equity method of accounting. For the year
ended December 31, 2004, our share of earnings, based on our ownership
percentage, before income taxes and amortization of excess investment cost was
$34.2 million from Cortez Pipeline Company, and $14.7 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.

  Summary of Certain Contractual Obligations
<TABLE>
<CAPTION>

                                                 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>
Contractual Obligations:
Commercial paper outstanding......     $  416,900    $416,900     $     --      $     --    $       --
Other debt borrowings(a)
 Principal payments...............      4,305,510     204,268      297,734       252,871     3,550,637
 Interest payments................      3,502,266     275,608      519,671       481,145     2,225,842
Lease obligations(b)..............        166,418      30,678       50,160        35,465        50,115
Postretirement welfare plans(c)...          1,800         300          600           600           300
Other obligations(d)..............         94,755      15,229       25,307        21,495        32,724
                                       ----------    --------     --------      --------    ----------
Total.............................     $8,487,649    $942,983     $893,472      $791,576    $5,859,618
                                       ==========    ========     ========      ========    ==========

Other commercial commitments:
Standby letters of credit(e)......     $  162,586    $132,253     $ 30,333      $     --    $       --
                                       ==========    ========     ========      ========    ==========
Capital expenditures(f)...........     $   13,788    $ 13,788            -             -             -
                                       ==========    ========     ========      ========    ==========
</TABLE>
----------

(a) Debt obligations exclude adjustments for interest rate swap agreements.

(b) Represents commitments for capital leases, including interest, and operating
    leases.

(c) Represents expected annual contributions of $0.3 million per year based on
    calculations of independent enrolled actuary as of December 31, 2004.

(d) Consist of payments due under carbon dioxide take-or-pay contracts, carbon
    dioxide removal contracts and natural gas liquids joint tariff agreements.

(e) The $162.6 million in letters of credit outstanding as of December 31 2004
    consisted of the following: (i) a $50 million letter of credit supporting
    our hedging of commodity price risks; (ii) our $30.3 million guarantee under
    letters of credit supporting our International Marine Terminals Partnership
    Plaquemines, Louisiana Port, Harbor, and Terminal Revenue Bonds; (iii) a
    $25.9 million letter of credit supporting Nassau County, Florida Ocean
    Highway and Port Authority tax-exempt bonds; (iv) a $25.4 million letter of
    credit supporting our Kinder Morgan Liquids Terminals LLC New Jersey
    Economic Development Revenue Bonds; (v) a $24.1 million letter of credit
    supporting our Kinder Morgan Operating L.P. "B" tax-exempt bonds; (vi) a
    $5.4 million letter of credit supporting our Arrow Terminals, L.P. Illinois
    Development

                                       74
<PAGE>


    Revenue Bonds; and (vii) three letters of credit totaling $1.5 million,
    supporting workers' compensation insurance polices and equipment rental
    obligations.

(f) Represents commitments for the purchase of plant, property and equipment as
    of December 31, 2004.

  In our 2005 sustaining capital expenditure plan, we have budgeted $125.8
million, primarily for the purchase of plant and equipment. Sustaining capital
expenditures are defined as capital expenditures which do not increase the
capacity of an asset. All of our capital expenditures, with the exception of
sustaining capital expenditures, are discretionary.

  Operating Activities

   Net cash provided by operating activities was $1,155.1 million in 2004,
versus $768.5 million in 2003. The $386.6 million (50%) period-to-period
increase in 2004 compared to 2003 includes the following cash flow increases:

  o a $236.2 million increase in cash from overall higher partnership income in
    2004, net of non-cash items including depreciation, depletion and
    amortization charges and undistributed earnings from equity investments;

  o a $141.7 million increase in cash inflows relative to net changes in working
    capital items; and

  o a $44.9 million increase related to transportation rate reparation and
    refund payments made in 2003.

   The higher partnership income reflects the increased level of segment
earnings before depreciation, depletion and amortization reported in 2004 and
discussed in "Results of Operations." The favorable inflows from working capital
in 2004 were mainly related to timing differences in the payments made on our
trade and related party account payables. In addition to 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.
The reparation and refund payments made in 2003 were mandated under an order
from the Federal Energy Regulatory Commission pursuant to a consolidated
proceeding in FERC Docket OR92-8-000 concerning rates charged by our Pacific
operations on certain interstate portions of their products pipelines.

  Offsetting the overall increase in cash provided by operating activities was a
$17.8 million (21%) decrease in distributions received from equity investments
and an $18.4 million decrease related to higher payments made in 2004 on
non-current accounts, most notably, higher capitalizable project costs and
higher cash settlements on long-term reserves and other deferred credits. The
decrease in distributions from our equity investments was primarily due to lower
distributions from our previous investment in MKM Partners, L.P. and our current
investment in the Red Cedar Gas Gathering Company. MKM Partners, L.P. was
dissolved on June 30, 2003, thereby eliminating our 15% equity ownership
interest, and the decrease in distributions from our 49% equity ownership
interest in Red Cedar related to its lower earnings in 2004 versus 2003.

  Investing Activities

  Net cash used in investing activities was $1,250.5 million for the year ended
December 31, 2004, compared to $943.1 million for the prior year. The $307.4
million (33%) increase in funds utilized in investing activities was mainly
attributable to higher payments made for capital expenditures, strategic
acquisitions, and incremental purchases of natural gas liquids related to the
initiation of our North System's line-fill program. Partially offsetting the
overall increase in cash used in investing activities was a $7.0 million (50%)
decrease in contributions to equity investments, mainly due to lower
contributions made to Plantation Pipe Line Company.

   Including expansion and maintenance projects, our capital expenditures were
$747.3 million in 2004 versus $577.0 million in 2003. The $170.3 million (30%)
increase was mainly driven by higher capital investment in our Products
Pipelines and CO2 business segments, as we continued to expand and grow our
existing asset infrastructure

                                       75
<PAGE>


by adding both throughput capacity to our products pipelines and production and
delivery capacity to our oil field and carbon dioxide flooding operations. Our
sustaining capital expenditures were $119.2 million for 2004, compared to $92.8
million for 2003.

  Additionally, we continue to make significant investments in strategic
acquisitions to fuel future growth and increase unitholder value. During 2004,
our acquisition outlays for assets and investments totaled $479.9 million, a
$120.0 million (33%) increase over the $359.9 million spent for acquisitions in
2003. Both our 2004 and 2003 acquistion expenditures are discussed more fully in
Note 3 to our consolidated financial statements included elsewhere in this
report.

  We also spent $23.0 million in 2004 pursuant to the implementation of our
North System's natural gas liquids line-fill program, as discussed in "Results
of Operations." The line-fill program calls for us to purchase natural gas
liquids to be used as pipeline line-fill and pass the carrying costs on to our
shippers through a cost of service filing with the FERC. As of December 31,
2004, we had purchased approximately 650,000 barrels of propane, normal butane
and natural gasoline, which we believe will help mitigate the operational
constraints that resulted from a lack of product supplies caused by shippers
reducing their inventory levels at the close of the winter season.

  Financing Activities

   Net cash provided by financing activities was $72.1 million in 2004, compared
to $156.8 million in 2003. The $84.7 million (54%) period-to-period decrease in
cash provided by financing activities resulted primarily from lower cash inflows
from overall debt financing activities and from higher partnership
distributions. These overall decreases in cash provided by financing activities
were partially offset by an increase in cash inflows from overall partnership
equity issuances and an increase in temporary cash book overdrafts.

   During each of the years 2004 and 2003, we used our commercial paper
borrowings to fund our asset acquisitions, capital expansion projects and other
partnership activities, and we subsequently raised funds to refinance a portion
of those borrowings by completing public 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.

  In 2004, we received $257.0 million from overall debt financing activities,
which included both issuances and payments of debt, loans to related parties and
debt issuance costs. In 2003, our debt financing activities provided us with
$655.1 million in cash. The $398.1 million (61%) period-to-period net decrease
was primarily due to the following:

  o a $215.4 million decrease in net incremental commercial paper borrowings in
    2004 versus 2003;

  o an $87.9 million decrease related to payments, in 2004, to redeem and retire
    the principal amount of five series of tax-exempt bonds related to certain
    liquids terminal facilities. Pursuant to certain provisions that gave us the
    right to call and retire the bonds prior to maturity, we took advantage of
    the opportunity to refinance at lower rates;

  o a $96.3 million decrease related to a long-term loan we made to Plantation
    Pipe Line Company in 2004, which corresponded to our 51.17% ownership
    interest and allowed Plantation to pay all of its outstanding credit
    facility and commercial paper borrowings. In exchange, we received a seven
    year note receivable bearing interest at the rate of 4.72% per annum;

  o a $28.4 million decrease related to payments made to retire a significant
    portion of the $33.7 million of outstanding debt assumed as part of our
    October 2004 acquisition of Kinder Morgan River Terminals, LLC;

  o a $9.5 million decrease related to payments made to retire all of the
    outstanding debt assumed as part of our August 2004 acquisition of Kinder
    Morgan Wink Pipeline, L.P.; and

  o a $37.1 million increase related to payments made in December 2003 to retire
    the outstanding balance under SFPP, L.P.'s Series F notes.

                                       76
<PAGE>


  In addition, in each of November 2004 and 2003, we closed public offerings of
$500 million in principal amount of senior notes. The offerings resulted in cash
inflows, net of discounts and issuing costs, of $496.3 million and $493.6
million, respectively.

  Cash distributions to all partners, consisting of our common and Class B
unitholders (including KMI), our general partner, and minority interests,
increased to $791.0 million in 2004 compared to $679.3 million in 2003. The
$111.7 million (16%) increase in distributions was due to increases in the per
unit cash distributions paid, the number of outstanding units and the resulting
increase in our general partner incentive distributions.

  The $398.5 million period-to-period increase in cash inflows from additional
partnership equity issuances was related to the excess of cash received from our
2004 issuances of both common and i-units over cash received from our June 2003
issuance of common units. In 2004, we received proceeds of $574.1 million from
additional partnership equity issuances, primarily consisting of the following
(amounts are net of all commissions and underwriting expenses):

  o $237.8 million received from our issuance of 5,300,000 common units in a
    February 2004 public offering;

  o $14.9 million received from our issuance of 360,664 i-units in March 2004 to
    KMR;

  o $268.3 million received from our issuance of 6,075,000 common
    units in a November 2004 public offering; and

  o $52.6 million received from our issuance of 1,300,000 i-units in November
    2004 to KMR.

  By comparison, in 2003, we received net proceeds of $175.6 million from
additional partnership equity issuances, mainly the result of $173.3 million
received from the issuance of 4,600,000 of our common units in a June 2003
public offering. In both 2003 and 2004, we used the proceeds from each of these
issuances to reduce the borrowings under our commercial paper program.

  The $29.9 million period-to-period increase in cash inflows from cash book
overdrafts resulted from temporary increases in outstanding checks due to timing
differences in the payments of year-end accruals and outstanding vendor invoices
in 2004 versus 2003.

  We paid distributions of $2.81 per unit in 2004 compared to $2.575 per unit in
2003. The 9% increase in distributions paid per unit principally resulted from
favorable operating results in 2004. We also distributed 3,500,512 and 3,342,417
i-units in quarterly distributions during 2004 and 2003, 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 2004 and 2003. 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 and net
reductions in reserves, less cash disbursements and net additions to reserves
and amounts payable to the former general partner of SFPP, L.P. in respect of
its remaining 0.5% interest in SFPP.

  Our general partner is granted discretion by our partnership agreement, which
discretion has been delegated to KMR, subject to the approval of our general
partner in certain cases, to establish, maintain and adjust reserves for future
operating expenses, debt service, maintenance capital expenditures, rate refunds
and distributions for the next four quarters. These reserves are not restricted
by magnitude, but only by type of future cash requirements with

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<PAGE>

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 2004,
2003 and 2002, we distributed 87.0%, 100.4% and 97.6%, of the total of cash
receipts less cash disbursements, respectively (calculations assume that KMR
unitholders received cash). The difference between these numbers and 100% of
distributable cash flow reflects net changes in reserves.

  Our general partner and owners of our common units and Class B units receive
distributions in cash, while KMR, the sole owner of our i-units, receives
distributions in additional i-units. We do not distribute cash to i-unit owners
but retain the cash for use in our business. However, the cash equivalent of
distributions of i-units is treated as if it had actually been distributed for
purposes of determining the distributions to our general partner.

  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 2004 was $390.7 million, while the incentive distribution paid
to our general partner during 2004 was $370.5 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 14, 2005, we paid a quarterly distribution of $0.74 per unit for
the fourth quarter of 2004. This distribution was 9% greater than the $0.68
distribution per unit we paid for the fourth quarter of 2003 and 7% greater than
the $0.69 distribution per unit we paid for the first quarter of 2004. 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 $0.74 cash distribution per common unit. We believe that future operating
results will continue to support similar levels of quarterly cash and i-unit
distributions; however, no assurance can be given that future distributions will
continue at such levels.

  Litigation and Environmental

  As of December 31, 2004, we have recorded a total reserve for environmental
claims, without discounting and without regard to anticipated insurance
recoveries, in the amount of $40.9 million. The reserve is primarily established
to address and clean up soil and ground water impacts from former releases to
the environment at facilities we have acquired. 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

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<PAGE>

employees, and, if appropriate, collect soil and groundwater samples.

   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 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

  The Pipeline Safety Improvement Act of 2002 requires pipeline companies to
perform integrity tests on natural gas transmission pipelines that exist in high
population density areas that are designated as High Consequence Areas. Pipeline
companies are required to perform the integrity tests within ten years of
December 17, 2002, the date of enactment, and must perform subsequent integrity
tests on a seven year cycle. At least 50% of the highest risk segments must be
tested within five years of the enactment date. The risk ratings are based on
numerous factors, including the population density in the geographic regions
served by a particular pipeline, as well as the age and condition of the
pipeline and its protective coating. Testing will consist of hydrostatic
testing, internal electronic testing, or direct assessment of the piping. A
similar integrity management rule for refined petroleum products pipelines
became effective May 29, 2001. All baseline assessments for products pipelines
must be completed by March 31, 2008, and at least half of the line pipe
affecting High Consequence Areas was required to be assessed by September 30,
2004. We have included all incremental expenditures estimated to occur during
2005 associated with the Pipeline Safety Improvement Act of 2002 and the
integrity management of our products pipelines in our 2005 budget and capital
expenditure plan.

  Please refer to Note 16 to our consolidated financial statements included
elsewhere in this report for additional information regarding regulatory
matters.

Recent Accounting Pronouncements

  Please refer to Note 17 to our consolidated financial statements included
elsewhere in this report for information concerning recent accounting
pronouncements.

Information Regarding Forward-Looking Statements

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

   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;

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<PAGE>


   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;

   o our ability to obtain insurance coverage without a significant level of
     self-retention of risk;

   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;

   o the extent of our success in discovering, developing and producing oil and
     gas reserves, including the risks inherent in exploration and development
     drilling, well completion and other development activities;

   o engineering and mechanical or technological difficulties with operational
     equipment, in well completions and workovers, and in drilling new wells;

   o the uncertainty inherent in estimating future oil and natural
     gas production or reserves;

   o the timing and success of business development efforts; and

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<PAGE>


   o unfavorable results of litigation and the fruition of contingencies
     referred to in Note 16 to our consolidated financial statements included
     elsewhere in this report.

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

Energy Financial Instruments

   We are exposed to commodity market risk and other external risks, such as
weather-related risk, in the ordinary course of business. We take steps to limit
our exposure to these risks in order to maintain a more stable and predictable
earnings stream. Accordingly, 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.

   While we enter into derivative transactions only with investment grade
counterparties and actively monitor their credit ratings, it is nevertheless
possible that losses will result from counterparty credit risk in the future.
The credit ratings of the primary parties from whom we purchase energy financial
instruments are as follows:

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

   We account for our risk management 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 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
application of SFAS No. 133 has resulted in deferred net loss amounts of $457.3
million and $155.8 million being reported as "Accumulated other comprehensive
loss" in our accompanying balance sheets as of December 31, 2004 and December
31, 2003, respectively.

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<PAGE>


   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, 2004 and
2003, value-at-risk reached a high of $8.6 million and $12.8 million,
respectively, and a low of $2.4 million and $2.2 million, respectively.
Value-at-risk as of December 31, 2004, was $8.6 million and averaged $5.1
million for 2004. Value-at-Risk as of December 31, 2003, was $6.2 million and
averaged $5.2 million for 2003.

   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, with the exception of a minor amount of
hedging inefficiency, is offset by changes in the value of the underlying
physical transactions. For more information on our risk management activities,
see Note 14 to our consolidated financial statements included elsewhere in this
report.

Interest Rate Risk

   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 our 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, 2004 and 2003, the carrying values of our long-term fixed
rate debt were approximately $4,209.6 million and $3,801.7 million,
respectively, compared to fair values of $4,626.9 million and $4,372.3 million,
respectively. Fair values were determined using quoted market prices, where
applicable, or future cash flow discounted at market rates for similar types of
borrowing arrangements. A hypothetical 10% change in the average interest rates
applicable to such debt for 2004 and 2003, respectively, would result in changes
of approximately $161.0 million and $158.6 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 $495.1 million as of December 31, 2004 and $493.0 million as of December 31,
2003. 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 our variable rate debt,
including adjustments for notional swap amounts as of December 31, 2004 and
2003, would result in changes of approximately $11.7 million and $10.9 million
in our 2004 and 2003 annualized pre-tax earnings, respectively.

  As of December 31, 2004 and 2003, we were a party to interest rate swap
agreements with notional principal amounts of $2.3 billion and $2.1 billion,
respectively. We entered into these agreements for the purpose of hedging the
interest rate risk associated with our fixed and variable rate debt 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 2004

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<PAGE>

or 2003. 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. In general, we attempt to maintain an overall
target mix of approximately 50% fixed rate debt and 50% variable rate debt.

   As of December 31, 2004, 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 101.


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

   None.


Item 9A. Controls and Procedures.

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

  As of December 31, 2004, 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.

Management's Report on Internal Control Over Financial Reporting

  Our management is responsible for establishing and maintaining adequate
internal control over financial reporting, as such term is defined in Exchange
Act Rule 13a-15(f). Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements. Projections of any
evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the
degree of compliance with the policies or procedures may deteriorate. Under the
supervision and with the participation of our management, including our
principal executive officer and principal financial officer, we conducted an
evaluation of the effectiveness of our internal control over financial reporting
based on the framework in Internal Control - Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission. Based on our
evaluation under the framework in Internal Control - Integrated Framework, our
management concluded that our internal control over financial reporting was
effective as of December 31, 2004.

  Our management's assessment of the effectiveness of our internal control over
financial reporting as of December 31, 2004 has been audited by
PricewaterhouseCoopers LLP, an independent registered public accounting firm, as
stated in their report which is included elsewhere in this report.

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<PAGE>

  Certain businesses we acquired during 2004 were excluded from the scope of our
management's assessment of the effectiveness of our internal control over
financial reporting as of December 31, 2004. These businesses excluded were
North Charleston Bulk Terminal, Kinder Morgan Wink Pipeline, L.P., Kinder Morgan
River Terminals LLC, Charter Products Terminals and Kinder Morgan Fairless Hills
Terminal. These businesses, in the aggregate, constituted .04% of our
consolidated revenues for 2004 and 2.75% of our consolidated assets at December
31, 2004.

Changes in Internal Control Financial Reporting

  There has been no change in our internal control over financial reporting
during the fourth quarter of 2004 that has materially affected, or is reasonably
likely to materially affect, our internal control over financial reporting.

Item 9B.  Other Information.

   None.

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                                    PART III

Item 10.  Directors 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, the delegate of our general partner.
All directors of our general partner are elected annually by, and may be removed
by, Kinder Morgan (Delaware), Inc. as its sole shareholder, and all directors of
KMR are elected annually by, and may be removed by, our general partner as the
sole holder of the delegate's voting shares. Kinder Morgan (Delaware), Inc. is a
wholly owned subsidiary of KMI. All officers of the general partner and all
officers of KMR serve at the discretion of the board of directors of our general
partner.

       Name               Age Position with our General Partner and the Delegate
------------------        --- --------------------------------------------------
Richard D. Kinder.......  60  Director, Chairman, Chief Executive Officer and
                              President
C. Park Shaper..........  36  Director, Executive Vice President and Chief
                              Financial Officer
Edward O. Gaylord.......  73  Director
Gary L. Hultquist.......  61  Director
Perry M. Waughtal.......  69  Director
Thomas A. Bannigan......  51  Vice President (President, Products Pipelines)
Richard T. Bradley......  49  Vice President (President, CO2)
David D. Kinder.........  30  Vice President, Corporate Development
Joseph Listengart.......  36  Vice President, General Counsel and Secretary
Deborah A. Macdonald....  53  Vice President (President, Natural Gas Pipelines)
Jeffrey R. Armstrong....  36  Vice President (President, Terminals)
James E. Street.........  48  Vice President, Human Resources and Administration

     Richard D. Kinder is Director, Chairman, Chief Executive Officer and
President 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 was elected
President of KMR, Kinder Morgan G.P., Inc. and KMI in July 2004. Mr. Kinder is
the uncle of David Kinder, Vice President, Corporate Development of KMR, Kinder
Morgan G.P., Inc. and KMI.

     C. Park Shaper is Director, Executive Vice President and Chief Financial
Officer of KMR and Kinder Morgan G.P., Inc. and Executive Vice President and
Chief Financial Officer of KMI. Mr. Shaper was elected Executive Vice President
of KMR, Kinder Morgan G.P., Inc. and KMI in July 2004, and 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 was elected Vice President, Treasurer and Chief Financial Officer of
KMI in January 2000, and served as Treasurer of KMI from January 2000 to January
2004. 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. 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.

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<PAGE>


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

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

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

     David D. Kinder is Vice President, Corporate Development 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. 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
President, General Counsel and Secretary of KMI in October 1999. Mr. Listengart
was elected Secretary of Kinder Morgan G.P., Inc. in November 1998 and has been
an employee of Kinder Morgan G.P., Inc. since March 1998. 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 Vice President (President, Natural Gas Pipelines)
of KMR, Kinder Morgan G.P., Inc. and KMI. She was elected as Vice President
(President, Natural Gas Pipelines) of KMR, Kinder Morgan G.P., Inc. and KMI in
June 2002. Ms. Macdonald served as President of Natural Gas Pipeline Company of
America from October 1999 to March 2003. 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 Vice President (President, Terminals) of KMR and
Kinder Morgan G.P., Inc. Mr. Armstrong became Vice President (President,
Terminals) in July 2003. He served as President, Kinder Morgan Liquids Terminals
LLC from March 1, 2001, when the company was formed via the acquisition of GATX
Terminals, through July 2003. From 1994 to 2001, Mr. Armstrong worked for GATX
Terminals, where he was General Manager of their East Coast operations. He
received his bachelor's degree from the United States Merchant Marine Academy
and an MBA from the University of Notre Dame.

     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. 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.

                                       86
<PAGE>

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 acts as our board of directors. Similarly, the standing
committees of KMR's board of directors function as standing committees of our
board. KMR's board of directors is comprised of the same persons who comprise
our general partner's board of directors. References in this report to the board
mean KMR's board, acting as our board of directors, and references to committees
mean KMR's committees, acting as committees of our board of directors.

  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, interim chief executive officer or interim executive officer, such
    employment relationship ended by the date of determination);

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

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

  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 quarterly and special board meetings, these three
non-management directors also meet in executive session without members of
management. In December 2004, Mr. Gaylord was elected for a one year term 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. Waughtal is the
chairman of the audit committee and has been determined by the board to be an
"audit committee financial expert."

                                       87
<PAGE>


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 tax-exempt organization in which any of our or
KMR's independent directors serves as an executive officer that in any single
fiscal year exceeded the greater of $1 million or 2% of such tax-exempt
organization's consolidated gross revenues.

  On September 3, 2004, our chief executive officer certified to the New York
Stock Exchange, as required by Section 303A.12(a) of the New York Stock Exchange
Listed Company Manual, that as of September 3, 2004, he was not aware of any
violation by us of the New York Stock Exchange's Corporate Governance listing
standards. We have also filed as an exhibit to this report the Sarbanes-Oxley
Act Section 302 certifications regarding the quality of our public disclosure.

  We make available free of charge within the "Investors" information section of
our Internet website, at www.kindermorgan.com, and in print to any unitholder
who requests, the governance guidelines, the charters of the audit committee,
compensation committee and nominating and governance committee, and our code of
business conduct and ethics (which applies to senior financial and accounting
officers and the chief executive officer, among others). Requests for copies may
be directed to Investor Relations, Kinder Morgan Energy Partners, L.P., 500
Dallas Street, Suite 1000, Houston, Texas 77002, or telephone (713) 369-9490. We
intend to disclose any amendments to our code of business conduct and ethics
that would otherwise be disclosed on Form 8-K and any waiver from a provision of
that code granted to our executive officers or directors that would otherwise be
disclosed on Form 8-K on our Internet website within 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, the chairpersons of any of the board's
committees, the independent directors as a group or the full board by mail to
Kinder Morgan Management, LLC, 500 Dallas Street, Suite 1000, Houston, Texas
77002, Attention: General Counsel, or by e-mail within the "Contact Us" section
of our Internet website, at www.kindermorgan.com. 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 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 2004.


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.

                                       88
<PAGE>

<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...........    2004     $      1  $     --   $       --           --       $    --
  Director, Chairman , CEO      2003            1        --           --           --            --
  and President                 2002            1        --           --           --            --

C. Park Shaper..............    2004      200,000   975,000           --           --         8,378
  Director, Executive Vice      2003      200,000   875,000    5,918,000           --         8,378
  President and CFO             2002      200,000   950,000           --      100,000(4)      8,336

Deborah A. Macdonald........    2004      200,000   975,000           --           --         8,966
  Vice President (President,    2003      200,000   875,000    5,380,000           --         8,966
  Natural Gas Pipelines)        2002      200,000   950,000           --       50,000(5)      8,966

Joseph Listengart...........    2004      200,000   875,000           --           --         8,378
  Vice President,               2003      200,000   825,000    3,766,000           --         8,378
  General Counsel and           2002      200,000   950,000           --           --         8,336
Secretary

Richard T. Bradley..........    2004      200,000   560,000           --           --         8,630
  Vice President (President,    2003      200,000   525,000    2,152,000           --         8,606
  CO2)                          2002      200,000   500,000           --           --         8,606
</TABLE>
----------

(1)  Amounts earned in year shown but paid the following year.

(2)  Represent shares of restricted KMI stock awarded in 2003. The 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.
     All of these hurdles have been met. The 2003 awards were long-term equity
     compensation for our current senior management through July 2008, and
     neither we nor KMI intend to make further restricted stock awards or other
     long-term equity grants to them before that date. The holders of the
     restricted stock awards are eligible to vote and to receive dividends
     declared on such shares.

(3)  Amounts represent value of contributions to the Kinder Morgan Savings Plan
     (a 401(k) plan), value of group-term life insurance exceeding $50,000 and
     taxable parking subsidy.

(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. The Kinder Morgan Savings Plan is a defined
contribution 401(k) plan. The plan permits all full-time employees of Kinder
Morgan, Inc. and KMGP Services Company, Inc. to contribute between 1% and 50% of
base compensation, on a pre-tax basis, into participant accounts. In addition to
a mandatory contribution equal to 4% of base compensation per year for most plan
participants, our general partner may make 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
2005, we will not make any discretionary contributions to individual accounts
for 2004.

                                       89
<PAGE>

For employees hired on or prior to December 31, 2004, all contributions,
together with earnings thereon, are immediately vested and not subject to
forfeiture. Employer contributions for employees hired on or after January 1,
2005 will vest on the second anniversary of the date of hire. 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.

   At its July 2004 meeting, the compensation committee of the KMI board of
directors approved that contingent upon its approval at its July 2005 meeting,
each eligible employee will receive an additional 1% company contribution based
on eligible base pay to his or her Savings Plan account each pay period
beginning with the first pay period after the July 2005 Committee meeting. The
1% contribution will be in the form of KMI common stock (the same as the current
4% contribution). The 1% contribution will be in addition to, and does not
change or otherwise impact, the annual 4% contribution that eligible employees
currently receive. It may be converted to any other Savings Plan investment fund
at any time and it will vest on the second anniversary of the employee's date of
hire. Since this additional 1% company contribution is discretionary,
compensation committee approval will be required annually for each contribution.

   Common Unit Option Plan. Pursuant to our Common Unit Option Plan, key
personnel are eligible to receive grants of options to acquire common units. The
total number of common units authorized under the option plan is 500,000. None
of the options granted under the option plan may be "incentive stock options"
under Section 422 of the Internal Revenue Code. If an option expires without
being exercised, the number of common units covered by such option will be
available for a future award. The exercise price for an option may not be less
than the fair market value of a common unit on the date of grant. KMR's
compensation committee administers the option plan, and the plan has a
termination date of March 5, 2008.

   No individual employee may be granted options for more than 20,000 common
units in any year. KMR's compensation committee will determine the duration and
vesting of the options to employees at the time of grant. As of December 31,
2004, options to purchase 95,400 common units are currently outstanding and held
by 30 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. As of December 31, 2004, all 95,400 outstanding options were fully
vested.

   The option plan also granted to each of our non-employee directors 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. Under this
provision, as of December 31, 2004, options to purchase 20,000 common units are
currently outstanding and held by 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. As of December 31, 2004, all 20,000 outstanding options were
fully vested.

   No options to purchase common units were granted during 2004 to any of the
individuals named in the Summary Compensation Table above. The following table
sets forth certain information as of December 31, 2004 and for the fiscal year
then ended 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 2004 and 2004 Year-End Common Unit Option Values

                                                             Number of Units             Value of Unexercised
                                                         Underlying Unexercised          In-the-Money Options
                     Units Acquired        Value        Options at 2004 Year-End                At 2004 Year-End
                                                     ---------------------------    ----------------------------
       Name            on Exercise       Realized      Exercisable   Unexercisable    Exercisable    Unexercisable
------------------   --------------    ----------    -------------  --------------  --------------  --------------
<S>                        <C>         <C>                   <C>             <C>                <C>              <C>
Joseph Listengart....      10,000      $  283,667            --              --                 --               --

</TABLE>

                                       90
<PAGE>

  KMI Stock Plan. Under KMI's stock 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 restricted KMI stock
and grants of options to acquire shares of common stock of KMI. The compensation
committee of KMI's board of directors administers this plan. The primary purpose
for granting restricted KMI stock and KMI 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 the 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 2004, none of the
persons named in the Summary Compensation Table above were granted KMI stock
options.
<TABLE>
<CAPTION>

                                                                      Number of Shares          Value of Unexercised
                                                                   Underlying Unexercised       In-the-Money Options
                                                                  Options at 2004 Year-End       at 2004 Year-End(1)
                                 Shares Acquired      Value    ---------------------------  ----------------------------
        Name                       on Exercise      Realized    Exercisable Unexercisable   Exercisable    Unexercisable
--------------------            ---------------    ----------  ---------------------------  -----------    -------------
<S>                                  <C>           <C>             <C>           <C>         <C>               <C>
C. Park Shaper..............              -        $        -      170,000       50,000      $5,984,475        $807,000
Deborah A. Macdonald........         50,000        $1,900,674       25,000       25,000      $  403,500        $403,500
Joseph Listengart...........         50,000        $1,843,154       56,300            -      $2,612,382               -
Richard T. Bradley..........         40,000        $1,284,830       25,000            -      $1,057,938               -
</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 also eligible to participate in a Cash Balance Retirement Plan. Certain
employees continue to accrue benefits through a career-pay formula,
"grandfathered" according to age and years of service on December 31, 2000, or
collective bargaining arrangements. All other employees accrue benefits through
a personal retirement account in the Cash Balance Retirement Plan. Employees
with prior service and not grandfathered converted to the Cash Balance
Retirement Plan on January 1, 2001, 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 3% of eligible compensation every pay period. In addition,
discretionary contributions are made to the plan based on our and KMI's
performance. No discretionary contributions were made for 2004 performance.
Interest is credited to the personal retirement accounts at the 30-year U.S.
Treasury bond rate, or an approved substitute, in effect each year. Employees
become fully vested in the plan after five years, and they may take a lump sum
distribution upon termination of employment or retirement.

   The following table sets forth the estimated annual benefits payable as of
December 31, 2004, 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, 2005       Plans        Retirement (1)
           ----              ------------    ------------   ------------   ------------     --------------
<S>                                <C>            <C>           <C>          <C>               <C>
Richard D. Kinder.........         4              8.8           60.2         $      1          $     -
C. Park Shaper............         4             32.7           36.4          200,000           62,363
Joseph Listengart.........         4             32.5           36.6          200,000           61,608
Deborah A. Macdonald......         4             15.9           53.1          200,000           15,763
Richard T. Bradley........         4             19.8           49.2          200,000           22,727
</TABLE>
----------

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

                                       91
<PAGE>


  2000 Annual Incentive Plan. Effective January 20, 2000, KMI established the
2000 Annual Incentive Plan of Kinder Morgan, Inc. The plan was established, in
part, to enable the portion of an officer's or other employee's annual bonus
based on objective performance criteria to qualify as "qualified performance-
based compensation" under the Internal Revenue Code. "Qualified performance-
based compensation" compensation is deductible for tax purposes. The plan
permits annual bonuses to be paid to KMI's officers and other employees and
employees of KMI's subsidiaries based on their individual performance, KMI's
performance and the performance of KMI's subsidiaries. The plan is administered
by the compensation committee of KMI's board of directors. Under the plan, at or
before the start of each calendar year, the compensation committee establishes
written performance objectives. The performance objectives are based on one or
more criteria set forth in the plan. The compensation committee may specify a
minimum acceptable level of achievement of each performance objective below
which no bonus is payable with respect to that objective. The maximum payout to
any individual under the plan in any year is $1.5 million, and the compensation
committee has the discretion to reduce the bonus amount in any performance
period. The cash bonuses set forth in the Summary Compensation Table above were
paid under the plan. Awards may be granted under the plan for calendar years
2000 through 2005.

   Compensation Committee Interlocks and Insider Participation. As disclosed
above, the compensation committee of KMR functions as our compensation
committee. KMR's compensation committee, comprised of Mr. Edward O. Gaylord, Mr.
Gary L. Hultquist and Mr. Perry M. Waughtal, makes compensation decisions
regarding the executive officers of our general partner and its delegate, KMR.
Mr. Richard D. Kinder 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. Our Directors' Unit Appreciation Rights Plan, as discussed
below, served as partial compensation for non-employee directors for 2004. In
addition to the awards provided by this plan, each non-employee director
received additional compensation of $10,000 in 2004, paid $2,500 per quarter.
Mr. Edward O. Gaylord, as chairman of the KMR audit committee, received
additional compensation in the amount of $10,000, paid $2,500 per quarter. Mr.
Perry M. Waughtal, appointed as lead director in October 2003 by KMR and who
served as lead director until December 2004, received additional compensation in
the amount of $25,000, paid $10,000 in the first quarter and $5,000 in each of
the last three quarters. In addition, directors are reimbursed for reasonable
expenses in connection with board meetings.

   In January 2005, KMR terminated the Directors' Unit Appreciation Rights Plan
and implemented the Kinder Morgan Energy Partners, L.P. Common Unit Compensation
Plan for Non-Employee Directors, as discussed below, to compensate non-employee
directors for 2005.

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

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

                                       92
<PAGE>

   On April 1, 2003, the date of adoption of the plan, each of KMR's three
non-employee directors were granted 7,500 unit appreciation rights. In addition,
10,000 unit appreciation rights were granted to each of KMR's three non-employee
directors on January 21, 2004, at the first meeting of the board in 2004. As of
December 31, 2004, 52,500 unit appreciation rights had been granted. No unit
appreciation rights were exercised during 2004. During the first board meeting
of 2005, the plan was terminated and replaced by the Kinder Morgan Energy
Partners, L.P. Common Unit Compensation Plan for Non-Employee Directors;
however, all unexercised awards made under the plan remain outstanding.

   Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for
Non-Employee Directors. On January 18, 2005, KMR's compensation committee
established the Kinder Morgan Energy Partners, L.P. Common Unit Compensation
Plan to compensate KMR's non-employee directors for 2005. The plan is
administered by KMR's compensation committee and KMR's board has sole discretion
to terminate the plan at any time. The primary purpose of this plan was to
promote our interests and the interests of our unitholders by aligning the
compensation of the non-employee members of the board of directors of KMR with
unitholders' interests. Further, since KMR's success is dependent on its
operation and management of our business and our resulting performance, the plan
is expected to align the compensation of the non-employee members of the board
with the interests of KMR's shareholders.

   The plan recognizes that the compensation to be paid to each non-employee
director is fixed by the KMR board, generally annually, and that the
compensation is expected to include an annual retainer payable in cash and other
cash compensation. Pursuant to the plan, in lieu of receiving the other cash
compensation, each non-employee director may elect to receive common units. Each
election shall be generally at or around the first board meeting in January of
each calendar year and will be effective for the entire calendar year. The
initial election under this plan was made effective January 20, 2005. A
non-employee director may make a new election each calendar year. The total
number of common units authorized under this compensation plan is 100,000.

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

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

  On January 18, 2005, the date of adoption of the plan, each of KMR's three
non-employee directors was awarded a cash retainer of $40,000 that will be paid
quarterly during 2005, and other cash compensation of $79,750. Effective January
20, 2005, each non-employe director elected to receive the other cash
compensation of $79,750 in the form of our common units and was issued 1,750
common units pursuant to the plan and its agreements (based on the $45.55
closing market price of our common units on January 18, 2005, as reported on the
New York Stock Exchange). Also, consistent with the plan, the $37.50 of other
cash compensation that did not equate to a whole

                                       93
<PAGE>

common unit, based on the January 18, 2005 $45.55 closing price, will be paid to
each of the non-employee directors as described above. No other compensation is
to be paid to the non-employee directors during 2005.


Item 12.  Security Ownership of Certain Beneficial Owners and Management.

   The following table sets forth information as of January 31, 2005, 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
5% 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.
<TABLE>
<CAPTION>

                                                                                        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>             <C>
Richard D. Kinder(6)...........        315,979        *            --        --         47,379         *    23,995,415      19.45%
C. Park Shaper(7)..............          4,000        *            --        --          2,534         *       326,808         *
Edward O. Gaylord(8)...........         34,750        *            --        --             --        --         2,000         *
Gary L. Hultquist(9)...........         11,750        *            --        --             --        --            --        --
Perry M. Waughtal(10)..........         39,050        *            --        --         37,594         *        50,000         *
Joseph Listengart(11)..........          4,198        *            --        --             --        --       140,106         *
Deborah A. Macdonald(12).......             --       --            --        --             --        --       121,374         *
Richard T. Bradley(13).........             --       --            --        --             --        --        71,314         *
Directors and Executive Officers
   as a group (12 persons)(14).        427,006        *            --        --         90,607         *    25,033,714      20.29%
Kinder Morgan, Inc.(15)........     14,355,735      9.73%   5,313,400   100.00%     13,293,298     24.55%           --         --
Fayez Sarofim(16)..............      7,888,871      5.35%          --        --             --        --            --         --
Capital Group International,                --        --           --        --      4,970,550      9.18%           --         --
Inc.(17).......................
OppenheimerFunds, Inc.(18).....             --        --           --        --      4,822,317      8.90%           --         --
Kayne Anderson Capital Advisors,
   L.P.(19)....................             --        --           --        --      3,816,642      7.05%           --         --
</TABLE>
----------

*  Less than 1%.

(1) Except as noted otherwise, all units, KMR shares and KMI shares involve sole
    voting power and sole investment power. For KMR, see note (4). On January
    18, 2005, KMR's board of directors initiated a rule requiring each director
    to own a minimum of 10,000 common units, KMR shares, or a combination
    thereof. If a director does not already own the minimum number of required
    securities, the director will have six years to acquire such securities.

(2) As of January 31, 2005, we had 147,555,658 common units issued and
    outstanding.

(3) As of January 31, 2005, we had 5,313,400 Class B units issued and
    outstanding.

(4) Represent the limited liability company shares of KMR. As of January 31,
    2005, there were 54,157,641 issued and outstanding KMR shares, including two
    voting shares owned by our general partner. In all cases, our i-units will
    be voted in proportion to the affirmative and negative votes, abstentions
    and non-votes of owners of KMR shares. Through the provisions in our
    partnership agreement and KMR's limited liability company agreement, the
    number of outstanding KMR shares, including voting shares owned by our
    general partner, and the number of our i-units will at all times be equal.

(5) As of January 31, 2005, KMI had a total of 123,378,197 shares of issued and
    outstanding voting common stock, which excludes 11,076,901 shares held in
    treasury.

(6) Includes (a) 7,879 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 195,000 KMI shares exercisable within 60 days
    of January 31, 2005, and includes 112,500 shares of restricted KMI stock.

                                       94
<PAGE>

(8)  Includes 1,750 restricted common units.

(9)  Includes options to purchase 10,000 common units exercisable within 60 days
     of January 31, 2005, and includes 1,750 restricted common units.

(10) Includes options to purchase 10,000 common units exercisable within 60 days
     of January 31, 2005, and includes 1,750 restricted common units.

(11) Includes options to purchase 56,300 KMI shares exercisable within 60 days
     of January 31, 2005, and includes 72,500 shares of restricted KMI stock.

(12) Includes 102,500 shares of restricted KMI stock.

(13) Includes options to purchase 20,000 KMI shares exercisable within 60 days
     of January 31, 2005, and includes 41,250 shares of restricted KMI stock.

(14) Includes options to purchase 24,000 common units and 433,300 KMI shares
     exercisable within 60 days of January 31, 2005, and includes 5,250
     restricted common units and 467,500 shares of restricted KMI stock.

(15) Includes common units owned by KMI and its consolidated subsidiaries,
     including 1,724,000 common units owned by Kinder Morgan G.P., Inc.

(16) As reported on the Schedule 13G/A filed February 11, 2005 by Fayez Sarofim
     & Co. and Fayez Sarofim. Mr. Sarofim reports that in regard to our common
     units, he has sole voting power over 2,300,000 common units, shared voting
     power over 4,242,612 common units, sole disposition power over 2,300,000
     common units and shared disposition power over 5,588,871 common units. Mr.
     Sarofim's address is 2907 Two Houston Center, Houston, Texas 77010.

(17) As reported on the Schedule 13G/A filed February 14, 2005 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 3,913,560 shares,
     shared voting power over 0 shares, sole disposition power over 4,970,550
     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.

(18) As reported on the Schedule 13G/A filed February 11, 2005 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 4,822,317
     shares. Of these 4,822,317 KMR shares, Oppenheimer Capital Income Fund has
     sole voting power over 3,232,500 shares, shared voting power over 0 shares,
     sole disposition power over 0 shares and shared disposition power over
     3,232,500 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.

(19) As reported on the Schedule 13G filed February 11, 2005 by Kayne Anderson
     Capital Advisors, L.P. and Richard A. Kayne. Kayne Anderson Capital
     Advisors, L.P. reports that in regard to KMR shares, it has sole voting
     power over 0 shares, shared voting power over 3,815,712 shares, sole
     disposition power over 0 shares and shared disposition power over 3,815,712
     shares. Mr. Anderson reports that in regard to KMR shares, he has sole
     voting power over 930 shares, shared voting power over 3,815,712 shares,
     sole disposition power over 930 shares and shared disposition power over
     3,815,712 shares. Kayne Anderson Capital Advisors, L.P. and Richard A.
     Kayne's address is 1800 Avenue of the Stars, Second Floor, Los Angeles,
     California 90067.

                      Equity Compensation Plan Information

   The following table sets forth information regarding our equity compensation
plans as of January 31, 2005. Specifically, the table refers to information
regarding our Common Unit Option Plan described in Item 11. "Executive
Compensation") as of January 31, 2005.

                                       95
<PAGE>

<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             95,900                  $18.0755                      55,400
                                               ------                                                ------

Total                                          95,900                                                55,400
                                               ======                                                ======
</TABLE>


Item 13.  Certain Relationships and Related Transactions.

   See Note 12 of the notes to our 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, 2004 and
2003 (in dollars):

                          Year Ended December 31,
                          -----------------------
                              2004        2003
                          ----------   ----------
Audit fees(1).............$2,147,000   $1,079,092
Audit-Related fees(2).....    34,000            -
Tax fees(3)............... 1,994,956    1,347,903
                           ---------    ---------
  Total...................$4,175,956   $2,426,995
                          ==========   ==========
----------

(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 for assurance and related services that are reasonably related
    to the performance of the audit or review of our financial statements.

(3) Includes fees related to professional services for tax compliance, tax
    advice and tax planning.

   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;

                                       96
<PAGE>

  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.

                                       97
<PAGE>


                                     PART IV

Item 15.  Exhibits and Financial Statement Schedules.

   (a)(1) and (2) Financial Statements and Financial Statement Schedules

   See "Index to Financial Statements" set forth on page 101.

   (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).
*3.2-- Amendment No. 1 dated November 19, 2004 to Third Amended and Restated
       Agreement of Limited Partnership of Kinder Morgan Energy Partners, L.P.
       (filed as Exhibit 99.1 to Kinder Morgan Energy Partners, L.P. Form 8-K
       filed November 22, 2004).
*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).

                                       98
<PAGE>

*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).
*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-- Indenture dated August 19, 2002 between Kinder Morgan Energy Partners,
        L.P. and Wachovia Bank, National Association, as Trustee (filed as
        Exhibit 4.1 to the Kinder Morgan Energy Partners, L.P. Registration
        Statement on Form S-4 (File No. 333-100346) filed on October 4, 2002
       (the "October 4, 2002 Form S-4")).
*4.18-- 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-- Senior Indenture dated January 31, 2003 between Kinder Morgan Energy
        Partners, L.P. and Wachovia Bank, National Association (filed as Exhibit
        4.2 to the Kinder Morgan Energy Partners, L.P. Registration Statement on
        Form S-3 (File No. 333-102961) filed on February 4, 2003 (the "February
        4, 2003 Form S-3")).
*4.21-- 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).
*4.22-- Subordinated Indenture dated January 31, 2003 between Kinder Morgan
        Energy Partners, L.P. and Wachovia Bank, National Association (filed as
        Exhibit 4.4 to the February 4, 2003 Form S-3).
*4.23-- 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).
*4.24-- Certificate of Vice President, Treasurer and Chief Financial Officer
        and Vice President, General Counsel and Secretary of Kinder Morgan
        Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan
        Energy Partners, L.P. establishing the terms of the 5.00% Notes due
        December 15, 2013 (filed as Exhibit 4.25 to Kinder Morgan Energy
        Partners, L.P. Form 10-K for 2003 filed March 5, 2004).
*4.25-- Specimen of 5.00% Notes due December 15, 2013 in book-entry form
        (filed as Exhibit 4.26 to Kinder Morgan Energy Partners, L.P. Form 10-K
        for 2003 filed March 5, 2004).
4.26--  Specimen of 5.125% Notes due November 15, 2014 in book-entry form.
4.27--  Certificate of Executive Vice President and Chief Financial Officer and
        Vice President, General Counsel and Secretary of Kinder Morgan
        Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan
        Energy Partners, L.P. establishing the terms of the 5.125% Notes
        due November 15, 2014.
4.28--  Certain instruments with respect to long-term debt of Kinder Morgan
        Energy Partners, L.P. and its consolidated subsidiaries which relate to
        debt that does not exceed 10% of the total assets of Kinder Morgan
        Energy Partners, L.P. and its consolidated subsidiaries are omitted
        pursuant to Item 601(b) (4) (iii) (A) of Regulation S-K, 17 C.F.R.
        sec.229.601.  Kinder Morgan Energy Partners, L.P. hereby agrees to
        furnish supplementally to the Securities and Exchange Commission a copy
        of each such instrument upon request.
*10.1-- Kinder Morgan Energy Partners, L.P. Common Unit Option Plan (filed as
        Exhibit 10.6 to the Kinder Morgan Energy Partners, L.P. 1997 Form 10-K,
        File No. 1-11234).
*10.2-- Delegation of Control Agreement among Kinder Morgan Management, LLC,
        Kinder Morgan G.P., Inc. and Kinder Morgan Energy Partners, L.P. and its
        operating partnerships (filed as Exhibit 10.1 to the Kinder Morgan
        Energy Partners, L.P. Form 10-Q for the quarter ended June 30, 2001).
*10.3-- Kinder Morgan Energy Partners, L.P. Directors' Unit Appreciation Rights
        Plan (filed as Exhibit 10.6 to the Kinder Morgan Energy Partners, L.P.
        Form 10-K for 2003 filed March 5, 2004).
*10.4-- Amendment No. 1 to Kinder Morgan Energy Partners, L.P. Directors' Unit
        Appreciation Rights Plan (filed as Exhibit 10.7 to the Kinder Morgan
        Energy Partners, L.P. Form 10-K for 2003 filed March 5, 2004).

                                       99
<PAGE>

*10.5-- Resignation and Non-Compete agreement dated July 21, 2004
        between KMGP Services, Inc. and Michael C. Morgan,
        President of Kinder Morgan, Inc., Kinder Morgan G.P., Inc.
        and Kinder Morgan Management, LLC (filed as Exhibit 10.1 to
        the Kinder Morgan Energy Partners, L.P. Form 10-Q for the
        quarter ended June 30, 2004, filed on August 5, 2004).
*10.6-- 5-Year Credit Agreement dated as of August 18, 2004 among Kinder
        Morgan Energy Partners, L.P., the lenders party thereto and Wachovia
        Bank, National Association as Administrative Agent (filed as Exhibit
        10.1 to Kinder Morgan Energy Partners, L.P. Form 10-Q for the quarter
        ended September 30, 2004, filed November 2, 2004).
*10.7-- Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for
        Non-Employee Directors (filed as Exhibit 10.2 to Kinder Morgan Energy
        Partners, L.P. Form 8-K filed January 21, 2005).
*10.8-- Form of Common Unit Compensation Agreement entered into with
        Non-Employee Directors (filed as Exhibit 10.1 to Kinder Morgan Energy
        Partners, L.P. Form 8-K filed January 21, 2005).
11.1--  Statement re: computation of per share earnings.
21.1--  List of Subsidiaries.
23.1--  Consent of PricewaterhouseCoopers LLP.
23.2--  Consent of Netherland, Sewell and Associates, Inc.
31.1--  Certification by CEO pursuant to Rule 13a-14(a) or
        15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to
        Section 302 of the Sarbanes-Oxley Act of 2002.
31.2--  Certification by CFO pursuant to Rule 13a-14(a) or 15d-14(a) of the
        Securities Exchange Act of 1934, as adopted pursuant to Section 302 of
        the Sarbanes-Oxley Act of 2002.
32.1--  Certification by CEO pursuant to 18 U.S.C. Section 1350, as adopted
        pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2--  Certification by CFO pursuant to 18 U.S.C. Section 1350, as adopted
        pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
----------

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

                                      100

<PAGE>


                          INDEX TO FINANCIAL STATEMENTS



                                                                           Page
                                                                          Number
                                                                          ------
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

Report of Independent Registered Public Accounting Firm.................   102


Consolidated  Statements of Income for the years ended  December 31,
2004, 2003, and 2002....................................................   103


Consolidated  Statements of Comprehensive Income for the years ended
December 31, 2004, 2003, and 2002.......................................   104


Consolidated Balance Sheets as of December 31, 2004 and 2003............   105


Consolidated  Statements of Cash Flows for the years ended  December
31, 2004, 2003, and 2002................................................   106


Consolidated  Statements  of  Partners'  Capital for the years ended
December 31, 2004, 2003, and 2002.......................................   107


Notes to Consolidated Financial Statements..............................   108



                                      101
<PAGE>


             Report of Independent Registered Public Accounting Firm


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

We have completed an integrated audit of Kinder Morgan Energy Partners, L.P.'s
(the Partnership) 2004 consolidated financial statements and of its internal
control over financial reporting as of December 31, 2004 and audits of its 2003
and 2002 consolidated financial statements in accordance with the standards of
the Public Company Accounting Oversight Board (United States). Our opinions,
based on our audits, are presented below.

Consolidated financial statements
---------------------------------

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 at December 31, 2004 and 2003,
and the results of their operations and their cash flows for each of the three
years in the period ended December 31, 2004 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 the
standards of the Public Company Accounting Oversight Board (United States).
Those standards require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit of financial statements 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.

Internal control over financial reporting
-----------------------------------------

Also, in our opinion, management's assessment, included in Management's Report
on Internal Control Over Financial Reporting appearing under Item 9A, that the
Partnership maintained effective internal control over financial reporting as of
December 31, 2004 based on criteria established in Internal Control --
Integrated Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO), is fairly stated, in all material respects, based on
those criteria. Furthermore, in our opinion, the Partnership maintained, in all
material respects, effective internal control over financial reporting as of
December 31, 2004, based on criteria established in Internal Control --
Integrated Framework issued by the COSO. The Partnership's management is
responsible for maintaining effective internal control over financial reporting
and for its assessment of the effectiveness of internal control over financial
reporting. Our responsibility is to express opinions on management's assessment
and on the effectiveness of the Partnership's internal control over financial
reporting based on our audit. We conducted our audit of internal control over
financial reporting in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether effective
internal control over financial reporting was maintained in all material
respects. An audit of internal control over financial reporting includes
obtaining an understanding of internal control over financial reporting,
evaluating management's assessment, testing and evaluating the design and
operating effectiveness of internal control, and performing such other
procedures as we consider necessary in the circumstances. We believe that our
audit provides a reasonable basis for our opinions.

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

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

As described in Management's Report on Internal Control Over Financial
Reporting, management has excluded North Charleston Bulk Terminal, Kinder Morgan
Wink Pipeline, L.P., Kinder Morgan River Terminals LLC, Charter Products
Terminals and Kinder Morgan Fairless Hills Terminal from its assessment of
internal control over financial reporting as of December 31, 2004 because these
businesses were acquired by the Partnership in purchase business combinations
during 2004. We have also excluded North Charleston Bulk Terminal, Kinder Morgan
Wink Pipeline, L.P., Kinder Morgan River Terminals LLC, Charter Products
Terminals and Kinder Morgan Fairless Hills Terminal from our audit of internal
control over financial reporting. These businesses, in the aggregate,
constituted .04% of the Partnership's consolidated revenues for 2004 and 2.75%
of the Partnership's consolidated assets at December 31, 2004.



PricewaterhouseCoopers LLP

Houston, Texas
March 3, 2004


                                      102
<PAGE>



<TABLE>
<CAPTION>
                              KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

                                        CONSOLIDATED STATEMENTS OF INCOME

                                                                                Year Ended December 31,
                                                                       --------------------------------------
                                                                          2004          2003          2002
                                                                       ----------    ----------    ----------
                                                                       (In thousands except per unit amounts)
Revenues
<S>                                                                    <C>           <C>           <C>
  Natural gas sales...............................................     $5,803,065    $4,889,235    $2,740,518
  Services........................................................      1,571,504     1,377,745     1,272,640
  Product sales and other.........................................        558,292       357,342       223,899
                                                                       ----------    ----------    ----------
                                                                        7,932,861     6,624,322     4,237,057
                                                                       ----------    ----------    ----------
Costs and Expenses
  Gas purchases and other costs of sales..........................      5,767,169     4,880,118     2,704,295
  Operations and maintenance......................................        499,714       397,723       376,479
  Fuel and power..................................................        151,480       108,112        86,413
  Depreciation and amortization...................................        288,626       219,032       172,041
  General and administrative......................................        170,507       150,435       122,205
  Taxes, other than income taxes..................................         81,369        62,213        51,326
                                                                       ----------    ----------    ----------
                                                                        6,958,865     5,817,633     3,512,759
                                                                       ----------    ----------    ----------

Operating Income..................................................        973,996       806,689       724,298

Other Income (Expense)
  Earnings from equity investments................................         83,190        92,199        89,258
  Amortization of excess cost of equity investments...............         (5,575)       (5,575)       (5,575)
  Interest, net...................................................       (192,882)     (181,357)     (176,460)
  Other, net......................................................          2,254         7,601         1,698
Minority Interest.................................................         (9,679)       (9,054)       (9,559)
                                                                       ----------    ----------    ----------

Income Before Income Taxes and Cumulative Effect of a Change in
  Accounting Principle ...........................................        851,304       710,503       623,660

Income Taxes......................................................         19,726        16,631        15,283
                                                                       ----------    ----------    ----------

Income Before Cumulative Effect of a Change in Accounting Principle       831,578       693,872       608,377

Cumulative effect adjustment from change in accounting for asset
  retirement obligations..........................................              -         3,465             -
                                                                       ----------    ----------    ----------

Net Income........................................................     $  831,578    $  697,337    $  608,377
                                                                       ==========    ==========    ==========

Calculation of Limited Partners' Interest in Net Income:
  Income  Before   Cumulative  Effect  of  a  Change  in  Accounting   $  831,578    $  693,872    $  608,377
Principle.........................................................
  Less: General Partner's interest................................       (395,092)     (326,489)     (270,816)
                                                                       ----------    ----------    ----------
  Limited Partners' interest......................................        436,486       367,383       337,561
  Add: Limited Partners' interest in Change in Accounting Principle             -         3,430             -
                                                                       ----------    ----------    ----------
  Limited Partners' interest in Net Income........................     $  436,486    $  370,813    $  337,561
                                                                       ==========    ==========    ==========

Basic and Diluted Limited Partners' Net Income per Unit:
  Income  Before   Cumulative  Effect  of  a  Change  in  Accounting   $     2.22    $     1.98    $     1.96
Principle.........................................................
  Cumulative effect adjustment from change in accounting for asset
    retirement obligations........................................              -          0.02             -
                                                                       ----------    ----------    ----------
  Net Income......................................................     $     2.22    $     2.00    $     1.96
                                                                       ==========    ===========   ==========

Weighted average number of units used in computation of Limited
  Partners' Net Income per Unit:
Basic.............................................................        196,956       185,384       172,017
                                                                       ==========    ==========    ==========

Diluted...........................................................        197,038       185,494       172,186
                                                                       ==========    ==========    ==========
</TABLE>

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

                                      103
<PAGE>



       KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

          CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

<TABLE>
<CAPTION>
                                                                         Year Ended December 31,
                                                                      2004       2003        2002
                                                                   ---------- ----------  -------
                                                                            (In thousands)

<S>                                                                <C>        <C>         <C>
  Net Income..................................................     $ 831,578  $ 697,337   $ 608,377
  Foreign currency translation adjustments....................           375         --          --
  Change in fair value of derivatives
     used for hedging purposes................................      (494,212)  (192,618)   (116,560)
  Reclassification of change in fair value of derivatives to net
     income...................................................       192,304     82,065       7,477
                                                                   ---------  ---------   ---------

  Comprehensive Income........................................     $ 530,045  $ 586,784   $ 499,294
                                                                   =========  =========   =========
</TABLE>

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

                                      104
<PAGE>


                   KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

                              CONSOLIDATED BALANCE SHEETS

<TABLE>
<CAPTION>
                                                                     December 31,
                                                                   2004          2003
                                                               -----------   --------
                                    ASSETS                       (Dollars in thousands)

Current Assets
<S>                                                             <C>           <C>
  Cash and cash equivalents................................     $         -   $   23,329
  Accounts, notes and interest receivable, net
     Trade.................................................         739,798      563,012
     Related parties.......................................          12,482       27,587
  Inventories
     Products..............................................          17,868        7,214
     Materials and supplies................................          11,345       10,783
  Gas imbalances
     Trade.................................................          24,653       36,449
     Related parties.......................................             980        9,084
  Gas in underground storage...............................               -        8,160
  Other current assets.....................................          46,045       19,904
                                                                -----------   ----------
                                                                    853,171      705,522
Property, Plant and Equipment, net.........................       8,168,680    7,091,558
Investments................................................         413,255      404,345
Notes receivable
  Trade....................................................           1,944        2,422
  Related parties..........................................         111,225            -
Goodwill...................................................         732,838      729,510
Other intangibles, net.....................................          15,284       13,202
Deferred charges and other assets..........................         256,545      192,623
                                                                -----------   ----------
Total Assets...............................................     $10,552,942   $9,139,182
                                                                ===========   ==========

                       LIABILITIES AND PARTNERS' CAPITAL
Current Liabilities
  Accounts payable
     Cash book overdrafts..................................     $    29,866   $        -
     Trade.................................................         685,034      477,783
     Related parties.......................................          16,650            -
  Current portion of long-term debt........................               -        2,248
  Accrued interest.........................................          56,930       52,356
  Accrued taxes............................................          26,435       20,857
  Deferred revenues........................................           7,825       10,752
  Gas imbalances...........................................          32,452       49,912
  Accrued other current liabilities........................         325,663      190,471
                                                                -----------   ----------
                                                                  1,180,855      804,379
Long-Term Liabilities and Deferred Credits
  Long-term debt
     Outstanding...........................................       4,722,410    4,316,678
     Market value of interest rate swaps...................         130,153      121,464
                                                                -----------   ----------
                                                                  4,852,563    4,438,142
  Deferred revenues........................................          14,680       20,975
  Deferred income taxes....................................          56,487       38,106
  Asset retirement obligations.............................          37,464       34,898
  Other long-term liabilities and deferred credits.........         468,727      251,691
                                                                -----------   ----------
                                                                  5,429,921    4,783,812
Commitments and Contingencies (Notes 13 and 16)
Minority Interest..........................................          45,646       40,064
                                                                -----------   ----------
Partners' Capital
  Common Units (147,537,908 and 134,729,258 units issued and
     outstanding as of December 31, 2004 and 2003,
     respectively).........................................       2,438,011    1,946,116
  Class B Units (5,313,400 and 5,313,400 units issued and
     outstanding as of December 31, 2004 and 2003,
     respectively).........................................         117,414      120,582
  i-Units (54,157,641 and 48,996,465 units issued and
      outstanding as of December 31, 2004 and 2003,
      respectively)........................................       1,694,971    1,515,659
  General Partner..........................................         103,467       84,380
  Accumulated other comprehensive loss.....................        (457,343)    (155,810)
                                                                -----------   ----------
                                                                  3,896,520    3,510,927
Total Liabilities and Partners' Capital....................     $10,552,942   $9,139,182
                                                                ===========   ==========
</TABLE>

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

                                      105
<PAGE>


                      KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

                              CONSOLIDATED STATEMENTS OF CASH FLOWS

<TABLE>
<CAPTION>
                                                                        Year Ended December 31,
                                                               ---------------------------------------
                                                                    2004          2003          2002
                                                               -----------   -----------   -----------
                                                                           (In thousands)
Cash Flows From Operating Activities
<S>                                                            <C>           <C>           <C>
  Net income................................................   $   831,578   $   697,337   $   608,377
  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................       288,626       219,032       172,041
    Amortization of excess cost of equity investments.......         5,575         5,575         5,575
    Earnings from equity investments........................       (83,190)      (92,199)      (89,258)
  Distributions from equity investments.....................        65,248        83,000        77,735
  Changes in components of working capital:
    Accounts receivable.....................................      (172,393)     (180,632)     (177,240)
    Other current assets....................................        26,175        (1,858)       (7,583)
    Inventories.............................................        (7,353)       (2,945)       (1,713)
    Accounts payable........................................       222,377        92,702       288,712
    Accrued liabilities.....................................       (18,482)        9,740        26,132
    Accrued taxes...........................................         3,444        (4,904)        2,379
  FERC rate reparations and refunds.........................             --      (44,944)           --
  Other, net................................................        (6,497)       (7,923)      (35,462)
                                                               -----------   -----------   -----------
Net Cash Provided by Operating Activities...................     1,155,108       768,516       869,695
                                                               -----------   -----------   -----------

Cash Flows From Investing Activities
  Acquisitions of assets....................................      (478,830)     (349,867)     (908,511)
  Additions  to  property,  plant and equip.
   for  expansion  and  maintenance projects................      (747,262)     (576,979)     (542,235)
  Sale of investments, property, plant and equipment,
   net of removal costs.....................................         1,069         2,090        13,912
  Acquisitions of investments...............................        (1,098)      (10,000)       (1,785)
  Contributions to equity investments.......................        (7,010)      (14,052)      (10,841)
  Natural gas stored underground and
   natural gas liquids line-fill............................       (19,189)        5,459          (884)
  Other.....................................................         1,810           288          (536)
                                                               -----------   -----------   -----------
Net Cash Used in Investing Activities.......................    (1,250,510)     (943,061)   (1,450,880)
                                                               -----------   -----------   -----------

Cash Flows From Financing Activities
  Issuance of debt..........................................     6,016,670     4,674,605     3,803,414
  Payment of debt...........................................    (5,657,566)   (4,014,296)   (2,985,322)
  Loans to related party....................................       (96,271)           --            --
  Debt issue costs..........................................        (5,843)       (5,204)      (17,006)
  Increase in cash book overdrafts..........................        29,866            --            --
  Proceeds from issuance of common units....................       506,520       175,567         1,586
  Proceeds from issuance of i-units.........................        67,528            --       331,159
  Contributions from General Partner........................         7,956         4,181         3,353
  Distributions to partners:
    Common units............................................      (389,912)     (340,927)     (306,590)
    Class B units...........................................       (14,931)      (13,682)      (12,540)
    General Partner.........................................      (376,005)     (314,244)     (253,344)
    Minority interest.......................................       (10,117)      (10,445)       (9,668)
  Other, net................................................        (5,822)        1,231         4,429
                                                               ------------  -----------   -----------
Net Cash Provided by Financing Activities...................        72,073       156,786       559,471
                                                               -----------   -----------   -----------

Decrease in Cash and Cash Equivalents.......................       (23,329)      (17,759)      (21,714)
Cash and Cash Equivalents, beginning of period..............        23,329        41,088        62,802
                                                               -----------   -----------   -----------
Cash and Cash Equivalents, end of period....................   $        --   $    23,329   $    41,088
                                                               ===========   ===========   ===========

Noncash Investing and Financing Activities:
  Assets acquired by the issuance of units..................    $   64,050    $    2,000    $        --
  Assets acquired by the assumption of liabilities..........        81,403        36,187       213,861
Supplemental disclosures of cash flow information:
  Cash paid (received) during the year for
  Interest (net of capitalized interest)....................       193,247       183,908       161,840
  Income taxes..............................................          (752)         (261)        1,464
</TABLE>

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


                                      106
<PAGE>


              KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

                  CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL

<TABLE>
<CAPTION>
<S>                                         <C>          <C>            <C>          <C>          <C>           <C>


                                                      2004                      2003                       2002
                                            ------------------------    -------------------------       ------------------------
                                                Units        Amount        Units        Amount           Units        Amount
                                            -----------  -----------    ------------  -----------      -----------   -----------
                                                                        (Dollars in thousands)
Common Units:
  Beginning Balance.....................    134,729,258  $ 1,946,116    129,943,218  $ 1,844,553       129,855,018   $ 1,894,677
  Net income............................             --      311,237             --      265,423                --       254,934
Units issued as consideration in the
    acquisition of assets...............      1,400,000       64,050         51,490        2,000                --            --
  Units issued for cash.................     11,408,650      506,520      4,734,550      175,067            88,200         1,532
  Distributions.........................             --     (389,912)            --     (340,927)               --      (306,590)
                                            -----------  -----------    -----------   -----------      -----------   -----------
  Ending Balance........................    147,537,908    2,438,011    134,729,258    1,946,116       129,943,218     1,844,553

Class B Units:
  Beginning Balance.....................      5,313,400      120,582      5,313,400      123,635         5,313,400       125,750
  Net income............................             --       11,763             --       10,629                --        10,427
  Units issued for cash.................             --           --             --           --                --            (2)
  Distributions.........................             --      (14,931)            --      (13,682)               --       (12,540)
                                            -----------  -----------    -----------   -----------      -----------   -----------
  Ending Balance........................      5,313,400      117,414      5,313,400      120,582         5,313,400       123,635

i-Units:
  Beginning Balance.....................     48,996,465    1,515,659     45,654,048    1,420,898        30,636,363     1,020,153
  Net income............................             --      113,486             --       94,761                --        72,200
  Units issued for cash.................      1,660,664       65,826             --           --        12,478,900       328,545
  Distributions.........................      3,500,512           --      3,342,417           --         2,538,785            --
                                            -----------  -----------    -----------   -----------      -----------   -----------
  Ending Balance........................     54,157,641    1,694,971     48,996,465    1,515,659        45,654,048     1,420,898

General Partner:
  Beginning Balance.....................             --       84,380             --       72,100                --        54,628
  Net income............................             --      395,092             --      326,524                --       270,816
  Units issued for cash.................             --           --             --           --                --            --
  Distributions.........................             --     (376,005)            --     (314,244)               --      (253,344)
                                            ------------ ------------   -----------   -----------      -----------   ------------
  Ending Balance........................             --      103,467             --       84,380                --        72,100

Accum. other comprehensive income (loss):
  Beginning Balance.....................             --     (155,810)            --      (45,257)               --        63,826
  Foreign currency translation adjustments           --          375             --           --                --            --
  Change in fair value of derivatives
    used for hedging purposes...........             --     (494,212)            --     (192,618)               --      (116,560)
  Reclassification of change in fair
    value of derivatives to net income..             --      192,304             --       82,065                --         7,477
                                            ------------  -----------  ------------   -----------      ------------  ------------
  Ending Balance........................             --     (457,343)            --     (155,810)               --       (45,257)

Total Partners' Capital.................    207,008,949  $ 3,896,520    189,039,123  $ 3,510,927       180,910,666   $ 3,415,929
                                            ===========  ===========   ============  ============      ===========   ============
</TABLE>


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


                                      107


<PAGE>


              KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1.   Organization

     General

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

     We own and manage a diversified portfolio of energy transportation and
storage assets. 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, commonly called
          CO2, 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
near-term commodity price risks and taking advantage of the tax benefits of a
limited partnership structure. We trade on the New York Stock Exchange under the
symbol "KMP" and presently conduct our business through four reportable business
segments:

     o    Products Pipelines;

     o    Natural Gas Pipelines;

     o    CO2; and

     o    Terminals.

     For more information on our reportable business segments, see Note 15.

     Kinder Morgan, Inc.

     Kinder Morgan, Inc., a Kansas corporation, is the sole stockholder of
Kinder Morgan (Delaware), Inc. Kinder Morgan (Delaware), Inc., a Delaware
corporation, is the sole stockholder of our general partner, Kinder Morgan G.P.,
Inc. Kinder Morgan, Inc. is referred to as "KMI" in this report. 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 135 terminals. At December 31, 2004, KMI
and its consolidated subsidiaries owned, through its general and limited partner
interests, an approximate 18.5% interest in us.

     Kinder Morgan Management, LLC

     Kinder Morgan Management, LLC, a Delaware limited liability company, was
formed on February 14, 2001. It is referred to as "KMR" in this report. Our
general partner owns all of KMR's voting securities and, pursuant to a
delegation of control agreement, our general partner has delegated to KMR, to
the fullest extent permitted under Delaware law and our partnership agreement,
all of its power and authority to manage and control our business and


                                      108


<PAGE>


affairs, except that KMR cannot take certain specified actions without the
approval of our general partner. Under the delegation of control agreement, KMR
manages and controls our business and affairs and the business and affairs of
our operating limited partnerships and their subsidiaries. Furthermore, in
accordance with its limited liability company agreement, KMR's activities are
limited to being a limited partner in, and managing and controlling the business
and affairs of us, our operating limited partnerships and their subsidiaries. As
of December 31, 2004, KMR owned approximately 26.2% of our outstanding limited
partner units (which are in the form of i-units that are issued only to KMR).


2.   Summary of Significant Accounting Policies

     Basis of Presentation

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

     Our consolidated financial statements were prepared in accordance with
accounting principles generally accepted in the United States. Certain amounts
included in or affecting our financial statements and related disclosures must
be estimated by management, requiring us to make certain assumptions with
respect to values or conditions which 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.

     Therefore, the reported amounts of our assets and liabilities and
associated disclosures with respect to contingent assets and obligations are
necessarily affected by these estimates. 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 are of more significance in our financial statement
preparation process than others.

     Cash Equivalents

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

     Accounts Receivables

     Our policy for determining an appropriate allowance for doubtful accounts
varies according to the type of business being conducted and the customers being
served. An allowance for doubtful accounts is charged to expense monthly,
generally using a percentage of revenue or receivables, based on a historical
analysis of uncollected amounts, adjusted as necessary for changed circumstances
and customer-specific information. When specific receivables are determined to
be uncollectible, the reserve and receivable are relieved. The following tables
show the balance in the allowance for doubtful accounts and activity for the
years ended December 31, 2004, 2003 and 2002.


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<PAGE>


                        Valuation and Qualifying Accounts
                                 (in thousands)
<TABLE>
<CAPTION>
<S>                                     <C>              <C>               <C>                 <C>             <C>

                                      Balance at        Additions         Additions                          Balance at
                                     beginning of   charged to costs  charged to other                         end of
Allowance for Doubtful Accounts         Period        and expenses       accounts(1)        Deductions(2)      period
--------------------------------     ------------   ----------------  -----------------  -----------------  -----------

Year ended December 31, 2004....        $8,783           $1,460            $  431              $(2,052)        $8,622

Year ended December 31, 2003....        $8,092           $1,448            $    -              $  (757)        $8,783

Year ended December 31, 2002....        $7,556           $  822            $    4              $  (290)        $8,092

</TABLE>


__________

(1)  Amount for 2004 represents the allowance recognized when we acquired Kinder
     Morgan River Terminals LLC and Consolidated Subsidiaries ($393) and
     TransColorado Gas Transmission Company ($38). Amount for 2002 represents
     the allowance recognized when we acquired IC Terminal Holdings Company and
     Consolidated Subsidiaries.

(2)  Deductions represent the write-off of receivables.

     In addition, the balances of "Accrued other current liabilities" in our
accompanying consolidated balance sheets include amounts related to customer
prepayments of approximately $5.1 million as of December 31, 2004 and $8.2
million as of December 31, 2003.

     Inventories

     Our inventories of products consist of natural gas liquids, refined
petroleum products, natural gas, carbon dioxide and coal. We report these assets
at the lower of weighted-average cost or market. We report materials and
supplies at the lower of cost or market.

     Property, Plant and Equipment

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

     We compute depreciation using the straight-line method based on estimated
economic lives. Generally, we apply composite depreciation rates to functional
groups of property having similar economic characteristics. The rates range from
2.0% to 12.5%, excluding certain short-lived assets such as vehicles. In
practice, the composite life may not be determined with a high degree of
precision, and hence the composite life may not reflect the weighted average of
the expected useful lives of the asset's principal components.

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

     A gain on the sale of property, plant and equipment used in our oil and gas
producing activities is calculated as the difference between the cost of the
asset disposed of, net of depreciation, and the sales proceeds received. A gain
on an asset disposal is recognized in income in the period that the sale is
closed. A loss on the sale of property,


                                      110


<PAGE>


plant and equipment is calculated as the difference between the cost of the
asset disposed of, net of depreciation, and the sales proceeds received or the
maket value if the asset is being held for sale. A loss is recognized when the
asset is sold or when the net cost of an asset held for sale is greater than the
market value of the asset.

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

     We review for the impairment of long-lived assets whenever events or
changes in circumstances indicate that our carrying amount of an asset may not
be recoverable. We would recognize an impairment loss when estimated future cash
flows expected to result from our use of the asset and its eventual disposition
is less than its carrying amount.

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

     On January 1, 2002, we adopted Statement of Financial Accounting Standards
No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" and we
now evaluate the impairment of our long-lived assets in accordance with this
Statement. This Statement retains the requirements of SFAS No. 121, "Accounting
for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed
Of," however, this Statement requires that long-lived assets that are to be
disposed of by sale be measured at the lower of book value or fair value less
the cost to sell. Furthermore, the scope of discontinued operations is expanded
to include all components of an entity with operations of the entity in a
disposal transaction. The adoption of SFAS No. 144 has not had an impact on our
business, financial position or results of operations.

     Equity Method of Accounting

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

     Excess of Cost Over Fair Value

     Effective January 1, 2002, we adopted SFAS No. 141, "Business Combinations"
and SFAS No. 142, "Goodwill and Other Intangible Assets." SFAS No. 141
supercedes Accounting Principles Board Opinion No. 16 and requires that all
transactions fitting the description of a business combination be accounted for
using the purchase method and prohibits the use of the pooling of interests for
all business combinations initiated after June 30, 2001. The Statement also
modifies the accounting for the excess of cost over the fair value of net assets
acquired as well as intangible assets acquired in a business combination. The
provisions of this Statement apply to all business combinations initiated after
June 30, 2001, and all business combinations accounted for by the purchase
method that are completed after July 1, 2001. In addition, this Statement
requires disclosure of the primary reasons for a business combination and the
allocation of the purchase price paid to the assets acquired and liabilities
assumed by major balance sheet caption.

     SFAS No. 142 supercedes Accounting Principles Board Opinion No. 17 and
requires that goodwill no longer be amortized, but instead should be tested, at
least on an annual basis, for impairment. A benchmark assessment of potential
impairment was required to be completed within six months of adopting SFAS No.
142. After the first six months, goodwill must be tested for impairment annually
or as changes in circumstances require. Other intangible assets are to be
amortized over their useful life and reviewed for impairment in accordance with
the provisions of SFAS No. 144, "Accounting for the Impairment or Disposal of
Long-Lived Assets." An intangible asset with an indefinite useful life can no
longer be amortized until its useful life becomes determinable. In addition,
this Statement requires disclosure of information about goodwill and other
intangible assets in the years subsequent to their acquisition that was not
previously required. Required disclosures include information about the changes
in the carrying amount of goodwill from period to period and the carrying amount
of intangible assets by major intangible asset class.


                                      111


<PAGE>


     These accounting pronouncements required that, beginning with their
implementation, we prospectively cease amortization of all intangible assets
having indefinite useful economic lives. Such assets, including goodwill, are
not to be amortized until their lives are determined to be finite. 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 the
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, 2005.

     Our total unamortized excess cost over fair value of net assets in
consolidated affiliates was approximately $732.8 million as of December 31, 2004
and $729.5 million as of December 31, 2003. Such amounts are reported as
"Goodwill" on our accompanying consolidated balance sheets. Our total
unamortized excess cost over underlying fair value of net assets accounted for
under the equity method was approximately $150.3 million as of both December 31,
2004, and December 31, 2003. Pursuant to SFAS No. 142, this amount, referred to
as equity method goodwill, should continue to be recognized in accordance with
Accounting Principles Board Opinion No. 18, "The Equity Method of Accounting for
Investments in Common Stock." Accordingly, we included this amount within
"Investments" on our accompanying consolidated balance sheets. In addition,
approximately $184.2 million and $189.7 million at December 31 2004 and 2003,
respectively, representing the excess of the fair market value of property,
plant and equipment over its book value at the date of acquisition was included
within "Investments" on our accompanying consolidated balance sheets and was
being amortized over a weighted average life of approximately 33.6 years.

     In addition to our annual impairment test of goodwill, we periodically
reevaluate the amount at which we carry the excess of cost over fair value of
net assets of businesses we acquired, as well as the amortization period for
such assets, to determine whether current events or circumstances warrant
adjustments to our carrying value and/or revised estimates of useful lives in
accordance with APB Opinion No. 18. The impairment test under APB No. 18
considers whether the fair value of the equity investment as a whole, not the
underlying net assets, has declined and whether that decline is other than
temporary. As of December 31, 2004, we believed no such impairment had occurred
and no reduction in estimated useful lives was warranted.

     For more information on our acquisitions, see Note 3. For more information
on our investments, see Note 7.

     Revenue Recognition

     We recognize revenues for our pipeline operations based on delivery of
actual volume transported or minimum obligations under take-or-pay contracts. We
recognize bulk terminal transfer service revenues based on volumes loaded. We
recognize liquids terminal tank rental revenue ratably over the contract period.
We recognize liquids terminal through-put revenue based on volumes received or
volumes delivered depending on the customer contract. Liquids terminal minimum
take-or-pay revenue is recognized at the end of the contract year or contract
term depending on the terms of the contract. We recognize transmix processing
revenues based on volumes processed or sold, and if applicable, when title has
passed. We recognize energy-related product sales revenues based on delivered
quantities of product.

     Revenues from the sale of oil and natural gas liquids production are
recorded using the entitlement method. Under the entitlement method, revenue is
recorded when title passes based on our net interest. We record our entitled
share of revenues based on entitled volumes and contracted sales prices.
Revenues from the sale of natural gas production are recognized when the natural
gas is sold. Since there is a ready market for oil and gas production, we sell
the majority of our products soon after production at various locations, at
which time title and risk of loss pass to the buyer. As a result, we maintain a
minimum amount of product inventory in storage and the differences between
actual production and sales is not significant.

     Capitalized Interest

     We capitalize interest expense during the construction or upgrade of
qualifying assets. Interest expense capitalized in 2004, 2003 and 2002 was $6.4
million, $5.3 million and $5.8 million, respectively.


                                      112



<PAGE>


     Unit-Based Compensation

     SFAS No. 123, "Accounting for Stock-Based Compensation," as amended by SFAS
No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure,"
encourages, but does not require, entities to adopt the fair value method of
accounting for stock or unit-based compensation plans. As allowed under SFAS No.
123, we apply APB Opinion No. 25, "Accounting for Stock Issued to Employees,"
and related interpretations in accounting for common unit options granted under
our common unit option plan. Accordingly, compensation expense is not recognized
for common unit options unless the options are granted at an exercise price
lower than the market price on the grant date. No compensation expense has been
recorded since the options were granted at exercise prices equal to the market
prices at the date of grant. Pro forma information regarding changes in net
income and per unit data, if the accounting prescribed by SFAS No. 123 had been
applied, is not material. For more information on unit-based compensation, see
Note 13.

     Environmental Matters

     We expense or capitalize, as appropriate, environmental expenditures that
relate to current operations. We expense expenditures that relate to an existing
condition caused by past operations, which do not contribute to current or
future revenue generation. We do not discount environmental liabilities to a net
present value, and we record environmental liabilities when environmental
assessments and/or remedial efforts are probable and we can reasonably estimate
the costs. Generally, our recording of these accruals coincides with our
completion of a feasibility study or our commitment to a formal plan of action.
We recognize receivables for anticipated associated insurance recoveries when
such recoveries are deemed to be probable.

     We 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.

     We routinely conduct reviews of potential environmental issues and claims
that could impact our assets or operations. In December 2004, we recognized a
$0.2 million increase in environmental expenses and an associated $0.1 million
increase in deferred income tax expense resulting from changes to previous
estimates. The adjustment included an $18.9 million increase in our estimated
environmental receivables and reimbursables and a $19.1 million increase in our
overall accrued environmental and related claim liabilities. We included the
additional $0.2 million environmental expense within "Other, net" in our
accompanying consolidated statement of income for 2004. The $0.3 million expense
item, including taxes, is the net impact of a $30.6 million increase in expense
in our Products Pipelines business segment, a $7.6 million decrease in expense
in our Natural Gas Pipelines segment, a $4.1 million decrease in expense in our
CO2 segment, and an $18.6 million decrease in expense in our Terminals business
segment.

     In December 2002, 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 our accompanying consolidated statement of income
for 2002. 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. For more information on our
environmental disclosures, see Note 16.

     Legal

     We are subject to litigation and regulatory proceedings as the result of
our business operations and transactions. We utilize both internal and external
counsel in evaluating our potential exposure to adverse outcomes from orders,
judgments or settlements. To the extent that actual outcomes differ from our
estimates, or additional facts and circumstances cause us to reviseour
estimates, our earnings will be affected. We expense legal costs as incurred and
all recorded legal liabilities are revised as better information becomes
available. For more information on our legal


                                      113


<PAGE>


disclosures, see Note 16.

     Pension

     We are required to make assumptions and estimates regarding the accuracy of
our pension investment returns. Specifically, these include:

     o    our investment return assumptions;

     o    the significant estimates on which those assumptions are based; and

     o    the potential impact that changes in those assumptions could have on
          our reported results of operations and cash flows.

     We consider our overall pension liability exposure to be minimal in
relation to the value of our total consolidated assets and net income. However,
in accordance with SFAS No. 87, "Employers' Accounting for Pensions," our net
periodic pension cost includes the return on pension plan assets, including both
realized and unrealized changes in the fair market value of pension plan assets.

     A source of volatility in pension costs comes from this inclusion of
unrealized or market value gains and losses on pension assets as part of the
components recognized as pension expense. To prevent wide swings in pension
expense from occurring because of one-time changes in fund values, SFAS No. 87
allows for the use of an actuarial computed "expected value" of plan asset gains
or losses to be the actual element included in the determination of pension
expense. The actuarial derived expected return on pension assets not only
employs an expected rate of return on plan assets, but also assumes a
market-related value of plan assets, which is a calculated value that recognizes
changes in fair value in a systematic and rational manner over not more than
five years. As required, we disclose the weighted average expected long-run rate
of return on our plan assets, which is used to calculate our plan assets'
expected return. For more information on our pension disclosures, see Note 10.

     Gas Imbalances and Gas Purchase Contracts

     We value gas imbalances due to or due from interconnecting pipelines at the
lower of cost or market. Gas imbalances represent the difference between
customer nominations and actual gas receipts from and gas deliveries to our
interconnecting pipelines under various operational balancing agreements.
Natural gas imbalances are either settled in cash or made up in-kind subject to
the pipelines' various tariff provisions.

     Minority Interest

     As of December 31, 2004, minority interest consisted of the following:

     o    the 1.0101% general partner interest in each of our five operating
          partnerships;

     o    the 0.5% special limited partner interest in SFPP, L.P.;

     o    the 50% interest in Globalplex Partners, a Louisiana joint venture
          owned 50% and controlled by Kinder Morgan Bulk Terminals, Inc.;

     o    the 33 1/3% interest in International Marine Terminals Partnership, a
          Louisiana partnership owned 66 2/3% and controlled by Kinder Morgan
          Operating L.P. "C";

     o    the approximate 31% interest in the Pecos Carbon Dioxide Company, a
          Texas general partnership owned approximately 69% and controlled by
          Kinder Morgan CO2 Company, L.P. and its consolidated subsidiaries;

     o    the 1% interest in River Terminals Properties, L.P., a Tennessee
          partnership owned 99% and controlled by Kinder Morgan River Terminals
          LLC; and


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<PAGE>


     o    the 25% interest in Guilford County Terminal Company, LLC, a limited
          liability company owned 75% and controlled by Kinder Morgan Southeast
          Terminals LLC.

     Income Taxes

     We are not a taxable entity for federal income tax purposes. As such, we do
not directly pay federal income tax. Our taxable income or loss, which may vary
substantially from the net income or net loss we report in our consolidated
statement of income, is includable in the federal income tax returns of each
partner. The aggregate difference in the basis of our net assets for financial
and tax reporting purposes cannot be readily determined as we do not have access
to information about each partner's tax attributes in us.

     Some of our corporate subsidiaries and corporations in which we have an
equity investment do pay federal and state income taxes. Deferred income tax
assets and liabilities for certain operations conducted through corporations are
recognized for temporary differences between the assets and liabilities for
financial reporting and tax purposes. Changes in tax legislation are included in
the relevant computations in the period in which such changes are effective.
Deferred tax assets are reduced by a valuation allowance for the amount of any
tax benefit not expected to be realized.

     Foreign Currency Translation

     In October 2004, we acquired Kinder Morgan River Terminals LLC, formerly
Global Materials Services LLC. Included in the acquisition was Arrow Terminals,
B.V., a wholly-owned subsidiary of Kinder Morgan River Terminals LLC that
conducts bulk terminal operations in The Netherlands. We translate the assets
and liabilities of Arrow Terminals, B.V. to U.S. dollars at year-end exchange
rates. Income and expense items are translated at weighted-average rates of
exchange prevailing during the year and stockholders' equity accounts are
translated by using historical exchange rates. Translation adjustments result
from translating all assets and liabilities at current year-end rates, while
stockholders' equity is translated by using historical and weighted-average
rates. The cumulative translation adjustments balance is reported as a component
of accumulated other comprehensive income within Partners' Capital on our
accompanying balance sheet. Due to the limited size of our foreign operations,
we do not believe these foreign currency translations are material to our
financial position.

     Comprehensive Income

     Statement of Financial Accounting Standards No. 130, "Accounting for
Comprehensive Income," requires that enterprises report a total for
comprehensive income. For the year ended December 31, 2004, the difference
between our net income and our comprehensive income resulted from unrealized
gains or losses on derivatives utilized for hedging purposes and from foreign
currency translation adjustments. For each of the years ended December 31, 2003
and 2002, the only difference between our net income and our comprehensive
income was the unrealized gain or loss on derivatives utilized for hedging
purposes. For more information on our risk management activities, see Note 14.

     Net Income Per Unit

     We compute Basic Limited Partners' Net Income per Unit by dividing Limited
Partners' interest in Net Income by the weighted average number of units
outstanding during the period. Diluted Limited Partners' Net Income per Unit
reflects the 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.

     Asset Retirement Obligations

     As of January 1, 2003, we account for asset retirement obligations pursuant
to SFAS No. 143, "Accounting for Asset Retirement Obligations." For more
information on our asset retirement obligations, see Note 4.


                                      115





<PAGE>


     Risk Management Activities

     We utilize energy derivatives for the purpose of mitigating our risk
resulting from fluctuations in the market price of natural gas, natural gas
liquids, crude oil and carbon dioxide. In addition, we enter into interest rate
swap agreements for the purpose of hedging the interest rate risk associated
with our debt obligations.

     Our derivatives are accounted for under SFAS No. 133, as amended by SFAS
No. 137, "Accounting for Derivative Instruments and Hedging Activities -
Deferral of the Effective Date of FASB Statement No.133" and No. 138,
"Accounting for Certain Derivative Instruments and Certain Hedging Activities."
SFAS No. 133 established accounting and reporting standards requiring that every
derivative financial instrument (including certain derivative instruments
embedded in other contracts) be recorded in the balance sheet as either an asset
or liability measured at its fair value. SFAS No. 133 requires that changes in
the derivative's fair value be recognized currently in earnings unless specific
hedge accounting criteria are met. If the derivatives meet those criteria, SFAS
No. 133 allows a derivative's gains and losses to offset related results on the
hedged item in the income statement, and requires that a company formally
designate a derivative as a hedge and document and assess the effectiveness of
derivatives associated with transactions that receive hedge accounting.

     Furthermore, if the derivative transaction qualifies for and is designated
as a normal purchase and sale, it is exempted from the fair value accounting
requirements of SFAS No. 133 and is accounted for using traditional accrual
accounting. Our derivatives that hedge our commodity price risks involve our
normal business activities, which include the sale of natural gas, natural gas
liquids, oil and carbon dioxide, and these derivatives have been designated as
cash flow hedges as defined by SFAS No. 133. SFAS No. 133 designates derivatives
that hedge exposure to variable cash flows of forecasted transactions as cash
flow hedges and the effective portion of the derivative's gain or loss is
initially reported as a component of other comprehensive income (outside
earnings) and subsequently reclassified into earnings when the forecasted
transaction affects earnings. The ineffective portion of the gain or loss is
reported in earnings immediately. See Note 14 for more information on our risk
management activities.


3.   Acquisitions and Joint Ventures

     During 2002, 2003 and 2004, we completed or made adjustments for the
following significant acquisitions. Each of the acquisitions was accounted for
under the purchase method and the assets acquired and liabilities assumed were
recorded at their estimated fair market values as of the acquisition date. The
preliminary allocation of assets and liabilities may be adjusted to reflect the
final determined amounts during a short period of time following the
acquisition. The results of operations from these acquisitions are included in
our consolidated financial statements from the acquisition date.


                                      116



<PAGE>


<TABLE>
<CAPTION>
<S>                                                            <C>          <C>       <C>         <C>       <C>       <C>

                                                                              Allocation of Purchase Price
                                                           -------------------------------------------------------------------
                                                                                     (in millions)
                                                           -------------------------------------------------------------------
                                                                                      Property    Deferred
                                                               Purchase     Current    Plant &     Charges            Minority
  Ref.   Date                  Acquisition                       Price       Assets   Equipment    & Other  Goodwill  Interest
  ----- -------------------------------------------------- -------------  ---------  ----------- --------- --------- ----------
  (1)     1/02  Kinder Morgan Materials Services LLC......      $ 14.1    $  0.9      $  13.2          $-         $-        $-
  (2)     1/02  66 2/3% Interest in Intl. MarineTerminals.        40.5       6.6         31.8         0.1          -       2.0
  (3)     1/02  Kinder Morgan Tejas.......................       878.5      56.5        674.1           -      147.9         -
  (4)     5/02  Milwaukee Bagging Operations..............         8.5       0.1          3.1           -        5.3         -
  (5)     5/02  Trailblazer Pipeline Company..............        80.1         -         41.7           -       15.0      23.4
  (6)     9/02  Owensboro Gateway Terminal................         7.7       0.0          4.3         0.1        3.3         -
  (7)     9/02  IC Terminal Holdings Company..............        17.7       0.1         14.3         3.3          -         -
  (8)     1/03  Bulk Terminals from M.J. Rudolph..........        31.3       0.1         18.2         0.1       12.9         -
  (9)     6/03  MKM Partners, L.P.........................        25.2         -         25.2           -          -         -
  (10)    8/03  Interest in Red Cedar Gathering Company...        10.0         -           -         10.0          -         -
  (11)   10/03  Shell Products Terminals..................        20.0         -         20.0           -          -         -
  (12)   11/03  Yates Field Unit and Carbon Dioxide Assets       259.9       3.6        256.6           -          -      (0.3)
  (13)   11/03  Interest in MidTex Gas Storage Co., LLP...        17.5         -         11.9           -          -       5.6
  (14)   12/03  ConocoPhillips Products Terminals.........        15.3         -         14.3         1.0          -         -
  (15)   12/03  Tampa, Florida Bulk Terminals.............        29.1         -         29.1           -          -         -
  (16)    3/04  ExxonMobil Products Terminals.............        50.9         -         50.9           -          -         -
  (17)    8/04  Kinder Morgan Wink Pipeline, L.P..........       100.3       0.1        100.2           -          -         -
  (18)   10/04  Interest in Cochin Pipeline System........        10.9         -         10.9           -          -         -
  (19)   10/04  Kinder Morgan River Terminals LLC.........        89.6       9.9         70.2         3.1        6.4         -
  (20)   11/04  Charter Products Terminals................        75.2       3.7         71.8         0.8          -      (1.1)
  (21)   11/04  TransColorado Gas Transmission Company....       284.5       2.0        280.6         1.9          -         -
  (22)   12/04  Kinder Morgan Fairless Hills Terminal.....     $   7.5       $ -        $ 6.2        $1.3         $-        $-

</TABLE>

     (1)  Kinder Morgan Materials Services LLC

     Effective January 1, 2002, we acquired all of the equity interests of
Kinder Morgan Materials Services LLC, formerly Laser Materials Services LLC, for
an aggregate consideration of $14.1 million, consisting of approximately $10.8
million in cash and the assumption of approximately $3.3 million of liabilities,
including long-term debt of $0.4 million. Kinder Morgan Materials Services LLC
currently operates approximately 60 transload facilities in 20 states. The
facilities handle dry-bulk products, including aggregates, plastics and liquid
chemicals. The acquisition of Kinder Morgan Materials Services LLC expanded our
growing terminal operations and is part of our Terminals business segment.

     (2)  66 2/3% Interest in International Marine Terminals

     Effective January 1, 2002, we acquired a 33 1/3% interest in International
Marine Terminals Partnership, referred to in this report as IMT, from Marine
Terminals Incorporated. Effective February 1, 2002, we acquired an additional 33
1/3% interest in IMT from Glenn Springs Holdings, Inc. Our combined purchase
price was approximately $40.5 million, including the assumption of $40 million
of long-term debt. IMT is a partnership that operates a bulk terminal site in
Port Sulphur, Louisiana. This terminal is a multi-purpose import and export
facility, which handles approximately 10 million tons annually of bulk products
including coal, petroleum coke, iron ore and barite. The acquisition complements
our existing bulk terminal assets. IMT is part of our Terminals business
segment.

     (3)  Kinder Morgan Tejas

     Effective January 31, 2002, we acquired all of the equity interests of
Tejas Gas, LLC, a wholly-owned subsidiary of InterGen (North America), Inc., for
an aggregate consideration of approximately $878.5 million, consisting of $727.1
million in cash and the assumption of $151.4 million of liabilities. Tejas Gas,
LLC consists primarily of a 3,400-mile natural gas intrastate pipeline system
that extends from south Texas along the Mexico border and the Texas Gulf Coast
to near the Louisiana border and north from near Houston to east Texas. The
acquisition expanded our natural gas operations within the State of Texas. The
acquired assets are referred to as Kinder Morgan Tejas in this report and are
included in our Natural Gas Pipelines business segment. The combination of these


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<PAGE>


systems is part of our Texas intrastate natural gas pipeline group. Our
allocation to assets acquired and liabilities assumed was based on an appraisal
of fair market values. The $147.9 million of goodwill was assigned to our
Natural Gas Pipelines business segment and the entire amount is expected to be
deductible for tax purposes.

     (4) Milwaukee Bagging Operations

     Effective May 1, 2002, we purchased a bagging operation facility adjacent
to our Milwaukee, Wisconsin dry-bulk terminal for $8.5 million. The purchase
enhances the operations at our Milwaukee bulk terminal, which is capable of
handling up to 150,000 tons per year of fertilizer and salt for de-icing and
livestock purposes. The Milwaukee bagging operations are included in our
Terminals business segment. The $5.3 million of goodwill was assigned to our
Terminals business segment and the entire amount is expected to be deductible
for tax purposes.

     (5) Trailblazer Pipeline Company

     On May 6, 2002, we acquired the remaining 33 1/3% ownership interest in
Trailblazer Pipeline Company that we did not already own from Enron Trailblazer
Pipeline Company for an aggregate consideration of $80.1 million. We now own
100% of Trailblazer Pipeline Company. In May 2002, we paid $68 million to an
affiliate of Enron Corp., and during the first quarter of 2002, we paid $12.1
million to CIG Trailblazer Gas Company, an affiliate of El Paso Corporation, in
exchange for CIG's relinquishment of its rights to become a 7% to 8% equity
owner in Trailblazer Pipeline Company in mid-2002. Trailblazer Pipeline Company
is an Illinois partnership that owns and operates a 436-mile natural gas
pipeline system that traverses from Colorado through southeastern Wyoming to
Beatrice, Nebraska. Trailblazer Pipeline Company has a current certificated
capacity of 846 million cubic feet per day of natural gas. The $15.0 million of
goodwill was assigned to our Natural Gas Pipelines business segment and the
entire amount is expected to be deductible for tax purposes.

     (6) Owensboro Gateway Terminal

     Effective September 1, 2002, we acquired the Lanham River Terminal near
Owensboro, Kentucky and related equipment for $7.7 million. In September 2002,
we paid approximately $7.2 million and established a $0.5 million purchase price
retention liability to be paid at the later of: (i) one year following the
acquisition, or (ii) the day we received consent to the assignment of a contract
between the seller and the New York Mercantile Exchange, Inc. We paid the $0.5
million liability in September 2003. The facility is one of the nation's largest
storage and handling points for bulk aluminum. The terminal also handles a
variety of other bulk products, including petroleum coke, lime and de-icing
salt. The terminal is situated on a 92-acre site along the Ohio River, and the
purchase expanded our presence along the river, complementing our existing
facilities located near Cincinnati, Ohio and Moundsville, West Virginia. We
refer to the acquired terminal as our Owensboro Gateway Terminal and we include
its operations in our Terminals business segment. The $3.3 million of goodwill
was assigned to our Terminals business segment and the entire amount is expected
to be deductible for tax purposes.

     (7) IC Terminal Holdings Company

     Effective September 1, 2002, we acquired all of the shares of the capital
stock of IC Terminal Holdings Company from the Canadian National Railroad. Our
purchase price was $17.7 million, consisting of $17.4 million in cash and the
assumption of $0.3 million in liabilities. The total purchase price decreased
$0.2 million in the third quarter of 2003 primarily due to adjustments in the
amount of working capital items assumed on the acquisition date. The acquisition
included the former ICOM marine terminal in St. Gabriel, Louisiana. The St.
Gabriel facility has 400,000 barrels of liquids storage capacity and a related
pipeline network. The acquisition further expanded our terminal businesses along
the Mississippi River. The acquired terminal is referred to as the Kinder Morgan
St. Gabriel terminal, and we include its operations in our Terminals business
segment.

     (8) Bulk Terminals from M.J. Rudolph

     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 the acquisition
was approximately $31.3 million. On December 31, 2002, we paid



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<PAGE>


$29.9 million, 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. The acquisition
expanded our growing Terminals business segment and complements certain of our
existing terminal facilities. We include its operations in our Terminals
business segment, and in our final analysis, it was considered reasonable to
allocate a portion of our purchase price to goodwill given the substance of this
transaction, including expected benefits from integrating this acquisition with
our existing assets. The $12.9 million of goodwill was assigned to our Terminals
business segment and the entire amount is expected to be deductible for tax
purposes.

     (9) MKM Partners, L.P.

     Effective June 1, 2003, we acquired the MKM joint venture's 12.75%
ownership interest in the SACROC oil field unit for an aggregate consideration
of $25.2 million, consisting of $23.3 million in cash 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%.

     On June 20, 2003, we signed an agreement with subsidiaries of Marathon Oil
Corporation to dissolve MKM Partners, L.P., a joint venture we formed on January
1, 2001 with subsidiaries of Marathon Oil Company. The joint venture assets
consisted of a 12.75% interest in the SACROC oil field unit, which we acquired
June 1, 2003 as described above, and a 49.9% interest in the Yates Field unit,
both of which are in the Permian Basin of West Texas. The MKM joint venture was
owned 85% by subsidiaries of Marathon Oil Company and 15% by Kinder Morgan CO2
Company, L.P. It was dissolved effective June 30, 2003, and the net assets were
distributed to partners in accordance with its partnership agreement.

     (10) Interest in 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. 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 be maintained at 49% in the
future. The purchase price was allocated to our equity investment in Red Cedar,
included with our equity method goodwill.

     (11) Shell Products Terminals

     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. As of our acquisition date, we expected to invest an
additional $8.0 million in the facilities. 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. As part of
the transaction, Shell has entered into a long-term contract to store products
in the terminals. The acquisition enhances our Pacific operations and
complements our existing West Coast Terminals. The acquired operations are
included as part of our Pacific operations and our Products Pipelines business
segment.

     (12) Yates Field Unit and Carbon Dioxide Assets

     Effective November 1, 2003, we acquired certain assets in the Permian Basin
of West Texas from a subsidiary of Marathon Oil Corporation. Our purchase price
was approximately $259.9 million, consisting of $230.2 million in cash and the
assumption of $29.7 million of liabilities. The assets acquired consisted of the
following:

     o    Marathon's approximate 42.5% interest in the Yates oil field unit. We
          previously owned a 7.5% ownership interest in the Yates field unit and
          we now operate the field;

     o    Marathon's 100% interest in the crude oil gathering system surrounding
          the Yates field unit; and


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<PAGE>


     o    Kinder Morgan Carbon Dioxide Transportation Company, formerly Marathon
          Carbon Dioxide Transportation Company. Kinder Morgan Carbon Dioxide
          Transportation Company owns a 65% ownership interest in the Pecos
          Carbon Dioxide Pipeline Company, which owns a 25-mile carbon dioxide
          pipeline. We previously owned a 4.27% ownership interest in the Pecos
          Carbon Dioxide Pipeline Company and accounted for this investment
          under the cost method of accounting. After the acquisition of our
          additional 65% interest in Pecos, its financial results are included
          in our consolidated results and we recognize the appropriate minority
          interest.

     Together, the acquisition of these assets complemented our existing carbon
dioxide assets in the Permian Basin, increased our working interest in the Yates
field to nearly 50% and allowed us to become the operator of the field. We
recorded a deferred tax liability of $0.8 million in August 2004 to properly
reflect the tax obligations of Kinder Morgan Carbon Dioxide Transportation
Company. The acquired operations are included as part of our CO2 business
segment.

     (13) Interest in MidTex Gas Storage Company, LLP

     Effective November 1, 2003, we acquired the remaining approximate 32%
ownership interest in MidTex Gas Storage Company, LLP that we did not already
own from an affiliate of NiSource Inc. Our combined purchase price was
approximately $17.5 million, consisting of $15.8 million in cash and the
assumption of $1.7 million of debt. The debt represented a MidTex note payable
that was to be paid by the former partner. We now own 100% of MidTex Gas Storage
Company, LLP. MidTex Gas Storage Company, LLP is a Texas limited liability
partnership that owns two salt dome natural gas storage facilities located in
Matagorda County, Texas. MidTex's operations are included as part of our Natural
Gas Pipelines business segment.

     (14) ConocoPhillips Products Terminals

     Effective December 11, 2003, we acquired seven refined petroleum products
terminals located in the southeastern United States from ConocoPhillips Company
and Phillips Pipe Line Company. Our purchase price was approximately $15.3
million, consisting of approximately $14.1 million in cash and $1.2 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 fully own and operate all of the terminals
except for the Doraville, Georgia facility, which is operated and owned 70% by
Citgo. As of our acquisition date, we expected to invest an additional $1.3
million in the facilities. Combined, the terminals have 35 storage tanks with
total capacity of approximately 1.15 million barrels for gasoline, diesel fuel
and jet fuel. As part of the transaction, ConocoPhillips entered into a
long-term contract to use the terminals. The contract consists of a five-year
terminaling agreement, an intangible asset which we valued at $1.0 million. The
acquisition broadened our refined petroleum products operations in the
southeastern United States as three of the terminals are connected to the
Plantation pipeline system, which is operated and owned 51% by us. The acquired
operations are included as part of our Products Pipelines business segment.

     (15) Tampa, Florida Bulk Terminals

     In December 2003, we acquired two bulk terminal facilities in Tampa,
Florida for an aggregate consideration of approximately $29.1 million,
consisting of $26.3 million in cash and $2.8 million in assumed liabilities. As
of our acquisition date, we expected to invest an additional $16.9 million in
the facilities. The principal facility purchased was a marine terminal acquired
from a subsidiary of The Mosaic Company, formerly IMC Global, Inc. We entered
into a long-term agreement with Mosaic pursuant to which Mosaic will 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. We closed on the
Tampaplex portion of this transaction on December 23, 2003. The second facility
purchased was the former Nitram, Inc. bulk terminal, which we have converted to
an inland bulk storage warehouse facility for overflow cargoes from our Port
Sutton, Florida import terminal. We closed on the Nitram portion of this
transaction on December 10, 2003. We recorded our final purchase price
adjustments in the third quarter of 2004. The adjustments included the removal
of a property tax liability in the amount of $0.6 million, which had been
established in December 2003 pending final determination of assumed tax
obligations. The



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<PAGE>


acquired operations are included as part of our Terminals business segment and
complement our existing businesses in the Tampa area by generating additional
fee-based income.

     (16) ExxonMobil Products Terminals

     Effective March 9, 2004, we acquired seven refined petroleum products
terminals in the southeastern United States from Exxon Mobil Corporation. Our
purchase price was approximately $50.9 million, consisting of approximately
$48.2 million in cash and $2.7 million in assumed liabilities. 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, ExxonMobil
entered into a long-term contract to store products at the terminals. As of our
acquisition date, we expected to invest an additional $1.2 million in the
facilities. The acquisition enhanced our terminal operations in the Southeast
and complemented our December 2003 acquisition of seven products terminals from
ConocoPhillips Company and Phillips Pipe Line Company. The acquired operations
are included as part of our Products Pipelines business segment.

     (17) Kinder Morgan Wink Pipeline, L.P.

     Effective August 31, 2004, we acquired all of the partnership interests in
Kaston Pipeline Company, L.P. from KPL Pipeline Company, LLC and RHC Holdings,
L.P. for a purchase price of approximately $100.3 million, consisting of $89.9
million in cash and the assumption of approximately $10.4 million of
liabilities, including debt of $9.5 million. In September 2004, we paid the $9.5
million outstanding debt balance. We renamed the limited partnership Kinder
Morgan Wink Pipeline, L.P., and since August 31, 2004, we have included its
results as part of our CO2 business segment. The acquisition included a 450-mile
crude oil pipeline system, consisting of four mainline sections, numerous
gathering systems and truck off-loading stations. The mainline sections, all in
Texas, have a total capacity of 115,000 barrels of crude oil per day. As part of
the transaction, we entered into a long-term throughput agreement with Western
Refining Company, L.P. to transport crude oil into Western's 107,000 barrel per
day refinery in El Paso, Texas. As of our acquisition date, we expected to
invest approximately $11.0 million over the next five years to upgrade the
assets. The acquisition allows us to better manage crude oil deliveries from our
oil field interests in West Texas.

     (18) Interest in Cochin Pipeline

     Effective October 1, 2004, we acquired an additional undivided 5% interest
in the Cochin Pipeline System from subsidiaries of ConocoPhillips Corporation
for approximately $10.9 million. On November 3, 2000, we acquired from NOVA
Chemicals Corporation an undivided 32.5% interest in the Cochin Pipeline System
for approximately $120.5 million. On June 20, 2001, we acquired an additional
2.3% ownership interest from Shell Canada Limited for approximately $8.1
million, and effective December 31, 2001, we purchased an additional 10%
ownership interest from NOVA Chemicals Corporation for approximately $29
million. We now own approximately 49.8% of the Cochin Pipeline System. A
subsidiary of BP owns the remaining interest and operates the pipeline. We
record our proportional share of joint venture revenues and expenses and cost of
joint venture assets with respect to the Cochin Pipeline System as part of our
Products Pipelines business segment. Our allocation of the purchase price to
assets acquired is preliminary, pending any minor adjustments that may be
necessary under the purchase and sale agreement. We expect to make any final
adjustments by the end of the first quarter of 2005.

     (19) Kinder Morgan River Terminals LLC

     Effective October 6, 2004, we acquired Global Materials Services LLC and
its consolidated subsidiaries from Mid-South Terminal Company, L.P. for
approximately $89.6 million, consisting of $31.8 million in cash and $57.8
million of assumed liabilities, including debt of $33.7 million. Global
Materials Services LLC, which we renamed Kinder Morgan River Terminals LLC,
operates a network of 21 river terminals and two rail transloading facilities
primarily located along the Mississippi River system. The network provides
loading, storage and unloading points for various bulk commodity imports and
exports. As of our acquisition date, we expected to invest an additional $9.4
million over the next two years to expand and upgrade the terminals, which are
located in 11 Mid-Continent states. The acquisition further expands and
diversifies our customer base and complements our existing terminal facilities
located along the lower-Mississippi River system. The acquired terminals are
included in our Terminals


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<PAGE>


business segment. Our allocation of the purchase price to assets acquired and
liabilities assumed is preliminary, pending final purchase price adjustments
that may be necessary following an independent appraisal of fair market values.
We expect the appraisal to be completed by the end of the first quarter of 2005.
The $6.4 million of goodwill was assigned to our Terminals business segment and
the entire amount is expected to be deductible for tax purposes.

     (20) Charter Products Terminals

     Effective November 5, 2004, we acquired ownership interests in nine refined
petroleum products terminals in the southeastern United States from Charter
Terminal Company and Charter-Triad Terminals, LLC for approximately $75.2
million, consisting of $72.4 million in cash and $2.8 million of assumed
liabilities. Three terminals are located in Selma, North Carolina, and the
remaining facilities are located in Greensboro and Charlotte, North Carolina;
Chesapeake and Richmond, Virginia; Athens, Georgia; and North Augusta, South
Carolina. We fully own seven of the terminals and jointly own the remaining two.
The nine facilities have a combined 3.2 million barrels of storage. As of our
acquisition date, we expected to invest an additional $2 million over the next
two years to upgrade the facilities. All of the terminals are connected to
products pipelines owned by either Plantation Pipe Line Company or Colonial
Pipeline Company. The acquisition complements the existing terminals we own in
the Southeast and increased our southeast terminal storage capacity 76% (to 7.7
million barrels) and terminal throughput capacity 62% (to over 340,000 barrels
per day). The acquired terminals are included as part of our Products Pipelines
business segment. Our allocation of the purchase price to assets acquired and
liabilities assumed is preliminary, pending final purchase price adjustments
that may be necessary following an independent appraisal of fair market values.
We expect the appraisal to be completed by the end of the first quarter of 2005.

     (21) TransColorado Gas Transmission Company

     Effective November 1, 2004, we acquired all of the partnership interests in
TransColorado Gas Transmission Company from two wholly-owned subsidiaries of
KMI. TransColorado Gas Transmission Company, a Colorado general partnership
referred to in this report as TransColorado, owned assets valued at
approximately $284.5 million. As consideration for TransColorado, we paid to KMI
$211.2 million in cash and approximately $64.0 million in units, consisting of
1,400,000 common units. We also assumed liabilities of approximately $9.3
million. The purchase price for this transaction was determined by the boards of
directors of KMR and our general partner, and KMI based on valuation parameters
used in the acquisition of similar assets. The transaction was approved
unanimously by the independent members of the boards of directors of both KMR
and our general partner, and KMI, with the benefit of advice of independent
legal and financial advisors, including the receipt of fairness opinions from
separate investment banks, specifically Goldman, Sachs & Co. and Morgan Stanley
& Co. TransColorado owns a 300-mile interstate natural gas pipeline that
originates in the Piceance Basin of western Colorado and runs to the Blanco Hub
in northwest New Mexico. The acquisition expanded our natural gas operations
within the Rocky Mountain region and the acquired operations are included as
part of our Natural Gas Pipelines business segment.

     (22) Kinder Morgan Fairless Hills Terminal

     Effective December 1, 2004, we acquired substantially all of the assets
used to operate the major port distribution facility located at the Fairless
Industrial Park in Bucks County, Pennsylvania for an aggregate consideration of
approximately $7.5 million, consisting of $7.2 million in cash and $0.3 million
in assumed liabilities. The facility, referred to as our Kinder Morgan Fairless
Hills Terminal, was purchased from Novolog Bucks County, Inc. and is located on
the Delaware River. It is the largest port on the East Coast for the handling of
semi-finished steel slabs, which are used as feedstock by domestic steel mills.
The port operations at Fairless Hills also include the handling of other types
of steel and specialized cargo that caters to the construction industry and
service centers that use steel sheet and plate. The terminal expanded our
presence along the Delaware River and complements our existing Mid-Atlantic
terminal facilities. As of our acquisition date, we expected to invest an
additional $8.3 million in the facility. We include its operations in our
Terminals business segment.


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     Pro Forma Information

  The following summarized unaudited pro forma consolidated income statement
information for the years ended December 31, 2004 and 2003, assumes that all of
the acquisitions we have made and joint ventures we have entered into since
January 1, 2003, including the ones listed above, had occurred as of January 1,
2003. We have prepared these unaudited pro forma financial results for
comparative purposes only. These unaudited pro forma financial results may not
be indicative of the results that would have occurred if we had completed these
acquisitions and joint ventures as of January 1, 2003 or the results that will
be attained in the future. Amounts presented below are in thousands, except for
the per unit amounts:

                                                          Pro Forma Year Ended
                                                              December 31,
                                                          ---------------------
                                                            2004         2003
                                                          ----------  ----------
                                                                (Unaudited)
Revenues................................................  $8,049,660  $6,872,721
Operating Income........................................   1,015,229     913,716
Income   Before   Cumulative   Effect  of  a  Change  in
 Accounting Principle...................................     868,759     786,247
Net Income..............................................  $  868,759  $  789,712
Basic and Diluted Limited Partners' Net Income per unit:
  Income  Before   Cumulative  Effect  of  a  Change  in
    Accounting Principle................................  $     2.38  $     2.44
  Net Income............................................  $     2.38  $     2.46


4.  Change in Accounting for Asset Retirement Obligations

     In August 2001, the Financial Accounting Standards Board issued SFAS No.
143, "Accounting for Asset Retirement Obligations." SFAS No. 143 provides
accounting and reporting guidance for legal obligations associated with the
retirement of long-lived assets that result from the acquisition, construction
or normal operation of a long-lived asset. The provisions of this Statement are
effective for fiscal years beginning after June 15, 2002. We adopted SFAS No.
143 on January 1, 2003.

     SFAS No. 143 requires companies to record a liability relating to the
retirement and removal of assets used in their businesses. Its primary impact on
us was to change the method of accruing for oil and gas production site
restoration costs related to our CO2 business segment. Prior to January 1, 2003,
we accounted for asset retirement obligations for this business in accordance
with SFAS No. 19, "Financial Accounting and Reporting by Oil and Gas Producing
Companies." Under SFAS No. 143, the fair value of asset retirement obligations
are recorded as liabilities on a discounted basis when they are incurred, which
is typically at the time the assets are installed or acquired. Amounts recorded
for the related assets are increased by the amount of these obligations. Over
time, the liabilities will be accreted for the change in their present value and
the initial capitalized costs will be depreciated over the useful lives of the
related assets. The liabilities are eventually extinguished when the asset is
taken out of service. Specifically, upon adoption of this Statement, an entity
must recognize the following items in its balance sheet:

     o    a liability for any existing asset retirement obligations adjusted for
          cumulative accretion to the date of adoption;

     o    an asset retirement cost capitalized as an increase to the carrying
          amount of the associated long-lived asset; and

     o    accumulated depreciation on that capitalized cost.

     Amounts resulting from initial application of this Statement are measured
using current information, current assumptions and current interest rates. The
amount recognized as an asset retirement cost is measured as of the date the
asset retirement obligation was incurred. Cumulative accretion and accumulated
depreciation are measured for the time period from the date the liability would
have been recognized had the provisions of this Statement been in effect to the
date of adoption of this Statement.

     The cumulative effect adjustment for this change in accounting principle
resulted in income of $3.4 million in the first quarter of 2003. Furthermore, as
required by SFAS No. 143, we recognized the cumulative effect of initially
applying SFAS No. 143 as a change in accounting principle as described in
Accounting Principles Board Opinion 20, "Accounting Changes." The cumulative
effect adjustment resulted from the difference between the amounts



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recognized in our consolidated balance sheet prior to the application of SFAS
No. 143 and the net amount recognized in our consolidated balance sheet pursuant
to SFAS No. 143.

     In our CO2 business segment, we are required to plug and abandon oil and
gas wells that have been removed from service and to remove our surface wellhead
equipment and compressors. As of December 31, 2004 and 2003, we have recognized
asset retirement obligations relating to these requirements at existing sites
within our CO2 segment in the aggregate amounts of $34.7 million and $32.7
million, respectively.

     In our Natural Gas Pipelines business segment, if we were to cease
providing utility services, we would be required to remove surface facilities
from land belonging to our customers and others. Our Texas intrastate natural
gas pipeline group has various condensate drip tanks and separators located
throughout its natural gas pipeline systems, as well as inactive gas processing
plants, laterals and gathering systems which are no longer integral to the
overall mainline transmission systems, and asbestos-coated underground pipe
which is being abandoned and retired. Our Kinder Morgan Interstate Gas
Transmission system has compressor stations which are no longer active and other
miscellaneous facilities, all of which have been officially abandoned. We
believe we can reasonably estimate both the time and costs associated with the
retirement of these facilities. As of December 31, 2004 and 2003, we have
recognized asset retirement obligations relating to the businesses within our
Natural Gas Pipelines segment in the aggregate amounts of $3.6 million and $3.0
million, respectively.

     We have included $0.8 million of our total asset retirement obligations as
of both December 31, 2004 and December 31, 2003 with "Accrued other current
liabilities" in our accompanying consolidated balance sheets. The remaining
$37.5 million obligation as of December 31, 2004 and $34.9 million obligation as
of December 31, 2003 are reported separately as non-current liabilities in our
accompanying consolidated balance sheets. No assets are legally restricted for
purposes of settling our asset retirement obligations. A reconciliation of the
beginning and ending aggregate carrying amount of our asset retirement
obligations for each of years ended December 31, 2004 and 2003 is as follows (in
thousands):

                                             Year Ended December 31,
                                        -------------------------------
                                             2004              2003
                                        ------------       ------------
Balance at beginning of period..........$     35,708       $          -
Initial ARO balance upon adoption.......           -             14,125
Liabilities incurred....................       1,157             12,911
Liabilities settled.....................        (672)            (1,056)
Accretion expense.......................       2,081              1,028
Revisions in estimated cash flows.......           -              8,700
                                        ------------       ------------
Balance at end of period................$     38,274       $     35,708
                                        ============       ============


     Pro Forma Information

     Had the provisions of SFAS No. 143 been in effect prior to January 1, 2003,
our net income and associated per unit amounts, and the amount of our liability
for asset retirement obligations, would have been as follows (in thousands,
except per unit amounts):


                                                           Pro Forma Year Ended
                                                           --------------------
                                                             December 31, 2002
                                                             -----------------
                                                                (Unaudited)
Reported income before cumulative effect of a change in
  accounting principle.....................................      $608,377
Adjustments from change in accounting for asset  retirement
  obligations..............................................        (1,161)
                                                                 ---------
Adjusted income before cumulative effect of a change in
  accounting principle.....................................      $607,216
                                                                 ========
Reported income before cumulative effect of a change in
accounting principle per unit (fully diluted)..............      $   1.96
                                                                 ========
Adjusted income before cumulative effect of a change in
accounting principle per unit (fully diluted)..............      $   1.95
                                                                 ========

                                                        December 31,
                                                        ------------
                                                            2002
                                                           ------
        Liability for asset retirement obligations....     $14,125
                                                           =======


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5.  Income Taxes

     Components of the income tax provision applicable to continuing operations
for federal, foreign and state taxes are as follows (in thousands):

                                        Year Ended December 31,
                                   ------------------------------
                                      2004       2003        2002
                                   ---------- ----------  -------
        Taxes currently payable:
          Federal.............     $  7,515   $    437    $ 15,855
          State...............        1,497      1,131       3,116
          Foreign.............           70         25         147
                                   --------   --------    ---------
          Total...............        9,082      1,593      19,118
        Taxes deferred:
          Federal.............        5,694     11,650      (3,280)
          State...............          883      1,939        (555)
          Foreign.............        4,067      1,449           -
                                   --------   --------    ---------
          Total...............       10,644     15,038      (3,835)
                                   --------   --------    ---------
        Total tax provision...     $ 19,726   $ 16,631    $ 15,283
                                   ========   ========    =========
        Effective tax rate....          2.3%       2.3%        2.4%


          The difference between the statutory federal income tax rate and our
     effective income tax rate is summarized as follows:


                                                   Year Ended December 31,
                                                 -------------------------
                                                   2004     2003     2002
                                                 -------  -------  -------
Federal income tax rate.......................     35.0%    35.0%   35.0%
Increase (decrease) as a result of:
  Partnership earnings not subject to tax.....    (35.0)%  (35.0)% (35.0)%
  Corporate subsidiary earnings subject to tax      0.5%     0.5%    0.6%
  Income tax expense attributable to corporate
    equity earnings...........................      1.2%     1.5%    1.6%
  Income tax expense attributable to foreign
    corporate earnings........................      0.5%     0.2%    -
  State taxes.................................      0.1%     0.1%    0.2%
                                                 -------  -------  -------
Effective tax rate............................      2.3%     2.3%    2.4%
                                                 =======  ======= ========

     Deferred tax assets and liabilities result from the following (in
thousands):

                                                          December 31,
                                                       -----------------
                                                         2004      2003
                                                       --------  -------
Deferred tax assets:
  Book accruals....................................    $  1,349  $ 1,424
  Net Operating Loss/Alternative minimum tax credits      7,138   10,797
  Other............................................       1,472        -
                                                       --------  -------
Total deferred tax assets..........................       9,959   12,221

Deferred tax liabilities:
  Property, plant and equipment....................      59,277   50,327
  Other............................................       7,169        -
                                                       --------  -------
Total deferred tax liabilities.....................      66,446   50,327
                                                       --------  -------
Net deferred tax liabilities.......................    $ 56,487  $38,106
                                                       ========  =======

     We had available, at December 31, 2004, approximately $0.3 million of
alternative minimum tax credit carryforwards, which are available indefinitely,
and $6.8 million of net operating loss carryforwards, which will expire between
the years 2005 and 2024. We believe it is more likely than not that the net
operating loss carryforwards will be utilized prior to their expiration;
therefore, no valuation allowance is necessary.


6.  Property, Plant and Equipment

    Property, plant and equipment consists of the following (in thousands):


                                      125

<PAGE>



                                                               December 31,
                                                       ------------------------
                                                           2004        2003
                                                       -----------  -----------
  Natural gas, liquids and carbon dioxide pipelines....$ 3,903,021  $ 3,458,736
  Natural  gas,  liquids  and  carbon  dioxide
   pipeline  station equipment.........................  3,443,817    2,908,273
  Coal and bulk tonnage transfer, storage and services.    512,024      359,088
  Natural gas and transmix processing..................    105,375      100,778
  Other................................................    511,787      330,982
  Accumulated depreciation and depletion...............   (947,660)    (641,914)
                                                       -----------  -----------
                                                         7,528,364    6,515,943
  Land and land right-of-way...........................    371,172      339,579
  Construction work in process.........................    269,144      236,036
                                                       -----------  -----------
  Property, Plant and Equipment, net...................$ 8,168,680  $ 7,091,558
                                                       ===========  ===========

     Depreciation and depletion expense charged against property, plant and
equipment consists of the following (in thousands):

                                                    2004      2003      2002
                                                  -------   --------  --------
        Depreciation and depletion expense....    $285,351  $217,401  $171,461


7.  Investments

    Our significant equity investments as of December 31, 2004 consisted of:

    o Plantation Pipe Line Company (51%);

    o Red Cedar Gathering Company (49%);

    o Thunder Creek Gas Services, LLC (25%);

    o Coyote Gas Treating, LLC (Coyote Gulch) (50%);

    o Cortez Pipeline Company (50%); and

    o Heartland Pipeline Company (50%).

     We own approximately 51% of Plantation Pipe Line Company, and an affiliate
of ExxonMobil owns the remaining approximate 49%. Each investor has an equal
number of directors on Plantation's board of directors, and board approval is
required for certain corporate actions that are considered participating rights.
Therefore, we do not control Plantation Pipe Line Company, and we account for
our investment under the equity method of accounting.

     On January 1, 2002, Kinder Morgan CO2 Company, L.P. owned a 15% interest in
MKM Partners, L.P., a joint venture with Marathon Oil Company. The remaining 85%
interest in MKM Partners was owned by subsidiaries of Marathon Oil Company. The
joint venture assets consisted of a 12.75% interest in the SACROC oil field unit
and a 49.9% interest in the Yates field unit, both of which are in the Permian
Basin of West Texas. We accounted for our 15% investment in the joint venture
under the equity method of accounting because our ownership interest included
50% of the joint venture's general partner interest, and the ownership of this
general partner interest gave us the ability to exercise significant influence
over the operating and financial policies of the joint venture. Effective June
1, 2003, we acquired the MKM joint venture's 12.75% ownership interest in the
SACROC unit for $23.3 million and the assumption of $1.9 million of liabilities.
On June 20, 2003, we signed an agreement with subsidiaries of Marathon Oil
Corporation to dissolve MKM Partners, L.P. The partnership's dissolution was
effective June 30, 2003, and the net assets were distributed to partners in
accordance with its partnership agreement. Our interests in the SACROC unit and
the Yates field unit, including the incremental interest acquired in November
2003, are accounted for using the proportional method of consolidation for oil
and gas operations.

     In September 2003, we paid $10.0 million to acquire reversionary interests
in the Red Cedar Gas Gathering Company. The 4% reversionary interests were held
by the Southern Ute Indian Tribe and 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 be maintained at 49% in the future. For
more information on our acquisitions, see Note 3.


                                      126
<PAGE>


     Our total investments consisted of the following (in thousands):

                                                               December 31,
                                                            -------------------
                                                              2004       2003
                                                            --------   --------
Plantation Pipe Line Company...........................     $216,142   $219,349
Red Cedar Gathering Company............................      124,209    114,176
Thunder Creek Gas Services, LLC........................       37,122     37,245
Cortez Pipeline Company................................       15,503     12,591
Coyote Gas Treating, LLC...............................       12,964     13,502
Heartland Pipeline Company.............................        5,106      5,109
All Others.............................................        2,209      2,373
                                                            --------   --------
Total Equity Investments...............................     $413,255   $404,345
                                                            ========   ========

     Our earnings from equity investments were as follows (in thousands):

                                             Year Ended December 31,
                                         -------------------------------
                                           2004        2003       2002
                                         --------    --------   --------
Cortez Pipeline Company.............     $ 34,179    $ 32,198   $ 28,154
Plantation Pipe Line Company........       25,879      27,983     26,426
Red Cedar Gathering Company.........       14,679      18,571     19,082
Thunder Creek Gas Services, LLC.....        2,828       2,833      2,154
Coyote Gas Treating, LLC............        2,453       2,608      2,651
Heartland Pipeline Company..........        1,369         973        998
MKM Partners, L.P...................            -       5,000      8,174
All Others..........................        1,803       2,033      1,619
                                         --------    --------   --------
Total...............................     $ 83,190    $ 92,199   $ 89,258
                                         ========    ========   ========
Amortization of excess costs........     $ (5,575)   $ (5,575)  $ (5,575)
                                         ========    ========   ========

     Summarized combined unaudited financial information for our significant
equity investments (listed above) is reported below (in thousands; amounts
represent 100% of investee financial information):

                                                    Year Ended December 31,
                                               --------------------------------
        Income Statement                           2004        2003       2002
----------------------------------             ---------   --------   ---------
Revenues...................................... $ 418,186   $467,871   $ 505,602
Costs and expenses............................   265,819    295,931     309,291
                                               ---------   --------   ---------
Earnings before extraordinary items and
  cumulative effect of a change in accounting
  principle...................................   152,367    171,940     196,311
                                               =========   ========   =========
Net income....................................  $152,367   $168,167    $196,311
                                               =========   ========   =========

                                               December 31,
                                          ----------------------
                  Balance Sheet               2004        2003
             --------------------------   ----------- ----------
             Current assets............   $  107,954  $   93,709
             Non-current assets........      696,493     684,754
             Current liabilities.......      218,922     377,535
             Non-current liabilities...      364,406     209,468
             Partners'/owners' equity..   $  221,119  $  191,460


8.   Intangibles

     Under ABP No. 18, any premium paid by an investor, which is analogous to
goodwill, must be identified. Under prior rules, excess cost over underlying
fair value of net assets accounted for under the equity method, referred to as
equity method goodwill, would have been amortized, however, under SFAS No. 142,
equity method goodwill is not subject to amortization but rather to impairment
testing pursuant to ABP No. 18. The impairment test under APB No. 18 considers
whether the fair value of the equity investment as a whole, not the underlying
net assets, has declined and whether that decline is other than temporary. This
test requires equity method investors to continue to assess impairment of
investments in investees by considering whether declines in the fair values of
those investments, versus carrying values, may be other than temporary in
nature. The caption "Investments" in our accompanying consolidated balance
sheets includes $150.3 million of equity method goodwill as of both December 31,
2004, and December 31, 2003.


                                      127
<PAGE>


     Our intangible assets include goodwill, lease value, contracts and
agreements. All of our intangible assets having definite lives are being
amortized on a straight-line basis over their estimated useful lives. Following
is information related to our intangible assets still subject to amortization
and our goodwill (in thousands):


                                              December 31,
                                         --------------------
                                            2004       2003
                                         ---------  ---------
         Goodwill
         Gross carrying amount......     $ 746,980  $ 743,652
         Accumulated amortization...       (14,142)   (14,142)
                                         ---------  ---------
         Net carrying amount........       732,838    729,510
                                         ---------  ---------

         Lease value
         Gross carrying amount......         6,592      6,592
         Accumulated amortization...        (1,028)      (888)
                                         ---------  ---------
         Net carrying amount........         5,564      5,704
                                         ---------  ---------

         Contracts and other
         Gross carrying amount......        10,775      7,801
         Accumulated amortization...        (1,055)      (303)
                                         ---------  ---------
         Net carrying amount........         9,720      7,498
                                         ---------  ---------

         Total intangibles, net.....     $ 748,122  $ 742,712
                                         =========  =========

<TABLE>
<CAPTION>

     Changes in the carrying amount of goodwill for each of the two years ended
December 31, 2003 and 2004 are summarized as follows (in thousands):

                                      Products     Natural Gas
                                     Pipelines      Pipelines        CO2        Terminals       Total
                                     -----------   -----------   -----------   -----------    -----------

<S>                                  <C>           <C>           <C>           <C>            <C>
Balance as of December 31, 2002...   $   263,182   $   253,358   $    46,101   $   153,969    $   716,610
  Goodwill acquired...............             -             -             -        12,900         12,900
  Impairments.....................             -             -             -             -              -
                                     -----------   -----------   -----------   -----------    -----------
Balance as of December 31, 2003...   $   263,182   $   253,358   $    46,101   $   166,869    $   729,510
  Goodwill acquired...............             -             -             -         6,368          6,368
  Disposals - purchase price adjs.             -        (3,040)            -             -         (3,040)
  Impairments.....................             -             -             -             -              -
                                     -----------   -----------   -----------   -----------    -----------
Balance as of December 31, 2004...   $   263,182   $   250,318   $    46,101   $   173,237    $   732,838
                                     ===========   ===========   ===========   ===========    ===========

</TABLE>


   Amortization expense on intangibles consists of the following (in thousands):

                                          Year Ended December 31,
                                        ---------------------------
                                          2004      2003     2002
                                        --------  -------- --------
           Goodwill.................    $      -  $     -  $      -
           Lease value..............         140      140       140
           Contracts and other......         752       64        40
                                        --------  -------  --------
           Total amortization.......    $    892  $   204  $    180
                                        ========  =======  ========

     As of December 31, 2004, our weighted average amortization period for our
intangible assets is approximately 24 years. Our estimated amortization expense
for these assets for each of the next five fiscal years is approximately $1.0
million.

     Had SFAS No. 142 been in effect prior to January 1, 2002, our limited
partners' interest in net income and net income per unit would not have differed
from the reported amounts.


9.  Debt

    Our debt and credit facility as of December 31, 2004, consisted primarily
of:

    o   a $1.25 billion unsecured five-year credit facility due August 18, 2009;


                                      128
<PAGE>


     o    $200 million of 8.00% Senior Notes due March 15, 2005;

     o    $40 million of Plaquemines, Louisiana Port, Harbor, and Terminal
          District Revenue Bonds due March 15, 2006 (our 66 2/3% owned
          subsidiary, International Marine Terminals, is the obligor on the
          bonds);

     o    $250 million of 5.35% Senior Notes due August 15, 2007;

     o    $20 million of 7.84% Senior Notes, with a final maturity of July 2008
          (our subsidiary, Central Florida Pipe Line LLC, is the obligor on the
          notes);

     o    $250 million of 6.30% Senior Notes due February 1, 2009;

     o    $5.3 million of Illinois Development Revenue Bonds due January 1, 2010
          (our subsidiary, Arrow Terminals L.P., is the obligor on the bonds);

     o    $250 million of 7.50% Senior Notes due November 1, 2010;

     o    $700 million of 6.75% Senior Notes due March 15, 2011;

     o    $450 million of 7.125% Senior Notes due March 15, 2012;

     o    $500 million of 5.00% Senior Notes due December 15, 2013;

     o    $500 million of 5.125% Senior Notes due November 15, 2014;

     o    $25 million of New Jersey Economic Development Revenue Refunding Bonds
          due January 15, 2018 (our subsidiary, Kinder Morgan Liquids Terminals
          LLC, is the obligor on the bonds);

     o    $23.7 million of tax-exempt bonds due April 1, 2024 (our subsidiary,
          Kinder Morgan Operating L.P. "B," is the obligor on the bonds);

     o    $300 million of 7.40% Senior Notes due March 15, 2031;

     o    $300 million of 7.75% Senior Notes due March 15, 2032;

     o    $500 million of 7.30% Senior Notes due August 15, 2033; and

     o    a $1.25 billion short-term commercial paper program (supported by our
          credit facility, the amount available for borrowing under our credit
          facility is reduced by our outstanding commercial paper borrowings).

     Our outstanding short-term debt as of December 31, 2004 was $621.2 million.
The balance consisted of:

     o    $416.9 million of commercial paper borrowings;

     o    $200 million of 8.00% Senior Notes due March 15, 2005;

     o    $5 million under the Central Florida Pipeline LLC Notes; and

     o    an offset of $0.7 million (which represents the net of other
          borrowings and the accretion of discounts on our senior note
          issuances).

     As of December 31, 2004, we intended and had the ability to refinance all
of our short-term debt on a long-term basis under our unsecured long-term credit
facility. Accordingly, such amounts have been classified as long-term debt in
our accompanying consolidated balance sheet. The weighted average interest rate
on all of our borrowings was approximately 4.4702% during 2004 and 4.4924%
during 2003.


                                      129
<PAGE>


     Credit Facilities

     As of December 31, 2002, we had two outstanding credit facilities. The two
facilities consisted of a $530 million unsecured 364-day credit facility due
October 14, 2003, and a $445 million unsecured three-year credit facility due
October 15, 2005. There were no borrowings under either credit facility as of
December 31, 2002.

     On May 5, 2003, we increased the borrowings available under our two credit
facilities by $75 million as follows:

     o    our $530 million unsecured 364-day credit facility was increased to
          $570 million; and

     o    our $445 million unsecured three-year credit facility was increased to
          $480 million.

     Our $570 million unsecured 364-day credit facility expired October 14,
2003. On that date, we obtained a new $570 million unsecured 364-day credit
facility due October 12, 2004. As of December 31, 2003, we had two credit
facilities totaling $1.05 billion in committed credit lines, consisting of the
$570 million unsecured 364-day credit facility due October 12, 2004, and the
$480 million unsecured three-year credit facility due October 15, 2005. There
were no borrowings under either credit facility as of December 31, 2003.

     On August 18, 2004, we replaced our existing bank facilities with a $1.25
billion five-year, unsecured revolving credit facility due August 18, 2009.
Similar to our previous credit facilities, our current credit facility is with a
syndicate of financial institutions and Wachovia Bank, National Association is
the administrative agent. There were no borrowings under our five-year credit
facility as of December 31, 2004.

     Our five-year credit facility also permits us to obtain bids for fixed rate
loans from members of the lending syndicate. Interest on our credit facility
accrues at our option at a floating rate equal to either:

     o    the administrative agent's base rate (but not less than the Federal
          Funds Rate, plus 0.5%); or

     o    LIBOR, plus a margin, which varies depending upon the credit rating of
          our long-term senior unsecured debt.

    The amount available for borrowing under our credit facility as of December
31, 2004 was reduced by:

     o    our outstanding commercial paper borrowings ($416.9 million as of
          December 31, 2004);

     o    a $50 million letter of credit that supports our hedging of commodity
          price risks involved from the sale of natural gas, natural gas
          liquids, oil and carbon dioxide;

     o    a $25.9 million letter of credit entered into on December 23, 2002
          that supports Nassau County, Florida Ocean Highway and Port Authority
          tax-exempt bonds (associated with the operations of our bulk terminal
          facility located at Fernandina Beach, Florida);

     o    a $24.1 million letter of credit that supports Kinder Morgan Operating
          L.P. "B"'s tax-exempt bonds;

     o    a $1 million letter of credit entered into on December 13, 2004 that
          supports a workers' compensation insurance policy;

     o    a $0.3 million letter of credit entered into on December 3, 2004 that
          supports an equipment rental obligation related to our bulk terminal
          facility located at Fairless Hills, Pennsylvania; and

     o    a $0.2 million letter of credit entered into on June 4, 2003 that
          supports a workers' compensation insurance policy.

   Our credit facility included the following restrictive covenants as of
December 31, 2004:

     o    requirements to maintain certain financial ratios:


                                      130
<PAGE>


     o    total debt divided by earnings before interest, income taxes,
          depreciation and amortization for the preceding four quarters may not
          exceed 5.0;

     o    total indebtedness of all consolidated subsidiaries shall at no time
          exceed 15% of consolidated indebtedness; and

     o    consolidated indebtedness shall at no time exceed 62.5% of total
          capitalization;

     o    certain limitations on entering into mergers, consolidations and sales
          of assets;

     o    limitations on granting liens; and

     o    prohibitions on making any distribution to holders of units if an
          event of default exists or would exist upon making such distribution.

     In addition to normal repayment covenants, under the terms of our credit
facility, the occurrence at any time of any of the following would constitute an
event of default:

     o    our failure to make required payments of any item of indebtedness or
          any payment in respect of any hedging agreement, provided that the
          aggregate outstanding principal amount for all such indebtedness or
          payment obligations in respect of all hedging agreements is equal to
          or exceeds $75 million;

     o    our general partner's failure to make required payments of any item of
          indebtedness, provided that the aggregate outstanding principal amount
          for all such indebtedness is equal to or exceeds $75 million;

     o    adverse judgments rendered against us for the payment of money in an
          aggregate amount in excess of $75 million, if this same amount remains
          undischarged for a period of thirty consecutive days during which
          execution shall not be effectively stayed; and

     o    voluntary or involuntary commencements of any proceedings or petitions
          seeking our liquidation, reorganization or any other similar relief
          under any federal, state or foreign bankruptcy, insolvency,
          receivership or similar law.

     Excluding the relatively non-restrictive specified negative covenants and
events of defaults, our credit facility does not contain material adverse change
clauses or any provisions designed to protect against a situation where a party
to an agreement is unable to find a basis to terminate that agreement while its
counterparty's impending financial collapse is revealed and perhaps hastened
through the default structure of some other agreement.

     None of our debt is subject to payment acceleration as a result of any
change to our credit ratings. However, the margin that we pay with respect to
LIBOR-based borrowings under our credit facility varies with our credit ratings.

     Interest Rate Swaps

     Information on our interest rate swaps is contained in Note 14.

     Commercial Paper Program

     As of December 31, 2003, our commercial paper program provided for the
issuance of up to $1.05 billion of commercial paper, and on that date, we had
$426.1 million of commercial paper outstanding with an average interest rate of
1.1803%. On October 15, 2004, we increased our commercial paper program by $200
million to provide for the issuance of up to $1.25 billion. Our $1.25 billion
unsecured 5-year credit facility supports our commercial paper program, and
borrowings under our commercial paper program reduce the borrowings allowed
under our credit facility. As of December 31, 2004, we had $416.9 million of
commercial paper outstanding with an average interest rate of 2.2856%. The
borrowings under our commercial paper program were used principally to finance
the acquisitions we made during 2003 and 2004.


                                      131
<PAGE>


     Senior Notes

     On November 21, 2003, we closed a public offering of $500 million in
principal amount of 5% senior notes due December 15, 2013 at a price to the
public of 99.363%. In the offering, we received proceeds, net of underwriting
discounts and commissions, of approximately $493.6 million. We used the proceeds
to reduce the outstanding balance of our commercial paper borrowings.

     On November 12, 2004, we closed a public offering of $500 million in
principal amount of 5.125% senior notes due November 15, 2014 at a price to the
public of 99.914%. In the offering, we received proceeds, net of underwriting
discounts and commissions, of approximately $496.3 million. We used the proceeds
to reduce the outstanding balance on our commercial paper borrowings.

     As of December 31, 2004, the outstanding balance on the various series of
our senior notes was as follows (in millions):

           8.00% senior notes due March 15, 2005......   $   200.0
           5.35% senior notes due August 15, 2007.....       249.9
           6.30% senior notes due February 1, 2009....       249.7
           7.50% senior notes due November 1, 2010....       249.1
           6.75% senior notes due March 15, 2011......       698.7
           7.125% senior notes due March 15, 2012.....       448.5
           5.00% senior notes due December 15, 2013...       497.2
           5.125% senior notes due November 15, 2014..       499.6
           7.40% senior notes due March 15, 2031......       299.3
           7.75% senior notes due March 15, 2032......       298.6
           7.30% senior notes due August 15, 2033.....       499.0
                                                         ---------
             Total....................................   $ 4,189.6
                                                         =========

  SFPP, L.P. Debt

     In December 2003, SFPP, L.P. prepaid the $37.1 million balance outstanding
under its Series F notes, plus $2.0 million for interest, as a result of its
taking advantage of certain optional prepayment provisions without penalty. The
annual interest rate on the Series F notes was 10.70%, the maturity was December
2004, and interest was payable semiannually in June and December. We had agreed
as part of the acquisition of SFPP, L.P.'s operations (which constitute a
significant portion of our Pacific operations) not to take actions with respect
to $190 million of SFPP, L.P.'s debt that would cause adverse tax consequences
for the prior general partner of SFPP, L.P. The Series F notes were
collateralized by mortgages on substantially all of the properties of SFPP, L.P.
and contained certain covenants limiting the amount of additional debt or equity
that may be issued by SFPP, L.P. and limiting the amount of cash distributions,
investments, and property dispositions by SFPP, L.P.

     Kinder Morgan Wink Pipeline, L.P. Debt

     Effective August 31, 2004, we acquired all of the partnership interests in
Kaston Pipeline Company, L.P., which we renamed Kinder Morgan Wink Pipeline,
L.P. (see Note 3). As part of our purchase price, we assumed Kaston's $9.5
million note payable to Western Refining Company, L.P. In September 2004, we
paid the $9.5 million outstanding balance under the note, and following our
repayment of the note, Kinder Morgan Wink Pipeline, L.P. had no outstanding
debt.

     International Marine Terminals Debt

     Since February 1, 2002, we have owned a 66 2/3% interest in International
Marine Terminals partnership (see Note 3). The principal assets owned by IMT are
dock and wharf facilities financed by the Plaquemines Port, Harbor and Terminal
District (Louisiana) $40,000,000 Adjustable Rate Annual Tender Port Facilities
Revenue Refunding Bonds (International Marine Terminals Project) Series 1984A
and 1984B. The bonds mature on March 15, 2006. The bonds are backed by two
letters of credit issued by KBC Bank N.V. On March 19, 2002, an Amended and
Restated Letter of Credit Reimbursement Agreement relating to the letters of
credit in the amount of $45.5 million was entered into by IMT and KBC Bank. In
connection with that agreement, we agreed to guarantee the obligations

                                      132
<PAGE>


of IMT in proportion to our ownership interest. Our obligation is approximately
$30.3 million for principal, plus interest and other fees.

     Central Florida Pipeline LLC Debt

     Effective January 1, 2001, we acquired Central Florida Pipeline LLC. As
part of our purchase price, we assumed an aggregate principal amount of $40
million of senior notes originally issued to a syndicate of eight insurance
companies. The senior notes have a fixed annual interest rate of 7.84% with
repayments in annual installments of $5 million beginning July 23, 2001. The
final payment is due July 23, 2008. Interest is payable semiannually on January
1 and July 23 of each year. As of December 31, 2003, Central Florida's
outstanding balance under the senior notes was $25.0 million. In July 2004, we
made an annual repayment of $5.0 million and as of December 31, 2004, Central
Florida's outstanding balance under the senior notes was $20.0 million.

     Kinder Morgan River Terminals LLC

     Effective October 6, 2004, we acquired Global Materials Services LLC and
its consolidated subsidiaries (see Note 3). We renamed Global Materials Services
LLC as Kinder Morgan River Terminals LLC, and as part of our purchase price, we
assumed debt of $33.7 million, consisting of third-party notes payables, current
and non-current bank borrowings, and long-term bonds payable. In October 2004,
we paid $28.4 million of the assumed debt and following these repayments, the
only remaining outstanding debt was a $5.3 million principal amount of
Adjustable Rate Industrial Development Revenue Bonds issued by the Illinois
Development Finance Authority. Our subsidiary, Arrow Terminals L.P., is the
obligor on these bonds. The bonds have a maturity date of January 1, 2010, and
interest on these bonds is paid and computed quarterly at the Bond Market
Association Municipal Swap Index. The bonds are collateralized by a first
mortgage on assets of Arrow's Chicago operations and a third mortgage on assets
of Arrow's Pennsylvania operations. As of December 31, 2004, the interest rate
was 1.674%. The bonds are also backed by a $5.4 million letter of credit issued
by JP Morgan Chase that backs-up the $5.3 million principal amount of the bonds
and $0.1 million of interest on the bonds for up to 45 days computed at 12% on a
per annum basis on the principal thereof.

     Kinder Morgan Liquids Terminals LLC Debt

     Effective January 1, 2001, we acquired Kinder Morgan Liquids Terminals LLC.
As part of our purchase price, we assumed debt of $87.9 million, consisting of
five series of tax-exempt industrial revenue bonds. Kinder Morgan Liquids
Terminals LLC was the obligor on the bonds, which consisted of the following:

     o    $4.1 million of 7.30% New Jersey Industrial Revenue Bonds due
          September 1, 2019;

     o    $59.5 million of 6.95% Texas Industrial Revenue Bonds due February 1,
          2022;

     o    $7.4 million of 6.65% New Jersey Industrial Revenue Bonds due
          September 1, 2022;

     o    $13.3 million of 7.00% Louisiana Industrial Revenue Bonds due March 1,
          2023; and

     o    $3.6 million of 6.625% Texas Industrial Revenue Bonds due February 1,
          2024.

     In May 2004, we exercised our right to call and retire all of the
industrial revenue bonds (other than the $3.6 million of 6.625% bonds due
February 1, 2024) prior to maturity at a redemption price of $84.3 million, plus
approximately $1.9 million for interest, prepayment premiums and redemption
fees. In October 2004, we exercised our right to call and retire the remaining
$3.6 million of bonds due February 1, 2024 prior to maturity at a redemption
price of $3.6 million, plus approximately $0.1 million for interest, prepayment
premiums and redemption fees. For both of these redemptions and retirements, we
borrowed the necessary funds under our commercial paper program. Pursuant to
Accounting Principles Board Opinion No. 26, "Early Extinguishment of Debt," we
recognized the $1.6 million excess of our reacquisition price over both the
carrying value of the bonds and unamortized debt issuance costs as a loss on
bond repurchases and we included this amount under the caption "Other, net" in
our accompanying consolidated statement of income.


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<PAGE>


     In November 2001, we acquired a liquids terminal in Perth Amboy, New Jersey
from Stolthaven Perth Amboy Inc. and Stolt-Nielsen Transportation Group, Ltd. As
part of our purchase price, we assumed $25.0 million of Economic Development
Revenue Refunding Bonds issued by the New Jersey Economic Development Authority.
These bonds have a maturity date of January 15, 2018. Interest on these bonds is
computed on the basis of a year of 365 or 366 days, as applicable, for the
actual number of days elapsed during Commercial Paper, Daily or Weekly Rate
Periods and on the basis of a 360-day year consisting of twelve 30-day months
during a Term Rate Period. As of December 31, 2004, the interest rate was
1.5288%. We have an outstanding letter of credit issued by Citibank in the
amount of $25.4 million that backs-up the $25.0 million principal amount of the
bonds and $0.4 million of interest on the bonds for up to 42 days computed at
12% on a per annum basis on the principal thereof.

     Kinder Morgan Operating L.P. "B" Debt

     This $23.7 million principal amount of tax-exempt bonds due April 1, 2024
was issued by the Jackson-Union Counties Regional Port District. These bonds
bear interest at a weekly floating market rate. As of December 31, 2004, the
interest rate on these bonds was 1.704%. An outstanding letter of credit issued
under our credit facilities supports our tax-exempt bonds. This letter of credit
reduces the amount available for borrowing under our credit facilities.

     Maturities of Debt

     The scheduled maturities of our outstanding debt, excluding market value of
interest rate swaps, as of December 31, 2004, are summarized as follows (in
thousands):

                  2005......  $  621,168
                  2006......      43,860
                  2007......     253,874
                  2008......       3,897
                  2009......     248,974
                  Thereafter   3,550,637
                              ----------
                  Total.....  $4,722,410
                              ==========

     Fair Value of Financial Instruments

     Fair value as used in SFAS No. 107 "Disclosures About Fair Value of
Financial Instruments" represents the amount at which an instrument could be
exchanged in a current transaction between willing parties. The estimated fair
value of our long-term debt, excluding market value of interest rate swaps, is
based upon prevailing interest rates available to us as of December 31, 2004 and
December 31, 2003 and is disclosed below.

                              December 31, 2004          December 31, 2003
                         -------------------------  ----------------------
                           Carrying     Estimated     Carrying      Estimated
                             Value     Fair Value       Value      Fair Value
                         -----------   ----------    ----------    ----------
                                            (In thousands)
          Total Debt      $4,722,410   $5,139,747    $4,318,926    $4,889,478


10.  Pensions and Other Post-retirement Benefits

     In connection with our acquisition of SFPP, L.P. and Kinder Morgan Bulk
Terminals, Inc. in 1998, we acquired certain liabilities for pension and
post-retirement benefits. We provide medical and life insurance benefits to
current employees, their covered dependents and beneficiaries of SFPP and Kinder
Morgan Bulk Terminals. We also provide the same benefits to former salaried
employees of SFPP. Additionally, we will continue to fund these costs for those
employees currently in the plan during their retirement years. SFPP's
post-retirement benefit plan is frozen and no additional participants may join
the plan.

     The noncontributory defined benefit pension plan covering the former
employees of Kinder Morgan Bulk Terminals is the Kinder Morgan, Inc. Retirement
Plan. The benefits under this plan are based primarily upon years of service and
final average pensionable earnings; however, benefit accruals were frozen as of
December 31, 1998.


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<PAGE>


   Net periodic benefit costs and weighted-average assumptions for these plans
include the following components (in thousands):

                                          Other Post-retirement Benefits
                                  ----------------------------------------------
                                     2004              2003              2002
                                  ------------    --------------    ------------
Net periodic benefit cost
Service cost......................  $  111            $   41            $  165
Interest cost.....................     389               807               906
Expected return on plan assets....      --                --                --
Amortization of prior service cost    (125)             (622)             (545)
Actuarial (gain)..................    (976)               --                --
                                    -------           ------            ------
Net periodic benefit cost.........  $ (601)           $  226            $  526
                                    =======           ======            ======

Additional amounts recognized
  Curtailment (gain) loss.........  $   --            $   --            $   --
Weighted-average assumptions as of
  December 31:
Discount rate.....................    5.75%             6.00%             6.50%
Expected return on plan assets....      --                --                --
Rate of compensation increase.....    3.9%              3.9%              3.9%

   Information concerning benefit obligations, plan assets, funded status and
recorded values for these plans follows (in thousands):

                                        Other Post-retirement Benefits
                                        ------------------------------
                                             2004              2003
                                        --------------    ------------
Change in benefit obligation
Benefit obligation at Jan. 1............   $  6,176          $ 13,275
Service cost............................        111                41
Interest cost...........................        389               807
Participant contributions...............        166               144
Amendments..............................       (207)             (190)
Actuarial (gain) loss...................       (632)           (7,456)
Benefits paid from plan assets..........       (448)             (445)
                                           --------          --------
Benefit obligation at Dec. 31...........   $  5,555          $  6,176
                                           ========          ========

Change in plan assets
Fair value of plan assets at Jan. 1.....   $     --          $     --
Actual return on plan assets............         --                --
Employer contributions..................        282               301
Participant contributions...............        166               144
Benefits paid from plan assets..........       (448)             (445)
                                           --------          --------
Fair value of plan assets at Dec. 31....   $     --          $     --
                                           =========         =========

                                        Other Post-retirement Benefits
                                        ------------------------------
                                             2004              2003
                                        --------------    ------------
Funded status...........................   $ (5,555)         $ (6,176)
Unrecognized net actuarial (gain) loss..     (6,383)           (6,728)
Unrecognized prior service (benefit)....       (710)             (627)
Adj. for 4th qtr. Employer
  contributions.........................         91                72
                                           --------          --------
Accrued benefit cost....................   $(12,557)         $(13,459)
                                           ========          ========

     The unrecognized prior service credit is amortized on a straight-line basis
over the average future lifetime until full eligibility for benefits. For
measurement purposes, a 10% annual rate of increase in the per capita cost of
covered health care benefits was assumed for 2005. The rate was assumed to
decrease gradually to 5% by 2010 and remain at that level thereafter.

     Assumed health care cost trend rates have a significant effect on the
amounts reported for the health care plans. A 1% change in assumed health care
cost trend rates would have the following effects (in thousands):

                                                   1-Percentage     1-Percentage
                                                 Point Increase   Point Decrease
                                                 --------------   --------------
Effect on total of service and interest cost
  components.....................................    $   34           $  (29)
Effect on postretirement benefit obligation......    $  552           $ (466)


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<PAGE>


     Amounts recognized in our consolidated balance sheets consist of (in
thousands):

                                                     As of December 31,
                                             --------------------------------
                                                  2004                2003
                                             --------------      ------------
Prepaid benefit cost......................    $       -          $       -
Accrued benefit liability.................        (12,557)           (13,459)
Intangible asset..........................            -                  -
Accumulated other comprehensive income....            -                  -
                                                  --------           --------
                                                      -                  -
  Net amount recognized as of Dec. 31.....    $   (12,557)       $   (13,459)
                                                  ========           ========

     We expect to contribute approximately $0.3 million to our post-retirement
benefit plans in 2005. The following benefit payments, which reflect expected
future service, as appropriate, are expected to be paid (in thousands):

              Other Post-retirement Benefits
             -------------------------------
             2005........         $       360
             2006........                 373
             2007........                 364
             2008........                 371
             2009........                 366
             2010-2014...               1,818
                                  -----------
             Total.......         $     3,652
                                  ===========

     Multiemployer Plans

     As a result of acquiring several terminal operations, primarily our
acquisition of Kinder Morgan Bulk Terminals, Inc. effective July 1, 1998, we
participate in several multi-employer pension plans for the benefit of employees
who are union members. We do not administer these plans and contribute to them
in accordance with the provisions of negotiated labor contracts. Other benefits
include a self-insured health and welfare insurance plan and an employee health
plan where employees may contribute for their dependents' health care costs.
Amounts charged to expense for these plans were $5.5 million for the year ended
2004 and $4.9 million for the year ended 2003.

     Kinder Morgan Savings Plan

     The Kinder Morgan Savings Plan permits all full-time employees of KMGP
Services Company, Inc. and KMI to contribute between 1% and 50% of base
compensation, on a pre-tax basis, into participant accounts. In addition to a
mandatory contribution equal to 4% of base compensation per year for most plan
participants, KMGP Services Company, Inc. and KMI may make discretionary
contributions in years when specific performance objectives are met. Certain
employees' contributions are based on collective bargaining agreements. Our
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. No discretionary contributions were made to individual accounts for
2004.

     At its July 2004 meeting, the compensation committee of the KMI board of
directors approved that contingent upon its approval at it's July 2005 meeting,
each eligible employee will receive an additional 1% company contribution based
on eligible base pay to his or her Savings Plan account each pay period
beginning with the first pay period after the July 2005 Committee meeting. The
1% contribution will be in the form of KMI common stock (the same as the current
4% contribution). The 1% contribution will be in addition to, and will not
change or otherwise impact, the annual 4% contribution that eligible employees
currently receive. It may be converted to any other Savings Plan investment fund
at any time and it will vest on the second anniversary of the employee's date of
hire. Since this additional 1% company contribution is discretionary,
compensation committee approval will be required annually for each contribution.

     The total amount charged to expense for our Savings Plan was $6.5 million
during 2004 and $5.9 million during 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.

                                       136

<PAGE>


     Cash Balance Retirement Plan

     Employees of KMGP Services Company, Inc. and KMI are also eligible to
participate in a Cash Balance Retirement Plan. Certain employees continue to
accrue benefits through a career-pay formula, "grandfathered" according to age
and years of service on December 31, 2000, or collective bargaining
arrangements. All other employees accrue benefits through a personal retirement
account in the Cash Balance Retirement Plan. Employees with prior service and
not grandfathered converted to the Cash Balance Retirement Plan on January 1,
2001, 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 3% of eligible
compensation every pay period. In addition, discretionary contributions are made
to the plan based on our and KMI's performance. No discretionary contributions
were made for 2004 performance. Interest is credited to the personal retirement
accounts at the 30-year U.S. Treasury bond rate, or an approved substitute, in
effect each year. Employees become fully vested in the plan after five years,
and they may take a lump sum distribution upon termination of employment or
retirement.


11.  Partners' Capital

     As of December 31, 2004 and 2003, our partners' capital consisted of the
following limited partner units:

                                                  December 31,      December 31,
                                                    2004                2003
                                                -----------        -----------
             Common units..................     147,537,908        134,729,258
             Class B units.................       5,313,400          5,313,400
             i-units.......................      54,157,641         48,996,465
                                                -----------        -----------
               Total limited partner units.     207,008,949        189,039,123
                                                ===========        ===========

     The total limited partner units represent our limited partners' interest,
an effective 98% economic interest in us, exclusive of our general partner's
incentive distribution rights. Our general partner has an effective 2% interest
in us, excluding its incentive distribution rights.

     As of December 31, 2004, our common unit total consisted of 133,182,173
units held by third parties, 12,631,735 units held by KMI and its consolidated
affiliates (excluding our general partner) and 1,724,000 units held by our
general partner. Our Class B units were held entirely by KMI and our i-units
were held entirely by KMR.

     Our total common units outstanding at December 31, 2003, consisted of
121,773,523 units held by third parties, 11,231,735 units held by KMI and its
consolidated affiliates (excluding our general partner) and 1,724,000 units held
by our general partner. Our Class B units were held entirely by KMI and our
i-units were held entirely by KMR.

     In June 2003, we issued, in a public offering, 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 9, 2004, we issued, in a public offering, 5,300,000 of our
common units at a price of $46.80 per unit, less commissions and underwriting
expenses. After commissions and underwriting expenses, we received net proceeds
of $237.8 million for the issuance of these common units. We used the proceeds
to reduce the borrowings under our commercial paper program.

     On November 10, 2004, we issued, in a public offering, 5,500,000 of our
common units. On December 8, 2004, we issued an additional 575,000 units upon
exercise by the underwriters of an over-allotment option. We issued these
6,075,000 units at a price of $46.00 per unit, less commissions and underwriting
expenses. After commissions and underwriting expenses, we received net proceeds
of $268.3 million and we used the proceeds to reduce the borrowings under our
commercial paper program.


                                      137

<PAGE>


     All of our Class B units were issued in December 2000 to KMI. The Class B
units are similar to our common units except that they are not eligible for
trading on the New York Stock Exchange.

     Our i-units are a separate class of limited partner interests in us. All of
our i-units are owned by KMR and are not publicly traded. In accordance with its
limited liability company agreement, KMR's activities are restricted to being a
limited partner in us, and controlling and managing our business and affairs and
the business and affairs of our operating limited partnerships and their
subsidiaries. Through the combined effect of the provisions in our partnership
agreement and the provisions of KMR's limited liability company agreement, the
number of outstanding KMR shares and the number of i-units will at all times be
equal.

     On March 25, 2004, KMR issued an additional 360,664 of its shares at a
price of $41.59 per share, less closing fees and commissions. The net proceeds
from the offering were used to buy additional i-units from us. After closing and
commission expenses, we received net proceeds of $14.9 million for the issuance
of 360,664 i-units. We used the proceeds from the i-unit issuance to reduce the
borrowings under our commercial paper program.

     On November 10, 2004, KMR issued an additional 1,300,000 of its shares at a
price of $41.29 per share, less closing fees and commissions. The net proceeds
from the offering were used to buy additional i-units from us. We received
proceeds of $52.6 million for the issuance of 1,300,000 i-units. We used the
proceeds from the i-unit issuance to reduce the borrowings under our commercial
paper program.

     Under the terms of our partnership agreement, we agreed that we will not,
except in liquidation, make a distribution on an i-unit other than in additional
i-units or a security that has in all material respects the same rights and
privileges as our i-units. The number of i-units we distribute to KMR is based
upon the amount of cash we distribute to the owners of our common units. When
cash is paid to the holders of our common units, we will issue additional
i-units to KMR. The fraction of an i-unit paid per i-unit owned by KMR will have
a value based on the cash payment on the common unit as described following.

     The cash equivalent of distributions of i-units will be treated as if it
had actually been distributed for purposes of determining the distributions to
our general partner. We will not distribute the cash to the holders of our
i-units but will retain the cash for use in our business. If additional units
are distributed to the holders of our common units, we will issue an equivalent
amount of i-units to KMR based on the number of i-units it owns. Based on the
preceding, KMR received a distribution of 929,105 i-units on November 12, 2004.
These additional i-units distributed were based on the $0.73 per unit
distributed to our common unitholders on that date. During the year ended
December 31, 2004, KMR received distributions of 3,500,512 i-units. These
additional i-units distributed were based on the $2.81 per unit distributed to
our common unitholders during 2004.

     For the purposes of maintaining partner capital accounts, our partnership
agreement specifies that items of income and loss shall be allocated among the
partners, other than owners of i-units, in accordance with their percentage
interests. Normal allocations according to percentage interests are made,
however, only after giving effect to any priority income allocations in an
amount equal to the incentive distributions that are allocated 100% to our
general partner. Incentive distributions are generally defined as all cash
distributions paid to our general partner that are in excess of 2% of the
aggregate value of cash and i-units being distributed.

     Incentive distributions allocated to our general partner are determined by
the amount quarterly distributions to unitholders exceed certain specified
target levels. For the years ended December 31, 2004, 2003 and 2002, we declared
distributions of $2.87, $2.63 and $2.435 per unit, respectively. Our
distributions to unitholders for 2004, 2003 and 2002 required incentive
distributions to our general partner in the amount of $390.7 million, $322.8
million and $267.4 million, respectively. The increased incentive distributions
paid for 2004 over 2003 and 2003 over 2002 reflect the increase in amounts
distributed per unit as well as the issuance of additional units. Distributions
for the fourth quarter of each year are declared and paid during the first
quarter of the following year.

     On January 18, 2005, we declared a cash distribution of $0.74 per unit for
the quarterly period ended December 31, 2004. This distribution was paid on
February 14, 2005, to unitholders of record as of January 31, 2005. Our common
unitholders and Class B unitholders received cash. KMR, our sole i-unitholder,
received a distribution in the form of additional i-units based on the $0.74
distribution per common unit. The number of i-units distributed


                                      138
<PAGE>


was 955,936. For each outstanding i-unit that KMR held, a fraction of an i-unit
(0.017651) was issued. The fraction was determined by dividing:

     o    $0.74, the cash amount distributed per common unit

by

     o    $41.924, the average of KMR's limited liability shares' closing market
          prices from January 12-26, 2005, the ten consecutive trading days
          preceding the date on which the shares began to trade ex-dividend
          under the rules of the New York Stock Exchange.

     This February 14, 2005 distribution required an incentive distribution to
our general partner in the amount of $106.0 million. Since this distribution was
declared after the end of the quarter, no amount is shown in our December 31,
2004 balance sheet as a distribution payable.


12.  Related Party Transactions

     General and Administrative Expenses

     KMGP Services Company, Inc., a subsidiary of our general partner, provides
employees and Kinder Morgan Services LLC, a wholly owned subsidiary of KMR,
provides centralized payroll and employee benefits services to us, our operating
partnerships and subsidiaries, Kinder Morgan G.P., Inc. and KMR (collectively,
the "Group"). Employees of KMGP Services Company, Inc. are assigned to work for
one or more members of the Group. The direct costs of all compensation, benefits
expenses, employer taxes and other employer expenses for these employees are
allocated and charged by Kinder Morgan Services LLC to the appropriate members
of the Group, and the members of the Group reimburse 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 KMI, and the related administrative costs are allocated
to members of the Group in accordance with existing expense allocation
procedures. The effect of these arrangements is that each member of the Group
bears the direct compensation and employee benefits costs of its assigned or
partially assigned employees, as the case may be, while also bearing its
allocable share of administrative costs. Pursuant to our limited partnership
agreement, we provide reimbursement for our share of these administrative costs
and such reimbursements will be accounted for as described above. Additionally,
we reimburse KMR with respect to costs incurred or allocated to KMR in
accordance with our limited partnership agreement, the delegation of control
agreement among our general partner, KMR, us and others, and KMR's limited
liability company agreement.

     The named executive officers of our general partner and KMR and other
employees that provide management or services to both KMI and the Group are
employed by KMI. Additionally, other KMI employees assist in the operation of
our Natural Gas Pipeline assets. These KMI employees' expenses are allocated
without a profit component between KMI and the appropriate members of the Group.

     Partnership Distributions

     Kinder Morgan G.P., Inc.

     Kinder Morgan G.P., Inc. serves as our sole general partner. Pursuant to
our partnership agreements, our general partner's interests represent a 1%
ownership interest in us, and a direct 1.0101% ownership interest in each of our
five operating partnerships. Collectively, our general partner owns an effective
2% interest in our operating partnerships, excluding incentive distributions
rights as follows:

     o    its 1.0101% direct general partner ownership interest (accounted for
          as minority interest in our consolidated financial statements); and

     o    its 0.9899% ownership interest indirectly owned via its 1% ownership
          interest in us.


                                      139
<PAGE>


     As of December 31, 2004, our general partner owned 1,724,000 common units,
representing approximately 0.83% of our outstanding limited partner units.

     Our partnership agreement requires that we distribute 100% of available
cash, as defined in our partnership agreement, to our partners within 45 days
following the end of each calendar quarter in accordance with their respective
percentage interests. Available cash consists generally of all of our cash
receipts, including cash received by our operating partnerships, 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.

     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 declared incentive
distributions for the years ended December 31, 2004, 2003 and 2002 were $390.7
million, $322.8 million and $267.4 million, respectively.

     Kinder Morgan, Inc.

     KMI, through its subsidiary Kinder Morgan (Delaware), Inc., remains the
sole stockholder of our general partner. As of December 31, 2004, KMI directly
owned 8,838,095 common units and 5,313,400 Class B units, indirectly owned
5,517,640 common units through its consolidated affiliates, including our
general partner, and owned 15,135,460 KMR shares, representing an indirect
ownership interest of 15,135,460 i-units. Together, these units represented
approximately 16.8% of our outstanding limited partner units. Including both its
general and limited


                                      140
<PAGE>


partner interests in us, at the 2004 distribution level, KMI received
approximately 51% of all quarterly distributions from us, of which approximately
41% is attributable to its general partner interest and 10% is 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.

     Kinder Morgan Management, LLC

     As of December 31, 2004, KMR, our general partner's delegate, remained the
sole owner of our 54,157,641 i-units.

     Asset Acquisitions and Sales

     2004 Kinder Morgan, Inc. Asset Contributions

     In June 2004, we bought two LM6000 gas-fired turbines and two boilers from
a subsidiary of KMI for their estimated fair market value of $21.1 million,
which we paid in cash. This equipment was a portion of the equipment that became
surplus as a result of KMI's decision to exit the power development business and
will be employed in conjunction with our CO2 business segment.

     Effective November 1, 2004, we acquired all of the partnership interests in
TransColorado Gas Transmission Company from two wholly-owned subsidiaries of
KMI. TransColorado Gas Transmission Company, a Colorado general partnership
referred to in this report as TransColorado, owned assets valued at
approximately $284.5 million. As consideration for TransColorado, we paid to KMI
$211.2 million in cash and approximately $64.0 million in units, consisting of
1,400,000 common units. We also assumed liabilities of approximately $9.3
million. The purchase price for this transaction was determined by the boards of
directors of KMR and our general partner, and KMI based on valuation parameters
used in the acquisition of similar assets. The transaction was approved
unanimously by the independent members of the boards of directors of both KMR
and our general partner, and KMI, with the benefit of advice of independent
legal and financial advisors, including the receipt of fairness opinions from
separate investment banks, specifically Goldman, Sachs & Co. and Morgan Stanley
& Co.

     In conjunction with our acquisition of TransColorado Gas Transmission
Company, KMI became a guarantor of approximately $210.8 million of our debt.

     1999 and 2000 Kinder Morgan, Inc. Asset Contributions

     In conjunction with our acquisition of Natural Gas Pipelines assets from
KMI on December 31, 1999 and 2000, KMI became a guarantor of approximately
$522.7 million of our debt. Thus, taking into consideration the guarantee of
debt associated with our TransColorado acquisition discussed above, KMI was a
guarantor of a total of approximately $733.5 million of our debt as of December
31, 2004. KMI would be obligated to perform under this guarantee only if we
and/or our assets were unable to satisfy our obligations.

     2004 Asset Sales

     In November 2004, Kinder Morgan Operating L.P. "A" sold a natural gas
gathering system to Kinder Morgan, Inc.'s retail division for $75,000. The
gathering system primarily consisted of approximately 23,000 miles of 6-inch
diameter pipeline located in Campbell County, Wyoming that was no longer being
used by Kinder Morgan Operating L.P. "A".

     Operations

     KMI or its subsidiaries operate and maintain for us the assets comprising
our Natural Gas Pipelines business segment. Natural Gas Pipeline Company of
America, a subsidiary of KMI, operates Trailblazer Pipeline Company's assets
under a long-term contract pursuant to which Trailblazer Pipeline Company incurs
the costs and expenses related to NGPL's operating and maintaining the assets.
Trailblazer Pipeline Company provides the funds for its own capital
expenditures. NGPL does not profit from or suffer loss related to its operation
of Trailblazer Pipeline Company's assets.


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     The remaining assets comprising our Natural Gas Pipelines business segment
are operated under other agreements between KMI and us. Pursuant to the
applicable underlying agreements, we pay KMI 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. On January
1, 2003, KMI began operating additional pipeline assets, including our North
System and Cypress pipeline, which are part of our Products Pipelines business
segment. The amounts paid to KMI for corporate general and administrative costs,
including amounts related to Trailblazer Pipeline Company, were $8.8 million of
fixed costs and $13.1 million of actual costs incurred for 2004, and $8.7
million of fixed costs and $10.8 million of actual costs incurred for 2003. We
estimate the total reimbursement for corporate general and administrative costs
to be paid to KMI in respect of all pipeline assets operated by KMI and its
subsidiaries for us for 2005 will be approximately $24.7 million, which includes
$5.5 million of fixed costs (adjusted for inflation) and $19.2 million of actual
costs.

     We believe the amounts paid to KMI for the services they provided each year
fairly reflect the value of the services performed. However, due to the nature
of the allocations, these reimbursements may not exactly match the actual time
and overhead spent. We believe the fixed amounts that were agreed upon at the
time the contracts were entered into were reasonable estimates of the corporate
general and administrative expenses to be incurred by KMI and its subsidiaries
in performing such services. We also reimburse KMI and its subsidiaries for
operating and maintenance costs and capital expenditures incurred with respect
to our assets.

     From time to time in the ordinary course of business, we buy and sell
pipeline and related services from KMI and its subsidiaries. Such transactions
are conducted in accordance with all applicable laws and regulations and on an
arms' length basis consistent with our policies governing such transactions.

     Certain of our business activities expose us to risks associated with
changes in the market price of natural gas, natural gas liquids, crude oil and
carbon dioxide. We perform risk management activities that involve the use of
energy financial instruments to reduce these risks and protect our profit
margins. 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 a separately designated standing
committee comprised of eleven executive-level employees of KMI or KMGP Services
Company, Inc. whose job responsibilities involve operations exposed to commodity
market risk and other external risks in the ordinary course of business. For
more information on our risk management activities see Note 14.

     Notes Receivable

     Plantation Pipe Line Company

     We own a 51.17% equity interest in Plantation Pipe Line Company. An
affiliate of ExxonMobil owns the remaining 48.83% interest. In July 2004,
Plantation repaid a $10 million note outstanding and $175 million in outstanding
commercial paper borrowings with funds of $190 million borrowed from its owners.
We loaned Plantation $97.2 million, which corresponds to our 51.17% ownership
interest, in exchange for a seven year note receivable bearing interest at the
rate of 4.72% per annum. As of December 31, 2004, the principal amount
receivable from this note was $96.3 million. We have included $2.2 million of
this balance within "Accounts, notes and interest receivable-Related Parties" on
our consolidated balance sheet. The remaining $94.1 million receivable is
included within "Notes receivable-Related Parties" on our consolidated balance
sheet.

     Coyote Gas Treating, LLC

     We own a 50% equity interest in Coyote Gas Treating, LLC, referred to in
this report as Coyote Gulch. Coyote Gulch is a joint venture, and Enterprise
Field Services LLC owns the remaining 50% equity interest. We are the managing
partner of Coyote Gulch. In June 2001, Coyote repaid the $34.2 million in
outstanding borrowings under its 364-day credit facility with funds borrowed
from its owners. We loaned Coyote $17.1 million, which corresponds to our 50%
ownership interest, in exchange for a one-year note receivable bearing interest
payable monthly at LIBOR plus a margin of 0.875%. On June 30, 2002 and June 30,
2003, the note was extended for one year. On June 30, 2004, the term of the note
was made month-to-month, and as of December 31, 2004, we included the principal
amount of $17.1 million related to this note within "Notes Receivable-Related
Parties" on our


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consolidated balance sheet. As of December 31, 2003, we included the $17.1
million receivable related to this note within "Accounts, notes and interest
receivable-Related Parties" on our consolidated balance sheet.

     Red Cedar Gas Gathering Company

     We own a 49% equity interest in the Red Cedar Gas Gathering Company. Red
Cedar is a joint venture and the Southern Ute Indian Tribe owns the remaining
51% equity interest. On December 22, 2004, we entered into a $10 million
unsecured revolving credit facility due July 1, 2005, with the Southern Ute
Indian Tribe and us, as lenders, and Red Cedar, as borrower. Subject to the
terms of the agreement, the lenders may severally, but not jointly, make
advances to Red Cedar up to a maximum outstanding principal amount of $10
million. However, as of April 1, 2005, through July 1, 2005, the maximum
outstanding principal amount will be automatically reduced to $5 million. In
January 2005, Red Cedar borrowed funds of $4 million from its owners pursuant to
this credit agreement and we loaned Red Cedar $1.96 million, which corresponds
to our 49% ownership interest. The interest on all advances made under this
agreement will be calculated as simple interest on the combined outstanding
balance of the credit agreement at 6% per annum based upon a 360 day year.

     Other

     Generally, KMR makes all decisions relating to the management and control
of our business. Our general partner owns all of KMR's voting securities and is
its sole managing member. KMI, through its wholly owned and controlled
subsidiary Kinder Morgan (Delaware), Inc., owns all the common stock of our
general partner. Certain conflicts of interest could arise as a result of the
relationships among KMR, our general partner, KMI and us. The directors and
officers of KMI have fiduciary duties to manage KMI, including selection and
management of its investments in its subsidiaries and affiliates, in a manner
beneficial to the shareholders of KMI. In general, KMR has a fiduciary duty to
manage us in a manner beneficial to our unitholders. The partnership agreements
for us and our operating partnerships contain provisions that allow KMR to take
into account the interests of parties in addition to us in resolving conflicts
of interest, thereby limiting its fiduciary duty to our unitholders, as well as
provisions that may restrict the remedies available to our unitholders for
actions taken that might, without such limitations, constitute breaches of
fiduciary duty.

     The partnership agreements provide that in the absence of bad faith by KMR,
the resolution of a conflict by KMR will not be a breach of any duties. The duty
of the directors and officers of KMI to the shareholders of KMI may, therefore,
come into conflict with the duties of KMR and its directors and officers to our
unitholders. The Audit Committee of KMR's board of directors will, at the
request of KMR, review (and is one of the means for resolving) conflicts of
interest that may arise between KMI or its subsidiaries, on the one hand, and
us, on the other hand.


13.  Leases and Commitments

     Capital Leases

     We acquired certain leases classified as capital leases as part of our
acquisition of Kinder Morgan River Terminals LLC in October 2004. We lease our
Memphis, Tennessee port facility under an agreement accounted for as a capital
lease. The lease is for 24 years and expires in 2017. Additionally, we have
approximately ten equipment leases accounted for as capital leases which expire
from 2005 to 2007.

     Amortization of assets recorded under capital leases is included with
depreciation expense. The components of property, plant and equipment recorded
under capital leases are as follows (in thousands):


                                                    December 31,
                                                    ------------
                                                        2004
                                                    -----------
                Leasehold improvements...........   $     4,089
                Machinery and equipment..........           150
                                                    -----------
                                                          4,239
                Less: Accumulated amortization...        (2,056)
                                                    -----------
                                                    $     2,183
                                                    ===========

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     Future commitments under capital lease obligations as of December 31, 2004
are as follows (in thousands):

       Year                                               Commitment
       ----                                               -----------
       2005......................                         $      228
       2006......................                                180
       2007......................                                169
       2008......................                                168
       2009......................                                168
       Thereafter................                              1,327
                                                          -----------
                                                               2,240
       Less: Amount representing interest                       (957)
                                                          -----------
       Present value of minimum capital lease payments    $    1,283
                                                          ===========

     Operating Leases

     Including probable elections to exercise renewal options, the remaining
terms on our operating leases range from one to 64 years. Future commitments
related to these leases as of December 31, 2004 are as follows (in thousands):

              Year                          Commitment
              ----                          ----------
              2005......................    $   30,450
              2006......................        26,240
              2007......................        23,571
              2008......................        19,748
              2009......................        15,381
              Thereafter................        48,788
                                            ----------
              Total minimum payments....    $  164,178
                                            ==========

     We have not reduced our total minimum payments for future minimum sublease
rentals aggregating approximately $0.6 million. Total lease and rental expenses,
including related variable charges were $39.3 million for 2004, $25.3 million
for 2003 and $21.6 million for 2002.

     Common Unit Option Plan

     During 1998, we established a common unit option plan, which provides that
key personnel of KMGP Services Company, Inc. and KMI are eligible to receive
grants of options to acquire common units. The number of common units authorized
under the option plan is 500,000. The option plan terminates in March 2008. The
options granted generally have a term of seven years, vest 40% on the first
anniversary of the date of grant and 20% on each of the next three
anniversaries, and have exercise prices equal to the market price of the common
units at the grant date.

     As of December 31, 2003, options to purchase 129,050 common units were held
by employees of KMI or KMGP Services Company, Inc. at an average exercise price
of $17.46 per unit. Outstanding options to purchase 20,000 common units were
held by two of Kinder Morgan G.P., Inc.'s three non-employee directors at an
average exercise price of $20.58 per unit. As of December 31, 2004, outstanding
options to purchase 95,400 common units were held by employees of KMI or KMGP
Services Company, Inc. at an average exercise price of $17.44 per unit.
Outstanding options to purchase 20,000 common units were held by two of Kinder
Morgan G.P., Inc.'s three non-employee directors at an average exercise price of
$20.58 per unit. As of December 31, 2004, all 115,400 outstanding options were
fully vested.

     During 2003, options to purchase 134,550 common units were exercised at an
average price of $17.06 per unit. The common units underlying these options had
an average fair market value of $38.85 per unit. During 2004, 33,650 options to
purchase common units were exercised at an average price of $17.50 per unit. The
common units underlying these options had an average fair market value of $45.92
per unit.

     We apply Accounting Principles Board Opinion No. 25, "Accounting for Stock
Issued to Employees," and related interpretations in accounting for common unit
options granted under our common unit option plan. Accordingly, we record
expense for our common unit option plan equal to the excess of the market price
of the underlying common units at the date of grant over the exercise price of
the common unit award, if any. Such excess is commonly referred to as the
intrinsic value. All of our common unit options were issued with the exercise
price


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equal to the market price of the underlying common units at the grant date and
therefore, no compensation expense has been recorded. We have not granted common
unit options since May 2000. Pro forma information regarding changes in net
income and per unit data, if the accounting prescribed by Statement of Financial
Accounting Standards No. 123 "Accounting for Stock Based Compensation," had been
applied, has not been provided because the impact is not material.

     Directors' Unit Appreciation Rights Plan

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

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

     On April 1, 2003, the date of adoption of the plan, each of KMR's three
non-employee directors were granted 7,500 unit appreciation rights. In addition,
10,000 unit appreciation rights were granted to each of KMR's three non-employee
directors on January 21, 2004, at the first meeting of the board in 2004. As of
December 31, 2004, 52,500 unit appreciation rights had been granted. No unit
appreciation rights were exercised during 2004. During the first board meeting
of 2005, the plan was terminated and replaced by the Kinder Morgan Energy
Partners, L.P. Common Unit Compensation Plan for Non-Employee Directors.

     Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for
Non-Employee Directors

     On January 18, 2005, KMR's compensation committee established the Kinder
Morgan Energy Partners, L.P. Common Unit Compensation Plan to compensate KMR's
non-employee directors for 2005. The plan is administered by KMR's compensation
committee and KMR's board has sole discretion to terminate the plan at any time.
The primary purpose of this plan was to promote our interests and the interests
of our unitholders by aligning the compensation of the non-employee members of
the board of directors of KMR with unitholders' interests. Further, since KMR's
success is dependent on its operation and management of our business and our
resulting performance, the plan is expected to align the compensation of the
non-employee members of the board with the interests of KMR's shareholders.

     The plan recognizes that the compensation to be paid to each non-employee
director is fixed by the KMR board, generally annually, and that the
compensation is expected to include an annual retainer payable in cash and other
cash compensation. Pursuant to the plan, in lieu of receiving the other cash
compensation, each non-employee director may elect to receive common units. Each
election shall be generally at or around the first board meeting in January of
each calendar year and will be effective for the entire calendar year. The
initial election under this plan was made effective January 20, 2005. A
non-employee director may make a new election each calendar year. The total
number of common units authorized under this compensation plan is 100,000.

     Each annual election shall be evidenced by an agreement, the Common Unit
Compensation Agreement, between us and each non-employee director, and this
agreement will contain the terms and conditions of each award. Pursuant to this
agreement, all common units issued under this plan are subject to forfeiture
restrictions that expire six months from the date of issuance. Until the
forfeiture restrictions lapse, common units issued under the plan may not be
sold, assigned, transferred, exchanged, or pledged by a non-employee director.
In the event the


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director's service as a director of KMR is terminated prior to the lapse of the
forfeiture restriction either for cause, or voluntary resignation, each director
shall, for no consideration, forfeit to us all common units to the extent then
subject to the forfeiture restrictions. Common units with respect to which
forfeiture restrictions have lapsed shall cease to be subject to any forfeiture
restrictions, and we will provide each director a certificate representing the
units as to which the forfeiture restrictions have lapsed. In addition, each
non-employee director shall have the right to receive distributions with respect
to the common units awarded to him under the plan, to vote such common units and
to enjoy all other unitholder rights, including during the period prior to the
lapse of the forfeiture restrictions.

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

     On January 18, 2005, the date of adoption of the plan, each of KMR's three
non-employee directors was awarded a cash retainer of $40,000 that will be paid
quarterly during 2005, and other cash compensation of $79,750. Effective January
20, 2005, each non-employee director elected to receive the other cash
compensation of $79,750 in the form of our common units and was issued 1,750
common units pursuant to the plan and its agreements (based on the $45.55
closing market price of our common units on January 18, 2005, as reported on the
New York Stock Exchange). Also, consistent with the plan, the $37.50 of other
cash compensation that did not equate to a whole common unit, based on the
January 18, 2005 $45.55 closing price, will be paid to each of the non-employee
directors as described above. No other compensation is to be paid to the
non-employee directors during 2005.

     Contingent Debt

     We apply the disclosure provisions of Financial Accounting Standards Board
Interpretation (FIN) No. 45, "Guarantor's Accounting and Disclosure Requirements
for Guarantees, Including Indirect Guarantees of Indebtedness of Others" to our
agreements that contain guarantee or indemnification clauses. These disclosure
provisions expand those required by SFAS No. 5, "Accounting for Contingencies,"
by requiring a guarantor to disclose certain types of guarantees, even if the
likelihood of requiring the guarantor's performance is remote. The following is
a description of our contingent debt agreements.

     Cortez Pipeline Company Debt

     Pursuant to a certain Throughput and Deficiency Agreement, the partners of
Cortez Pipeline Company (Kinder Morgan CO2 Company, L.P. - 50% partner; a
subsidiary of Exxon Mobil Corporation - 37% partner; and Cortez Vickers Pipeline
Company - 13% partner) are required, on a several, percentage ownership basis,
to contribute capital to Cortez Pipeline Company in the event of a cash
deficiency. The Throughput and Deficiency Agreement contractually supports the
borrowings of Cortez Capital Corporation, a wholly-owned subsidiary of Cortez
Pipeline Company, by obligating the partners of Cortez Pipeline Company to fund
cash deficiencies at Cortez Pipeline Company, including cash deficiencies
relating to the repayment of principal and interest on borrowings by Cortez
Capital Corporation. Parent companies of the respective Cortez Pipeline Company
partners further severally guarantee, on a percentage basis, the obligations of
the Cortez Pipeline Company partners under the Throughput and Deficiency
Agreement.

     Due to our indirect ownership of Cortez Pipeline Company through Kinder
Morgan CO2 Company, L.P., we severally guarantee 50% of the debt of Cortez
Capital Corporation. Shell Oil Company shares our several guaranty obligations
jointly and severally through December 31, 2006.

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<PAGE>


     As of December 31, 2004, the debt facilities of Cortez Capital Corporation
consisted of:

     o    $85 million of Series D notes due May 15, 2013;

     o    a $125 million short-term commercial paper program; and

     o    a $125 million five-year committed revolving credit facility due
          December 22, 2009 (to support the above-mentioned $125 million
          commercial paper program).

     As of December 31, 2004, Cortez Capital Corporation had $116.7 million of
commercial paper outstanding with an average interest rate of 2.2623%, the
average interest rate on the Series D notes was 7.0835% and there were no
borrowings under the credit facility.

     Plantation Pipe Line Company Debt

     On April 30, 1997, Plantation Pipe Line Company entered into a $10 million,
ten-year floating-rate term credit agreement. We, as an owner of Plantation Pipe
Line Company, severally guaranteed this debt on a pro rata basis equivalent to
our respective 51.17% ownership interest. During 1999, this agreement was
amended to reduce the maturity date by three years. In April 2004, we extended
the maturity to July 20, 2004.

     In July 2004, Plantation repaid the $10 million note outstanding and $175
million in outstanding commercial paper with funds of $190 million borrowed from
its owners. We loaned Plantation $97.2 million, which corresponds to our 51.17%
ownership interest, in exchange for a seven year note receivable bearing
interest at the rate of 4.72% per annum. The note provides for semiannual
payments of principal and interest on December 31 and June 30 each year
beginning on December 31, 2004 based on a 25 year amortization schedule, with a
final principal payment of $156.6 million due July 20, 2011. We funded our loan
of $97.2 million with borrowings under our commercial paper program. An
affiliate of ExxonMobil owns the remaining 48.83% equity interest in Plantation
and funded the remaining $92.8 million on similar terms.

     Red Cedar Gas Gathering Company Debt

     In October 1998, Red Cedar Gas Gathering Company sold $55 million in
aggregate principal amount of Senior Notes due October 31, 2010. The $55 million
was sold in 10 different notes in varying amounts with identical terms.

     The Senior Notes are collateralized by a first priority lien on the
ownership interests, including our 49% ownership interest, in Red Cedar Gas
Gathering Company. The Senior Notes are also guaranteed by us and the other
owner of Red Cedar Gas Gathering Company jointly and severally. The principal is
to be repaid in seven equal installments beginning on October 31, 2004 and
ending on October 31, 2010. As of December 31, 2004, $47.1 million in principal
amount of notes were outstanding.

     Nassau County, Florida Ocean Highway and Port Authority Debt

     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. Principal payments on the bonds are made on
the first of December each year and reductions are made to the letter of credit.
As of December 31, 2004, the value of this letter of credit outstanding under
our credit facility was $25.9 million.

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14.  Risk Management

     Hedging Activities

     Certain of our business activities expose us to risks associated with
changes in the market price of natural gas, natural gas liquids, crude oil and
carbon dioxide. We use energy financial instruments to reduce our risk of
changes in the prices of natural gas, natural gas liquids and crude oil markets
(and carbon dioxide to the extent contracts are tied to crude oil prices) as
discussed below. These risk management instruments are also called derivatives,
which are defined as financial instruments or contracts whose value is derived
from some other financial measure called the underlying, and includes payment
provisions called the notional amount. The value of a derivative (for example,
options, swaps, futures, etc.) is a function of the underlying (for example,
commodity prices) and the notional amount (for example, payment in cash,
commodities, etc.), and while the underlying changes due to changes in market
conditions, the notional amount remains constant throughout the life of the
derivative contract.

     Current accounting standards require derivatives to be reflected as assets
or liabilities at their fair market values and the fair value of our risk
management instruments reflects the estimated amounts that we would receive or
pay to terminate the contracts at the reporting date, thereby taking into
account the current unrealized gains or losses on open contracts. We have
available market quotes for substantially all of the financial instruments that
we use, including: commodity futures and options contracts, fixed-price swaps,
and basis swaps.

     Pursuant to our management's approved policy, we are to engage in these
activities 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 primarily 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.

     Specifically, our risk management committee is a separately designated
standing committee comprised of eleven executive-level employees of KMI or KMGP
Services Company, Inc. whose job responsibilities involve operations exposed to
commodity market risk and other external risks in the ordinary course of
business. Our risk management committee is chaired by our Chief Financial
Officer and is charged with the following three responsibilities:

     o    establish and review risk limits consistent with our risk tolerance
          philosophy;

     o    recommend to the audit committee of our general partner's delegate any
          changes, modifications, or amendments to our trading policy; and

     o    address and resolve any other high-level risk management issues.

     Our derivatives hedge the commodity price risks derived from our normal
business activities, which include the sale of natural gas, natural gas liquids,
oil and carbon dioxide, and these derivatives have been designated by us as cash
flow hedges as defined by SFAS No. 133. SFAS No. 133 designates derivatives that
hedge exposure to variable cash flows of forecasted transactions as cash flow
hedges and the effective portion of the derivative's gain or loss is initially
reported as a component of other comprehensive income (outside earnings) and
subsequently is reclassified into earnings when the forecasted transaction
affects earnings. If the transaction results in an asset or liability, amounts
in accumulated other comprehensive income should be reclassified into earnings
when the asset or liability affects earnings through cost of sales,
depreciation, interest expense, etc. To be considered effective,


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changes in the value of the derivative or its resulting cash flows must
substantially offset changes in the value or cash flows of the item being
hedged. The ineffective portion of the gain or loss and any component excluded
from the computation of the effectiveness of the derivative instrument is
reported in earnings immediately.

     The gains and losses included in "Accumulated other comprehensive loss" in
our accompanying consolidated balance sheets are reclassified into earnings as
the hedged sales and purchases take place. Approximately $171.9 million of the
Accumulated other comprehensive loss balance of $457.3 million representing
unrecognized net losses on derivative activities as of December 31, 2004 is
expected to be reclassified into earnings during the next twelve months. During
the year ended December 31, 2004, we reclassified $192.3 million of Accumulated
other comprehensive income into earnings as a result of hedged sales and
purchases during the period. This amount includes the accumulated other
comprehensive loss balance of $155.8 million representing unrecognized net
losses on derivative activities as of December 31, 2003.

     For each of the years ended December 31, 2004, 2003 and 2002, no gains or
losses included in "Accumulated other comprehensive loss" were reclassified into
earnings as a result of the discontinuance of cash flow hedges due to a
determination that the forecasted transactions would no longer occur by the end
of the originally specified time period.

     We recognized a gain of $0.1 million during 2004, a gain of $0.5 million
during 2003 and a gain of $0.7 million during 2002 as a result of ineffective
hedges. All of these amounts are reported within the caption "Gas purchases and
other costs of sales" in our accompanying consolidated statements of income. For
each of the years ended December 31, 2004, 2003 and 2002, we did not exclude any
component of the derivative instruments' gain or loss from the assessment of
hedge effectiveness.

     The differences between the current market value and the original physical
contracts value associated with our hedging activities are included within
"Other current assets", "Accrued other current liabilities", "Deferred charges
and other assets" and "Other long-term liabilities and deferred credits" in our
accompanying consolidated balance sheets.

     The following table summarizes the net fair value of our energy financial
instruments associated with our risk management activities and included on our
accompanying consolidated balance sheets as of December 31, 2004 and December
31, 2003 (in thousands): December December 31, 31, 2004 2003

                                                   December 31,     December 31,
                                                       2004             2003
                                                ---------------    -------------
Derivatives-net asset/(liability)
  Other current assets......................     $    41,010      $    18,157
  Deferred charges and other assets.........          17,408            2,722
  Accrued other current liabilities.........        (218,967)         (90,426)
  Other long-term liabilities and deferred
    credits.................................      $ (309,035)      $ (101,463)


     As of December 31, 2004, we had an outstanding $50 million letter of credit
issued to Morgan Stanley in support of our hedging activities. In late February
2005, we increased this letter of credit to $125 million.

     Given our portfolio of businesses as of December 31, 2004, our principal
uses of derivative energy financial instruments will be to mitigate the risk
associated with market movements in the price of energy commodities. Our net
short natural gas derivatives position primarily represents our hedging of
anticipated future natural gas purchases and sales. Our net short crude oil
derivatives position represents our crude oil derivative purchases and sales
made to hedge anticipated oil purchases and sales. Finally, our net short
natural gas liquids derivatives position reflects the hedging of our forecasted
natural gas liquids purchases and sales. As of December 31, 2004, the maximum
length of time over which we have hedged our exposure to the variability in
future cash flows associated with commodity price risk is through December 2010.

     As of December 31, 2004, our commodity contracts and over-the-counter swaps
and options (in thousands) consisted of the following:



                                      149

<PAGE>
<TABLE>
<CAPTION>

                                                                      Over the
                                                                       Counter
                                                                      Swaps and
                                                       Commodity       Options
                                                       Contracts      Contracts       Total
                                                       ---------      ----------      ------
                                                              (Dollars in thousands)
<S>                                                   <C>          <C>            <C>
Deferred Net (Loss) Gain...........................   $   3,614    $    (473,308) $  (469,694)
Contract Amounts -- Gross..........................   $  48,018    $   1,314,281  $ 1,362,299
Contract Amounts -- Net............................   $ (15,320)   $    (937,566) $  (952,886)

                                                             (Number of contracts(1))
Natural Gas
  Notional Volumetric Positions: Long..............         293            1,339        1,632
  Notional Volumetric Positions: Short.............        (556)          (1,822)      (2,378)
  Net Notional Totals to Occur in 2005.............        (263)            (638)        (901)
  Net Notional Totals to Occur in 2006 and Beyond..          --             (155)        (155)
Crude Oil
  Notional Volumetric Positions: Long..............          --              429          429
  Notional Volumetric Positions: Short.............          --          (41,541)     (41,541)
  Net Notional Totals to Occur in 2005.............          --          (16,389)     (16,389)
  Net Notional Totals to Occur in 2006 and Beyond..          --          (24,723)     (24,723)
Natural Gas Liquids
  Notional Volumetric Positions: Long..............          --               --           --
  Notional Volumetric Positions: Short.............          --             (298)        (298)
  Net Notional Totals to Occur in 2005.............          --             (298)        (298)
  Net Notional Totals to Occur in 2006 and Beyond..          --               --           --

</TABLE>

----------
(1) A term of reference describing a unit of commodity trading. One natural gas
    contract equals 10,000 MMBtus. One crude oil or natural gas liquids contract
    equals 1,000 barrels.

     Our over-the-counter swaps and options are with a number of parties, who
principally have investment grade credit ratings. We both owe money and are owed
money under these financial instruments; however, as of both December 31, 2004
and December 31, 2003, we were essentially in a net payable position and had
virtually no amounts owed to us from other parties. In addition, defaults by
counterparties under over-the-counter swaps and options could expose us to
additional commodity price risks in the event that we are unable to enter into
replacement contracts for such swaps and options on substantially the same
terms. Alternatively, we may need to pay significant amounts to the new
counterparties to induce them to enter into replacement swaps and options on
substantially the same terms. While we enter into derivative transactions
principally with investment grade counterparties and actively monitor their
credit ratings, it is nevertheless possible that from time to time losses will
result from counterparty credit risk in the future.

     Purchases or sales of commodity contracts require a dollar amount to be
placed in margin accounts. In addition, we are required to post margins with
certain over-the-counter swap partners. These margin requirements are determined
based upon credit limits and mark-to-market positions. Our margin deposits
associated with commodity contract positions were $1.6 million as of December
31, 2004 and $10.3 million as of December 31, 2003. Our margin deposits
associated with over-the-counter swap partners were $2.8 million as of December
31, 2004 and $7.7 million as of December 31, 2003.

     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.

Interest Rate Swaps

     In order to maintain a cost effective capital structure, it is our policy
to borrow funds using a mix of fixed rate and variable rate debt. As of December
31, 2004 and 2003, we were a party to interest rate swap agreements with
notional principal amounts of $2.3 billion and $2.1 billion, respectively. We
entered into these agreements for the purpose of hedging the interest rate risk
associated with our fixed and variable rate debt obligations.

                                      150

<PAGE>


     As of December 31, 2004, a notional principal amount of $2.2 billion of
these agreements effectively converts the interest expense associated with the
following series of our senior notes from fixed rates to variable rates based on
an interest rate of LIBOR plus a spread:

     o    $200 million principal amount of our 8.0% senior notes due March 15,
          2005;

     o    $200 million principal amount of our 5.35% senior notes due August 15,
          2007;

     o    $250 million principal amount of our 6.30% senior notes due February
          1, 2009;

     o    $200 million principal amount of our 7.125% senior notes due March 15,
          2012;

     o    $250 million principal amount of our 5.0% senior notes due December
          15, 2013;

     o    $200 million principal amount of our 5.125% senior notes due November
          15, 2014;

     o    $300 million principal amount of our 7.40% senior notes due March 15,
          2031;

     o    $200 million principal amount of our 7.75% senior notes due March 15,
          2032; and

     o    $400 million principal amount of our 7.30% senior notes due August 15,
          2033.

     These swap agreements have termination dates that correspond to the
maturity dates of the related series of senior notes, therefore, as of December
31, 2004, the maximum length of time over which we have hedged a portion of our
exposure to the variability in the value of this debt due to interest rate risk
is through August 15, 2033.

     The swap agreements related to our 7.40% senior notes contain mutual
cash-out provisions at the then-current economic value every seven years. The
swap agreements related to our 7.125% senior notes contain cash-out provisions
at the then-current economic value in March 2009. The swap agreements related to
our 7.75% senior notes and our 7.30% senior notes contain mutual cash-out
provisions at the then-current economic value every five or seven years.

     These interest rate swaps have been designated as fair value hedges as
defined by SFAS No. 133. SFAS No. 133 designates derivatives that hedge a
recognized asset or liability's exposure to changes in their fair value as fair
value hedges and the gain or loss on fair value hedges are to be recognized in
earnings in the period of change together with the offsetting loss or gain on
the hedged item attributable to the risk being hedged. The effect of that
accounting is to reflect in earnings the extent to which the hedge is not
effective in achieving offsetting changes in fair value.

     As of December 31, 2004, we also had swap agreements that effectively
convert the interest expense associated with $100 million of our variable rate
debt to fixed rate debt. Half of these agreements, converting $50 million of our
variable rate debt to fixed rate debt, mature on August 1, 2005, and the
remaining half mature on September 1, 2005. These swaps are designated as a cash
flow hedge of the risk associated with changes in the designated benchmark
interest rate (in this case, one-month LIBOR) related to forecasted payments
associated with interest on an aggregate of $100 million of our portfolio of
commercial paper.

     Our interest rate swaps meet the conditions required to assume no
ineffectiveness under SFAS No. 133 and, therefore, we have accounted for them
using the "shortcut" method prescribed for fair value hedges by SFAS No. 133.
Accordingly, we adjust the carrying value of each swap to its fair value each
quarter, with an offsetting entry to adjust the carrying value of the debt
securities whose fair value is being hedged. We record interest expense equal to
the variable rate payments or fixed rate payments under the swaps. Interest
expense is accrued monthly and paid semi-annually.

     The differences between fair value and the original carrying value
associated with our interest rate swap agreements are included within "Deferred
charges and other assets" and "Other long-term liabilities and deferred credits"
in our accompanying consolidated balance sheets. The offsetting entry to adjust
the carrying value of the


                                      151
<PAGE>


debt securities whose fair value was being hedged is recognized as "Market value
of interest rate swaps" on our accompanying consolidated balance sheets.

     The following table summarizes the net fair value of our interest rate swap
agreements associated with our interest rate risk management activities and
included on our accompanying consolidated balance sheets as of December 31, 2004
and December 31, 2003 (in thousands):

                                                    December 31,    December 31,
                                                         2004            2003
                                                ---------------  ------------
Derivatives-net asset/(liability)
  Deferred charges and other assets............   $  132,210      $  129,618
  Other  long-term  liabilities  and  deferred
  credits......................................       (2,057)         (8,154)
                                                  -----------    ------------
    Market value of interest rate swaps........   $  130,153       $ 121,464
                                                  ===========    ============

     We are exposed to credit related losses in the event of nonperformance by
counterparties to these interest rate swap agreements. While we enter into
derivative transactions primarily with investment grade counterparties and
actively monitor their credit ratings, it is nevertheless possible that from
time to time losses will result from counterparty credit risk.


15.  Reportable Segments

     We divide our operations into four reportable business segments:

     o    Products Pipelines;

     o    Natural Gas Pipelines;

     o    CO2; and

     o    Terminals.

     Each segment uses the same accounting policies as those described in the
summary of significant accounting policies (see Note 2). We evaluate performance
principally based on each segments' earnings before depreciation, depletion and
amortization, which exclude general and administrative expenses, third-party
debt costs and interest expense, unallocable interest income and minority
interest. Our reportable segments are strategic business units that offer
different products and services. Each segment is managed separately because each
segment involves different products and marketing strategies.

     Our Products Pipelines segment derives its revenues primarily from the
transportation and terminaling of refined petroleum products, including
gasoline, diesel fuel, jet fuel and natural gas liquids. Our Natural Gas
Pipelines segment derives its revenues primarily from the transmission, storage,
gathering and sale of natural gas. Our CO2 segment derives its revenues
primarily from the transportation and marketing of carbon dioxide used as a
flooding medium for recovering crude oil from mature oil fields and from the
production and sale of crude oil from fields in the Permian Basin of West Texas.
Our Terminals segment derives its revenues primarily from the transloading and
storing of refined petroleum products and dry and liquid bulk products,
including coal, petroleum coke, cement, alumina, salt, and chemicals.

     Financial information by segment follows (in thousands):
<TABLE>
<CAPTION>

                                                          2004            2003            2002
                                                     --------------  --------------  -------------
<S>                                                  <C>             <C>             <C>
Revenues
  Products Pipelines............................     $     645,249   $     585,376   $     576,542
  Natural Gas Pipelines.........................         6,252,921       5,316,853       3,086,187
  CO2...........................................           492,834         248,535         146,280
  Terminals.....................................           541,857         473,558         428,048
                                                     -------------   -------------   -------------
  Total consolidated revenues...................     $   7,932,861   $   6,624,322   $   4,237,057
                                                     =============   =============   =============
</TABLE>

                                      152

<PAGE>

<TABLE>
<CAPTION>


                                                          2004            2003            2002
                                                     --------------  --------------  -------------
<S>                                                  <C>             <C>             <C>
Operating expenses(a)
  Products Pipelines.............................    $     191,425   $     169,526   $     169,782
  Natural Gas Pipelines..........................        5,862,159       4,967,531       2,784,278
  CO2............................................          173,382          82,055          50,524
  Terminals......................................          272,766         229,054         213,929
                                                     -------------   -------------   -------------
  Total consolidated operating expenses..........    $   6,499,732   $   5,448,166   $   3,218,513
                                                     =============   =============   =============

Depreciation, depletion and amortization
  Products Pipelines...........................      $      71,263   $      67,345   $      64,388
  Natural Gas Pipelines........................             53,112          53,785          48,411
  CO2..........................................            121,361          60,827          29,196
  Terminals....................................             42,890          37,075          30,046
                                                     -------------   -------------   -------------
  Total consol. depreciation, depletion and
    amortiz....................................      $     288,626   $     219,032   $     172,041
                                                     =============   =============   =============

Earnings from equity investments
  Products Pipelines............................     $      29,050   $      30,948   $      28,998
  Natural Gas Pipelines.........................            19,960          24,012          23,887
  CO2...........................................            34,179          37,198          36,328
  Terminals.....................................                 1              41              45
                                                     -------------   -------------   -------------
  Total consolidated equity earnings............     $      83,190   $      92,199   $      89,258
                                                     =============   =============   =============

Amortization of excess cost of equity investments
  Products Pipelines............................     $       3,281   $       3,281   $       3,281
  Natural Gas Pipelines.........................               277             277             277
  CO2...........................................             2,017           2,017           2,017
  Terminals.....................................                --              --              --
                                                     --------------  --------------  -------------
  Total consol. amortization of excess cost of
    invests.....................................     $       5,575   $       5,575   $       5,575
                                                     =============   =============   =============

Interest income
  Products Pipelines.............................    $       2,091   $          --   $          --
  Natural Gas Pipelines..........................               --              --              --
  CO2............................................               --              --              --
  Terminals......................................               --              --              --
                                                     --------------  --------------  -------------
  Total segment interest income..................            2,091              --              --
  Unallocated interest income....................            1,199           1,420           1,819
                                                     -------------   -------------   -------------
  Total consolidated interest income.............    $       3,290   $       1,420   $       1,819
                                                     =============   =============   =============

Other, net-income (expense)(b)
  Products Pipelines............................    $     (28,025)   $       6,471   $     (14,000)
  Natural Gas Pipelines.........................            9,434            1,082              36
  CO2...........................................            4,152              (40)            112
  Terminals.....................................           18,255               88          15,550
                                                    -------------    -------------   -------------
  Total segment Other, net-income (expense)......           3,816            7,601           1,698
  Loss from early extinguishment of debt.........          (1,562)              --              --
                                                    --------------   --------------  -------------
  Total consolidated Other, net-income (expense).   $       2,254    $       7,601   $       1,698
                                                    =============    =============   =============

Income tax benefit (expense)
  Products Pipelines.............................   $     (12,075)   $     (11,669)  $     (10,154)
  Natural Gas Pipelines..........................          (1,895)          (1,066)           (378)
  CO2............................................            (147)             (39)             --
  Terminals(c)...................................          (5,609)          (3,857)         (4,751)
                                                    --------------   --------------  -------------
  Total consolidated income tax benefit(expense).   $     (19,726)   $     (16,631)  $     (15,283)
                                                    =============    =============   =============

Segment earnings
  Products Pipelines.............................   $     370,321    $     370,974   $     343,935
  Natural Gas Pipelines..........................         364,872          319,288         276,766
  CO2............................................         234,258          140,755         100,983
  Terminals......................................         238,848          203,701         194,917
                                                    -------------    -------------   -------------
  Total segment earnings(d)......................       1,208,299        1,034,718         916,601
  Interest and corporate administrative
    expenses(e)..................................        (376,721)        (337,381)       (308,224)
                                                    -------------    -------------   -------------
  Total consolidated net income..................   $     831,578    $     697,337   $     608,377
                                                    =============    =============   =============
</TABLE>



                                      153
<PAGE>

<TABLE>
<CAPTION>


                                                          2004            2003            2002
                                                     --------------  --------------  -------------
<S>                                                 <C>              <C>             <C>
Segment earnings before depreciation, depletion,
  amortization and amortization of excess cost of
  equity investments(f)
  Products Pipelines.............................   $     444,865    $     441,600   $     411,604
  Natural Gas Pipelines..........................         418,261          373,350         325,454
  CO2............................................         357,636          203,599         132,196
  Terminals......................................         281,738          240,776         224,963
                                                    -------------    -------------   -------------
  Total segment earnings before DD&A.............       1,502,500        1,259,325       1,094,217
  Consolidated depreciation and amortization.....        (288,626)        (219,032)       (172,041)
  Consolidated amortization of excess cost of
    invests......................................          (5,575)          (5,575)         (5,575)
  Interest and corporate administrative expenses.        (376,721)        (337,381)       (308,224)
                                                    -------------    -------------   -------------
  Total consolidated net income..................   $     831,578    $     697,337   $     608,377
                                                    =============    =============   =============

Capital expenditures
  Products Pipelines...........................     $     213,746    $      94,727   $      62,199
  Natural Gas Pipelines........................           106,358          101,679         194,485
  CO2..........................................           302,935          272,177         163,183
  Terminals....................................           124,223          108,396         122,368
                                                    -------------    -------------   -------------
  Total consolidated capital expenditures(g)...     $     747,262    $     576,979   $     542,235
                                                    =============    =============   =============

Investments at December 31
  Products Pipelines...........................     $     223,196    $     226,680   $     220,203
  Natural Gas Pipelines........................           174,296          164,924         157,778
  CO2..........................................            15,503           12,591          71,283
  Terminals....................................               260              150           2,110
                                                    -------------    -------------   -------------
  Total consolidated investments...............     $     413,255    $     404,345   $     451,374
                                                    =============    =============   =============

Assets at December 31
  Products Pipelines...........................     $   3,651,657    $   3,198,107   $   3,088,799
  Natural Gas Pipelines........................         3,691,457        3,253,792       3,121,674
  CO2..........................................         1,527,810        1,177,645         613,980
  Terminals....................................         1,576,333        1,368,279       1,165,096
                                                    -------------    -------------   -------------
  Total segment assets.........................        10,447,257        8,997,823       7,989,549
  Corporate assets(h)..........................           105,685          141,359         364,027
                                                    -------------    -------------   -------------
  Total consolidated assets....................     $  10,552,942    $   9,139,182   $   8,353,576
                                                    =============    =============   =============
</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)  2004 amounts include environmental liability adjustments resulting in a
     $30.6 million expense to our Products Pipelines business segment, a $7.6
     million earnings increase to our Natural Gas Pipelines business segment, a
     $4.1 million earnings increase to our CO2 business segment and an $18.7
     million earnings increase to our Terminals business segment. 2002 amounts
     include environmental liability adjustments resulting in a $15.7 million
     expense to our Products Pipelines business segment and a $16.0 million
     earnings increase to our Terminals business segment.

(c)  2004 amount includes expenses of $0.1 million related to environmental
     expense adjustments.

(d)  Includes revenues, earnings from equity investments, income taxes,
     allocable interest income and other, net, less operating expenses,
     depreciation, depletion and amortization, and amortization of excess cost
     of equity investments.

(e)  Includes unallocated interest income, interest and debt expense, general
     and administrative expenses, minority interest expense, loss from early
     extinguishment of debt (2004 only) and cumulative effect adjustment from a
     change in accounting principle (2003 only).

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

(g)  Includes sustaining capital expenditures of $119,244 in 2004, $92,837 in
     2003 and $76,967 in 2002. Sustaining capital expenditures are defined as
     capital expenditures which do not increase the capacity of an asset.

(h)  Includes cash, cash equivalents and certain unallocable deferred charges.


                                      154

<PAGE>


  We do not attribute interest and debt expense to any of our reportable
business segments. For each of the years ended December 31, 2004, 2003 and 2002,
we reported (in thousands) total consolidated interest expense of $196,172,
$182,777 and $178,279, respectively.

   Our total operating revenues are derived from a wide customer base. For each
of the years ended December 31, 2004, 2003 and 2002, only one customer accounted
for more than 10% of our total consolidated revenues. Total transactions within
our Natural Gas Pipelines segment with CenterPoint Energy accounted for 14.3%,
16.8% and 15.6% of our total consolidated revenues during 2004, 2003 and 2002,
respectively.


16.  Litigation and Other Contingencies

   The tariffs we charge for transportation on our interstate common carrier
pipelines are subject to rate regulation by the Federal Energy Regulatory
Commission, referred to in this report as FERC, under the Interstate Commerce
Act. The Interstate Commerce Act requires, among other things, that interstate
petroleum products pipeline rates be just and reasonable and nondiscriminatory.
Pursuant to FERC Order No. 561, effective January 1, 1995, interstate petroleum
products pipelines are able to change their rates within prescribed ceiling
levels that are tied to an inflation index. FERC Order No. 561-A, affirming and
clarifying Order No. 561, expanded the circumstances under which interstate
petroleum products pipelines may employ cost-of-service ratemaking in lieu of
the indexing methodology, effective January 1, 1995. For each of the years ended
December 31, 2004, 2003 and 2002, the application of the indexing methodology
did not significantly affect tariff rates on our interstate petroleum products
pipelines.

  SFPP, L.P.

  Federal Energy Regulatory Commission Proceedings

  SFPP, L.P., referred to in this report as SFPP, 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 FERC 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.

  OR92-8, et al. proceedings. FERC Docket No. OR92-8-000 et al., is a
consolidated proceeding that began in September 1992 and includes a number of
shipper complaints against certain rates and practices on SFPP's East Line (from
El Paso, Texas to Phoenix, Arizona) and West Line (from Los Angeles, California
to Tucson, Arizona), as well as SFPP's gathering enhancement fee at Watson
Station in Carson, California. The complainants in the case are El Paso
Refinery, L.P. (which settled with SFPP in 1996), Chevron Products Company,
Navajo Refining Company (now Navajo Refining Company, L.P.), ARCO Products
Company (now part of BP West Coast Products, LLC), Texaco Refining and Marketing
Inc., Refinery Holding Company LP (now named Western Refining Company, L.P.),
Mobil Oil Corporation (now part of ExxonMobil Oil Corporation) and Tosco
Corporation (now part of ConocoPhillips Company). The FERC has ruled that the
complainants have the burden of proof in this proceeding.

  A FERC administrative law judge held hearings in 1996, and issued an initial
decision in September 1997. The initial decision held that all but one of SFPP's
West Line rates were "grandfathered" under the Energy Policy Act of 1992 and
therefore deemed to be just and reasonable; it further held that complainants
had failed to prove "substantially changed circumstances" with respect to those
rates and that they therefore could not be challenged in the Docket No. OR92-8
et al. proceedings, either for the past or prospectively. However, the initial
decision also made rulings generally adverse to SFPP on certain cost of service
issues relating to the evaluation of East Line rates, which are not
"grandfathered" under the Energy Policy Act. Those issues included the capital
structure to be used in computing SFPP's "starting rate base," the level of
income tax allowance SFPP may include in rates and the recovery of civil and
regulatory litigation expenses and certain pipeline reconditioning costs
incurred by SFPP. The initial decision also held SFPP's Watson Station gathering
enhancement service was subject to FERC jurisdiction and ordered SFPP to file a
tariff for that service.


                                      155
<PAGE>


  The FERC subsequently reviewed the initial decision, and issued a series of
orders in which it adopted certain rulings made by the administrative law judge,
changed others and modified a number of its own rulings on rehearing. Those
orders began in January 1999, with FERC Opinion No. 435, and continued through
June 2003.

  The FERC affirmed that all but one of SFPP's West Line rates are
"grandfathered" and that complainants had failed to satisfy the threshold burden
of demonstrating "substantially changed circumstances" necessary to challenge
those rates. The FERC further held that the one West Line rate that was not
grandfathered did not need to be reduced. The FERC consequently dismissed all
complaints against the West Line rates in Docket Nos. OR92-8 et al. without any
requirement that SFPP reduce, or pay any reparations for, any West Line rate.

  The FERC initially modified the initial decision's ruling regarding the
capital structure to be used in computing SFPP's "starting rate base" to be more
favorable to SFPP, but later reversed that ruling. The FERC also made certain
modifications to the calculation of the income tax allowance and other cost of
service components, generally to SFPP's disadvantage.

  On multiple occasions, the FERC required SFPP to file revised East Line rates
based on rulings made in the FERC's various orders. SFPP was also directed to
submit compliance filings showing the calculation of the revised rates, the
potential reparations for each complainant and in some cases potential refunds
to shippers. SFPP filed such revised East Line rates and compliance filings in
March 1999, July 2000, November 2001 (revised December 2001), October 2002 and
February 2003 (revised March 2003). Most of those filings were protested by
particular SFPP shippers. The FERC has held that certain of the rates SFPP filed
at the FERC's directive should be reduced retroactively and/or be subject to
refund; SFPP has challenged the FERC's authority to impose such requirements in
this context.

  While the FERC initially permitted SFPP to recover certain of its litigation,
pipeline reconditioning and environmental costs, either through a surcharge on
prospective rates or as an offset to potential reparations, it ultimately
limited recovery in such a way that SFPP was not able to make any such surcharge
or take any such offset. Similarly, the FERC initially ruled that SFPP would not
owe reparations to any complainant for any period prior to the date on which
that party's complaint was filed, but ultimately held that each complainant
could recover reparations for a period extending two years prior to the filing
of its complaint (except for Navajo, which was limited to one month of
pre-complaint reparations under a settlement agreement with SFPP's predecessor).
The FERC also ultimately held that SFPP was not required to pay reparations or
refunds for Watson Station gathering enhancement fees charged prior to filing a
FERC tariff for that service.

  In April 2003, SFPP paid complainants and other shippers reparations and/or
refunds as required by FERC's orders. In August 2003, SFPP paid shippers an
additional refund as required by FERC's most recent order in the Docket No.
OR92-8 et al. proceedings. We made aggregate payments of $44.9 million in 2003
for reparations and refunds pursuant to a FERC order.

  Beginning in 1999, SFPP, the complainants and intervenor Ultramar Diamond
Shamrock Corporation (now part of Valero Energy Corporation) filed petitions for
review of FERC's Docket OR92-8 et al. orders in the United States Court of
Appeals for the District of Columbia Circuit. Certain of those petitions were
dismissed by the Court of Appeals as premature, and the remaining petitions were
held in abeyance pending completion of agency action. However, in December 2002,
the Court of Appeals returned to its active docket all petitions to review the
FERC's orders in the case through November 2001 and severed petitions regarding
later FERC orders. The severed orders were held in abeyance for later
consideration.

  Briefing in the Court of Appeals was completed in August 2003, and oral
argument took place on November 12, 2003. On July 20, 2004, the U.S. Court of
Appeals for the District of Columbia Circuit issued an opinion affirming the
FERC orders under review on most issues, vacating the tax provision that the
FERC had allowed SFPP to include under the FERC's "Lakehead" policy giving a tax
allowance to partnership pipelines and remanding for further FERC proceedings on
other issues.

  The court held that, in the context of the Docket No. OR92-8, et al.
proceedings, all of SFPP's West Line rates were grandfathered other than the
charge for use of SFPP's Watson Station gathering enhancement facility and the
rate for turbine fuel movements to Tucson under SFPP Tariff No. 18. It concluded
that the FERC had a reasonable

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basis for concluding that the addition of a West Line origin point at East
Hynes, California did not involve a new "rate" for purposes of the Energy Policy
Act. It rejected arguments from West Line Shippers that certain protests and
complaints had challenged West Line rates prior to the enactment of the Energy
Policy Act.

  The court also held that complainants had failed to satisfy their burden of
demonstrating substantially changed circumstances, and therefore could not
challenge grandfathered West Line rates in the Docket No. OR92-8 et al.
proceedings. It specifically rejected arguments that other shippers could
"piggyback" on the special Energy Policy Act exception permitting Navajo to
challenge grandfathered West Line rates, which Navajo had withdrawn under a
settlement with SFPP. The court remanded the changed circumstances issue "for
further consideration" by the FERC in light of the court's decision, described
below, regarding SFPP's tax allowance. The FERC had previously held in the
OR96-2 proceeding that the tax allowance policy should not be used as a
stand-alone factor in determining when there have been substantially changed
circumstances.

  The court upheld the FERC's rulings on most East Line rate issues. However, it
found the FERC's reasoning inadequate on some issues, including the tax
allowance.

  The court held the FERC had sufficient evidence to use SFPP's December 1988
stand-alone capital structure to calculate its starting rate base as of June
1985. It rejected SFPP arguments that would have resulted in a higher starting
rate base.

  The court analyzed at length the tax allowance for pipelines that are
organized as partnerships. It concluded that the FERC had provided "no rational
basis" on the record before it for giving SFPP a tax allowance, and denied
recovery by SFPP of "income taxes not incurred and not paid."

  The court accepted the FERC's treatment of regulatory litigation costs,
including the limitation of recoverable costs and their offset against
"unclaimed reparations" - that is, reparations that could have been awarded to
parties that did not seek them. The court also accepted the FERC's denial of any
recovery for the costs of civil litigation by East Line shippers against SFPP
based on the 1992 re-reversal of the six-inch line between Tucson and Phoenix.
However, the court did not find adequate support for the FERC's decision to
allocate the limited litigation costs that SFPP was allowed to recover in its
rates equally between the East Line and the West Line, and ordered the FERC to
explain that decision further on remand.

  The court held the FERC had failed to justify its decision to deny SFPP any
recovery of funds spent to recondition pipe on the East Line, for which SFPP had
spent nearly $6 million between 1995 and 1998. It concluded that the
Commission's reasoning was inconsistent and incomplete, and remanded for further
explanation, noting that "SFPP's shippers are presently enjoying the benefits of
what appears to be an expensive pipeline reconditioning program without sharing
in any of its costs."

  The court affirmed the FERC's rulings on reparations in all respects. It held
the Arizona Grocery doctrine did not apply to orders requiring SFPP to file
"interim" rates, and that "FERC only established a final rate at the completion
of the OR92-8 proceedings." It held that the Energy Policy Act did not limit
complainants' ability to seek reparations for up to two years prior to the
filing of complaints against rates that are not grandfathered. It rejected
SFPP's arguments that the FERC should not have used a "test period" to compute
reparations, that it should have offset years in which there were
underrecoveries against those in which there were overrecoveries, and that it
should have exercised its discretion against awarding any reparations in this
case.

  The court also rejected:

  o Navajo's argument that its prior settlement with SFPP's predecessor did not
    limit its right to seek reparations;

  o Valero's argument that it should have been permitted to recover reparations
    in the Docket No. OR92-8 et al. proceedings rather than waiting to seek
    them, as appropriate, in the Docket No. OR96-2 et al. proceedings;

  o arguments that the former ARCO and Texaco had challenged East Line rates
    when they filed a complaint in January 1994 and should therefore be entitled
    to recover East Line reparations; and


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  o Chevron's argument that its reparations period should begin two years before
    its September 1992 protest regarding the six-inch line reversal rather than
    its August 1993 complaint against East Line rates.

  On September 2, 2004, BP West Coast Products, ChevronTexaco, ConocoPhillips
and ExxonMobil filed a petition for rehearing and rehearing en banc asking the
Court of Appeals to reconsider its ruling that West Line rates were not subject
to investigation at the time the Energy Policy Act was enacted. On September 3,
2004, SFPP filed a petition for rehearing asking the Court to confirm that the
FERC has the same discretion to address the income tax allowance issue on remand
that administrative agencies normally have when their decisions are set aside by
reviewing courts because they have failed to provide a reasoned basis for their
conclusions. On October 4, 2004, the Court of Appeals denied both petitions
without further comment.

  On November 2, 2004, the Court of Appeals issued its mandate remanding the
proceedings to the FERC. SFPP and shipper parties subsequently filed various
pleadings with the FERC regarding the proper nature and scope of the remand
proceedings. The FERC has not yet issued an order regarding the Docket No.
OR92-8 remand proceedings, but on December 2, 2004, it issued a Notice of
Inquiry and opened a new proceeding (Docket No. PL05-5) to consider how broadly
the court's ruling on the tax allowance issue should affect the range of
entities the FERC regulates. A number of parties filed comments in response to
that notice on January 21, 2005.

  On December 17, 2004, the Court of Appeals issued orders directing that the
petitions for review relating to FERC orders issued after November 2001, which
had previously been severed from the main Court of Appeals docket, should
continue to be held in abeyance pending completion of the remand proceedings
before the FERC.

  On January 3, 2005, SFPP filed a petition for a writ of certiorari asking the
United States Supreme Court to review the Court of Appeals' ruling that the
Arizona Grocery doctrine does not apply to "interim" rates, and that "FERC only
established a final rate at the completion of the OR92-8 proceedings." BP West
Coast Products and ExxonMobil also filed a petition for certiorari, on December
30, 2004, seeking review of the Court of Appeals' ruling that there was no
pending investigation of West Line rates at the time of enactment of the Energy
Policy Act (and thus that those rates remained grandfathered). Oppositions to
both petitions are currently due on March 7, 2005.

  We are continuing to review the potential impact of the Court of Appeals
decision and prepare for proceedings before the FERC on the issues that have
been remanded to it. In addition to participating in the FERC's proceedings on
remand, we may also seek review by the United States Supreme Court on one or
more issues.

  Sepulveda proceedings. In December 1995, Texaco filed a complaint at FERC
(Docket No. OR96-2) alleging that movements on SFPP's Sepulveda pipelines (Line
Sections 109 and 110) to Watson Station, in the Los Angeles basin, were subject
to FERC's jurisdiction under the Interstate Commerce Act, and claimed that the
rate for that service was unlawful. Several other West Line shippers filed
similar complaints and/or motions to intervene.

  Following a hearing in March 1997, a FERC administrative law judge issued an
initial decision holding that the movements on the Sepulveda pipelines were not
subject to FERC jurisdiction. On August 5, 1997, the FERC reversed that
decision. On October 6, 1997, SFPP filed a tariff establishing the initial
interstate rate for movements on the Sepulveda pipelines at the pre-existing
rate of five cents per barrel. Several shippers protested that rate. In December
1997, SFPP filed an application for authority to charge a market-based rate for
the Sepulveda service, which application was protested by several parties. On
September 30, 1998, the FERC issued an order finding that SFPP lacks market
power in the Watson Station destination market and set a hearing to determine
whether SFPP possessed market power in the origin market.

  Following a hearing, on December 21, 2000, an administrative law judge found
that SFPP possessed market power over the Sepulveda origin market. On February
28, 2003, the FERC issued an order upholding that decision. SFPP filed a request
for rehearing of that order on March 31, 2003. The FERC denied SFPP's request
for rehearing on July 9, 2003.

  As part of its February 28, 2003 order denying SFPP's application for
market-based ratemaking authority, the FERC remanded to the ongoing litigation
in Docket No. OR96-2, et al. the question of whether SFPP's current rate

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for service on the Sepulveda line is just and reasonable. A hearing in this
proceeding is scheduled to commence on February 15, 2005.

  OR96-2; OR97-2; OR98-1. et al. proceedings. In October 1996, Ultramar Diamond
Shamrock Corporation filed a complaint at FERC (Docket No. OR97-2) challenging
SFPP's West Line rates, claiming they were unjust and unreasonable and no longer
subject to grandfathering. In October 1997, ARCO, Mobil and Texaco filed a
complaint at the FERC (Docket No. OR98-1) challenging the justness and
reasonableness of all of SFPP's interstate rates, raising claims against SFPP's
East and West Line rates similar to those that have been at issue in Docket Nos.
OR92-8, et al. discussed above, but expanding them to include challenges to
SFPP's grandfathered interstate rates from the San Francisco Bay area to Reno,
Nevada and from Portland to Eugene, Oregon - the North Line and Oregon Line. In
November 1997, Ultramar filed a similar, expanded complaint (Docket No. OR98-2).
Tosco Corporation filed a similar complaint in April 1998. The shippers seek
both reparations and prospective rate reductions for movements on all of SFPP's
lines. The FERC accepted the complaints and consolidated them into one
proceeding (Docket No. OR96-2, et al.), but held them in abeyance pending a FERC
decision on review of the initial decision in Docket Nos. OR92-8, et al.

  In a companion order to Opinion No. 435, the FERC gave the complainants an
opportunity to amend their complaints in light of Opinion No. 435, which the
complainants did in January 2000. In August 2000, Navajo and Western filed
complaints against SFPP's East Line rates and Ultramar filed an additional
complaint updating its pre-existing challenges to SFPP's interstate pipeline
rates. These complaints were consolidated with the ongoing proceeding in Docket
No. OR96-2, et al.

  A hearing in this consolidated proceeding was held from October 2001 to March
2002. A FERC administrative law judge issued his initial decision on June 24,
2003. The initial decision found that, for the years at issue, the complainants
had shown substantially changed circumstances for rates on SFPP's West, North
and Oregon Lines and for SFPP's fee for gathering enhancement service at Watson
Station and thus found that those rates should not be "grandfathered" under the
Energy Policy Act of 1992. The initial decision also found that most of SFPP's
rates at issue were unjust and unreasonable.

  On March 26, 2004, the FERC issued an order on the phase one initial decision.
The FERC's phase one order reversed the initial decision by finding that SFPP's
rates for its North and Oregon Lines should remain "grandfathered" and amended
the initial decision by finding that SFPP's West Line rates (i) to Yuma, Tucson
and CalNev, as of 1995, and (ii) to Phoenix, as of 1997, should no longer be
"grandfathered" and are not just and reasonable. The FERC's phase one order did
not address prospective West Line rates and whether reparations are necessary.
As discussed below, those issues have been addressed in the non-binding phase
two initial decision recently issued by the presiding administrative law judge.
The FERC's phase one order also did not address the "grandfathered" status of
the Watson Station fee, noting that it would address that issue once it was
ruled on by the United States Court of Appeals for the District of Columbia
Circuit in its review of the FERC's Opinion No. 435 orders. Several of the
participants in the proceeding requested rehearing of the FERC's phase one
order. FERC action on those requests is pending. In addition, several
participants, including SFPP, filed petitions with the United States Court of
Appeals for the District of Columbia Circuit for review of the FERC's phase one
order. On August 13, 2004, the FERC filed a motion to dismiss the pending
petitions for review of the phase one order, which Petitioners, including SFPP,
answered on August 30, 2004. On December 20, 2004, the Court referred the FERC's
motion to the merits panel and directed the parties to address the issues in
that motion on brief, thus effectively dismissing the FERC's motion. In the same
order, the Court granted a motion to hold the petitions for review of the FERC's
phase one order in abeyance and directed the parties to file motions to govern
future proceeding 30 days after FERC disposition of the pending rehearing
requests.

  The FERC's phase one order also held that SFPP failed to seek authorization
for the accounting entries necessary to reflect in SFPP's books, and thus in its
annual report to FERC ("FERC Form 6"), the purchase price adjustment ("PPA")
arising from SFPP's 1998 acquisition by us. The phase one order directed SFPP to
file for permission to reflect the PPA in its FERC Form 6 for the calendar year
1998 and each subsequent year. In its April 26, 2004 compliance filing, SFPP
noted that it had previously requested such permission and that the FERC's
regulations require an oil pipeline to include a PPA in its Form 6 without first
seeking FERC permission to do so. Several parties protested SFPP's compliance
filing. SFPP answered those protests, and FERC action on this matter is pending.

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  On September 9, 2004, the presiding administrative law judge issued his
non-binding initial decision in the phase two portion of this proceeding. If
affirmed by the FERC, the phase two initial decision would establish the basis
for prospective rates and the calculation of reparations for complaining
shippers with respect to the West Line and East Line. However, as with the phase
one initial decision, the phase two initial decision must be fully reviewed by
the FERC, which may accept, reject or modify the decision. A FERC order on phase
two of the case is not expected before the second quarter of 2005. Any such
order may be subject to further FERC review, review by the United States Court
of Appeals for the District of Columbia Circuit, or both.

  We are not able to predict with certainty the final outcome of the pending
FERC proceedings involving SFPP, should they be carried through to their
conclusion, or whether we can reach a settlement with some or all of the
complainants. The final outcome will depend, in part, on the outcomes of the
appeals of these proceedings and the OR92-8, et al. proceedings taken by SFPP,
complaining shippers, and an intervenor.

  We estimated, as of December 31, 2003, that shippers' claims for reparations
totaled approximately $154 million and that prospective rate reductions would
have an aggregate average annual impact of approximately $45 million. As the
timing for implementation of rate reductions and the payment of reparations is
extended, total estimated reparations and the interest accruing on the
reparations increase. For each calendar quarter of delay in the implementation
of rate reductions sought, we estimate that reparations and accrued interest
accumulates by approximately $9 million. We now assume that any potential rate
reductions will be implemented no earlier than the third quarter of 2005 and
that reparations and accrued interest thereon will be paid no earlier than the
third quarter of 2006; however, the timing, and nature, of any rate reductions
and reparations that may be ordered will likely be affected by the FERC's income
tax allowance inquiry in Docket No. PL05-5 and the FERC's disposition of issues
remanded by the D.C. Circuit in the BP West Coast decision. If the phase two
initial decision were to be largely adopted by the FERC, the estimated
reparations and rate reductions would be larger than noted above; however, we
continue to estimate the combined annual impact of the rate reductions and the
capital costs associated with financing the payment of reparations sought by
shippers and accrued interest thereon to be approximately 15 cents of
distributable cash flow per unit. We believe, however, that the ultimate
resolution of these complaints will be for amounts substantially less than the
amounts sought.

  Chevron complaint OR02-4 proceedings. On February 11, 2002, Chevron, an
intervenor in the Docket No. OR96-2, et al. proceeding, filed a complaint
against SFPP in Docket No. OR02-4 along with a motion to consolidate the
complaint with the Docket No. OR96-2, et al. proceeding. On May 21, 2002, the
FERC dismissed Chevron's complaint and motion to consolidate. Chevron filed a
request for rehearing, which the FERC dismissed on September 25, 2002. In
October 2002, Chevron filed a request for rehearing of the FERC's September 25,
2002 Order, which the FERC denied on May 23, 2003. On July 1, 2003, Chevron
filed a petition for review of this denial at the U.S. Court of Appeals for the
District of Columbia Circuit. On August 18, 2003, SFPP filed a motion to dismiss
Chevron's petition on the basis that Chevron lacks standing to bring its appeal
and that the case is not ripe for review. Chevron answered on September 10,
2003. SFPP's motion was pending, when the Court of Appeals, on December 8, 2003,
granted Chevron's motion to hold the case in abeyance pending the outcome of the
appeal of the Docket No. OR92-8, et al. proceeding. On January 8, 2004, the
Court of Appeals granted Chevron's motion to have its appeal of the FERC's
decision in Docket No. OR03-5 (see below) consolidated with Chevron's appeal of
the FERC's decision in the Docket No. OR02-4 proceeding. On December 10, 2004,
the Court dismissed Chevron's petition for review in Docket No. OR03-5 and set
Chevron's appeal of the FERC's orders in OR02-4 for briefing. On January 4,
2005, the Court granted Chevron's request to hold such briefing in abeyance
until after final disposition of the OR96-2 proceeding. Chevron continues to
participate in the Docket No. OR96-2 et al. proceeding as an intervenor.

  OR03-5 proceedings. On June 30, 2003, Chevron filed another complaint against
SFPP - substantially similar to its previous complaint - and moved to
consolidate the complaint with the Docket No. OR96-2, et al. proceeding. This
complaint was docketed as Docket No. OR03-5. Chevron requested that this new
complaint be treated as if it were an amendment to its complaint in Docket No.
OR02-4, which was previously dismissed by the FERC. By this request, Chevron
sought to, in effect, back-date its complaint, and claim for reparations, to
February 2002. SFPP answered Chevron's complaint on July 22, 2003, opposing
Chevron's requests for consolidation and for the back-dating of its complaint.
On October 28, 2003, the FERC accepted Chevron's complaint, but held it in
abeyance

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pending the outcome of the Docket No. OR96-2, et al. proceeding. The FERC denied
Chevron's request for consolidation and for back-dating.

  On November 21, 2003, Chevron filed a petition for review of the FERC's
October 28, 2003 Order at the Court of Appeals for the District of Columbia
Circuit. On January 8, 2004, the Court of Appeals granted Chevron's motion to
have its appeal consolidated with Chevron's appeal of the FERC's decision in the
Docket No. OR02-4 proceeding and to have the two appeals held in abeyance
pending the outcome of the appeal of the Docket No. OR92-8, et al. proceeding.
On August 13, 2004, the FERC filed a motion to dismiss the pending petitions for
review of the FERC's orders in the OR02-4 and OR03-5 proceedings. SFPP filed a
motion to dismiss Chevron's petitions for review on August 18, 2004. On December
10, 2004, the Court granted the motions to dismiss.

  OR04-3 proceeding. On September 21, 2004, America West Airlines, Inc.,
Southwest Airlines, Co., Northwest Airlines, Inc. and Continental Airlines, Inc.
(collectively "Airlines") filed a complaint against SFPP at the FERC. The
Airlines' complaint alleges that the rates on SFPP's West Line and SFPP's charge
for its gathering enhancement service at Watson Station are not just and
reasonable. The Airlines seek rate reductions and reparations for two years
prior to the filing of their complaint. BP West Coast Products LLC and
ExxonMobil Oil Corporation, ConocoPhillips Company, Navajo Refining Company,
L.P., and ChevronTexaco Products Company all filed timely motions to intervene
in this proceeding. Valero Marketing and Supply Company filed a motion to
intervene one day after the deadline. SFPP answered the Airlines' complaint on
October 12, 2004. On October 29, 2004, the Airlines filed a response to SFPP's
answer and on November 12, 2004, SFPP replied to the Airlines' response. FERC
action on the complaint is pending.

  OR05-4 proceeding. On December 22, 2004, BP West Coast Products LLC and
ExxonMobil Oil Corporation filed a complaint against SFPP at the FERC. The
complaint alleges that SFPP's interstate rates are not just and reasonable, that
certain rates found grandfathered by the FERC are not entitled to such status,
and, if so entitled, that "substantially changed circumstances" have occurred,
removing such protection. The complainants seek rate reductions and reparations
for two years prior to the filing of their complaint and ask that the complaint
be consolidated with the Airlines' complaint in the OR04-3 proceeding.
ConocoPhillips Company, Navajo Refining Company, L.P., and Western Refining
Company, L.P. all filed timely motions to intervene in this proceeding. SFPP
answered the complaint on January 24, 2005. FERC action on the complaint is
pending.

  OR05-5 proceeding. On December 29, 2004, ConocoPhillips filed a complaint
against SFPP at the FERC. The complaint alleges that SFPP's interstate rates are
not just and reasonable, that certain rates found grandfathered by the FERC are
not entitled to such status, and, if so entitled, that "substantially changed
circumstances" have occurred, removing such protection. ConocoPhillips seeks
rate reductions and reparations for two years prior to the filing of their
complaint. BP West Coast Products LLC and ExxonMobil Oil Corporation, Navajo
Refining Company, L.P., and Western Refining Company, L.P. all filed timely
motions to intervene in this proceeding. SFPP answered the complaint on January
28, 2005. FERC action on the complaint is pending.

      California Public Utilities Commission Proceeding

   ARCO, Mobil and Texaco filed a complaint against SFPP with the California
Public Utilities Commission on April 7, 1997. The complaint challenges rates
charged by SFPP for intrastate transportation of refined petroleum products
through its pipeline system in the State of California and requests prospective
rate adjustments. On October 1, 1997, the complainants filed testimony seeking
prospective rate reductions aggregating approximately $15 million per year.

   On August 6, 1998, the CPUC issued its decision dismissing the complainants'
challenge to SFPP's intrastate rates. On June 24, 1999, the CPUC granted limited
rehearing of its August 1998 decision for the purpose of addressing the proper
ratemaking treatment for partnership tax expenses, the calculation of
environmental costs and the public utility status of SFPP's Sepulveda Line and
its Watson Station gathering enhancement facilities. In pursuing these rehearing
issues, complainants sought prospective rate reductions aggregating
approximately $10 million per year.


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  On March 16, 2000, SFPP filed an application with the CPUC seeking authority
to justify its rates for intrastate transportation of refined petroleum products
on competitive, market-based conditions rather than on traditional,
cost-of-service analysis.

  On April 10, 2000, ARCO and Mobil filed a new complaint with the CPUC
asserting that SFPP's California intrastate rates are not just and reasonable
based on a 1998 test year and requesting the CPUC to reduce SFPP's rates
prospectively. The amount of the reduction in SFPP rates sought by the
complainants is not discernible from the complaint.

  The rehearing complaint was heard by the CPUC in October 2000 and the April
2000 complaint and SFPP's market-based application were heard by the CPUC in
February 2001. All three matters stand submitted as of April 13, 2001, and
resolution of these submitted matters may occur within the first or second
quarters of 2005.

  The CPUC subsequently issued a resolution approving a 2001 request by SFPP to
raise its California rates to reflect increased power costs. The resolution
approving the requested rate increase also required SFPP to submit cost data for
2001, 2002, and 2003, and to assist the CPUC in determining whether SFPP's
overall rates for California intrastate transportation services are reasonable.
The resolution reserves the right to require refunds, from the date of issuance
of the resolution, to the extent the CPUC's analysis of cost data to be
submitted by SFPP demonstrates that SFPP's California jurisdictional rates are
unreasonable in any fashion. On February 21, 2003, SFPP submitted the cost data
required by the CPUC, which submittal was protested by Valero Marketing and
Supply Company, Ultramar Inc., BP West Coast Products LLC, Exxon Mobil Oil
Corporation and Chevron Products Company. Issues raised by the protest,
including the reasonableness of SFPP's existing intrastate transportation rates,
were the subject of evidentiary hearings conducted in December 2003 and may be
resolved by the CPUC in the first or second quarter of 2005.

  On November 22, 2004, SFPP filed an application with the CPUC requesting a $9
million increase in existing intrastate rates to reflect the in-service date of
SFPP's replacement and expansion of its Concord-to-Sacramento pipeline. The
requested rate increase, which automatically became effective as of December 22,
2004 pursuant to California Public Utilities Code Section 455.3, is being
collected subject to refund, pending resolution of protests to the application
by Valero Marketing and Supply Company, Ultramar Inc., BP West Coast Products
LLC, Exxon Mobil Oil Corporation and ChevronTexaco Products Company. The CPUC is
expected to resolve the matter by the fourth quarter of 2005.

  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. There is no
way to quantify the potential extent to which the CPUC could determine that
SFPP's existing California rates are unreasonable. With regard to the amount of
dollars potentially subject to refund as a consequence of the CPUC resolution
requiring the provision by SFPP of cost-of-service data, such refunds could
total about $6 million per year from October 2002 to the anticipated date of a
CPUC decision.

  SFPP believes the submission of the required, representative cost data
required by the CPUC indicates that SFPP's existing rates for California
intrastate services remain reasonable and that no refunds are justified.

  We believe that the resolution of such matters will not have a material
adverse effect on our business, financial position, results of operations or
cash flows.

  Trailblazer Pipeline Company

  Rate Case

  As required by its last rate case settlement, Trailblazer Pipeline Company
made a general rate case filing at the FERC on November 29, 2002. The filing
provides for a small rate decrease and a number of non-rate tariff changes. By
an order issued December 31, 2002, the FERC effectively bifurcated the
proceeding. The FERC accepted the rate decrease effective January 1, 2003,
subject to refund and a hearing. The FERC suspended most of the non-rate tariff
changes until June 1, 2003, subject to refund and a technical conference
procedure.


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  Trailblazer sought rehearing of the FERC rate decrease order with respect to
the refund condition. On April 15, 2003, the FERC granted Trailblazer's
rehearing request to remove the refund condition that had been imposed in the
FERC's December 31, 2002 order. Certain intervenors have sought rehearing as to
the FERC's acceptance of certain non-rate tariff provisions.

  The technical conference on non-rate tariff issues was held on February 6,
2003. The non-rate tariff issues include:

  o capacity award procedures;

  o credit procedures;

  o imbalance penalties; and

  o the maximum length of bid terms considered for evaluation in
    the right of first refusal process.

  Comments on the non-rate tariff issues as discussed at the technical
conference were filed by parties in March 2003. On May 23, 2003, the FERC issued
an order deciding non-rate tariff issues and denying rehearing of its prior
order. In the May 23, 2003 order, the FERC:

  o accepted Trailblazer's proposed capacity award procedures with very limited
    changes;

  o accepted Trailblazer's credit procedures subject to very extensive changes,
    consistent with numerous recent orders involving other pipelines;

  o accepted a compromise agreed to by Trailblazer and the active parties under
    which existing shippers must match competing bids in the right of first
    refusal process for up to ten years (in lieu of the current five years); and

  o accepted Trailblazer's withdrawal of daily imbalance charges.

  More specifically, the May 23, 2003 order:

  o allowed shortened notice periods for suspension of service, but required at
    least thirty days notice for service termination;

  o limited prepayments and any other assurance of future performance, such as a
    letter of credit, to three months of service charges except for new
    facilities;

  o required the pipeline to pay interest on prepayments or allow those funds to
    go into an interest-bearing escrow account; and

  o required much more specificity about credit criteria and procedures in
    tariff provisions.

  Certain shippers and Trailblazer sought rehearing of the May 23, 2003 order.
Trailblazer made its compliance filing on June 20, 2003. The tariff changes
under the May 23, 2003 order were made effective as of May 23, 2003, except that
Trailblazer filed to make the revised credit procedures effective August 15,
2003. In an order issued July 13, 2004, the FERC accepted Trailblazer's
compliance filing of June 20, 2003, but required some minor changes, and denied
the rehearing requests. On August 6, 2004, Trailblazer made the compliance
filing to the FERC's July 13, 2004 order. On February 11, 2005, the FERC issued
an order approving the August 6, 2004 compliance filing.

  With respect to the rate review portion of the case, direct testimony was
filed by the FERC Staff and the Indicated Shippers on May 22, 2003 and
cross-answering testimony was filed by the Indicated Shippers on June 19, 2003.
Trailblazer's answering testimony was filed on July 29, 2003.


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<PAGE>


  On September 22, 2003, Trailblazer filed an offer of settlement with the FERC
with respect to the rate review portion of the case. Under the proposed
settlement, Trailblazer's rate would be reduced effective January 1, 2004, from
$0.12 to $0.09 per dekatherm of natural gas, and Trailblazer would file a new
rate case to be effective January 1, 2010.

  On January 23, 2004, the FERC issued an order approving, with modification,
the settlement that was filed on September 22, 2003. The FERC modified the
settlement to expand the scope of severance of contesting parties to present and
future direct interests, including capacity release agreements. The settlement
had provided the scope of the severance to be limited to present direct
interests. On February 20, 2004, Trailblazer filed a letter with the FERC
accepting the modifications to the settlement. As of March 1, 2004, all members
of the Indicated Shippers group opposing the settlement had filed to withdraw
their opposition. On April 9, 2004, the FERC accepted tariff sheets setting out
the settlement rates and, recognizing that the settlement is now unopposed,
dismissed the pending initial decision on Trailblazer's rates as moot. The
settlement rates were put into effect January 1, 2004. On March 26, 2004,
Trailblazer refunded approximately $0.9 million to shippers covering the period
January 1, 2004 through February 29, 2004 pursuant to the terms of the rate case
settlement. On July 13, 2004, the FERC issued an order requiring Trailblazer to
refund additional amounts to shippers previously contesting the settlement.
Trailblazer issued these additional refunds, totaling approximately $73,000 on
July 23, 2004. The FERC issued an order approving the refund report on December
1, 2004, and no issues remain outstanding in this proceeding.

  Fuel Tracking Filing

  On March 31, 2004, Trailblazer made its annual filing to revise its fuel
tracker percentage (its fuel rate) applicable to its expansion shippers. In the
filing, Trailblazer proposed to reduce its fuel rate from the previous level of
2.0% to 1.57%. On April 12, 2004, Marathon Oil Company filed a protest stating
that Trailblazer overstated projected volumes at the Station 601 compressor
facility and proposed that the volumes at the station be reduced, which would
result in a reduction of the fuel rate to 1.20%. On April 30, 2004, the FERC
issued an order allowing Trailblazer to place its proposed 1.57% fuel rate into
effect, subject to refund, on May 1, 2004. The order also established a comment
procedure, pursuant to which Trailblazer filed comments supporting its proposal
on May 20, 2004 and Marathon filed reply comments on June 1, 2004. On July 9,
2004, the FERC issued an order adopting Marathon's position. Trailblazer
implemented the 1.20% fuel rate on August 1, 2004. In addition, in September
2004, Trailblazer refunded approximately $600,000 to affected shippers for the
period May 1, 2004 to July 31, 2004; the period in which Trailblazer's rejected
fuel rate was billed to shippers. On October 8, 2004, Trailblazer filed with the
FERC its refund report supporting the September 2004 refunds. On November 9,
2004, the FERC accepted the refund report as filed and no issues remain
outstanding in this proceeding.

  FERC Order 637

  On August 15, 2000, Trailblazer Pipeline Company made a filing to comply with
the FERC's Order Nos. 637 and 637-A. Trailblazer's compliance filing reflected
changes in:

  o segmentation;

  o scheduling for capacity release transactions;

  o receipt and delivery point rights;

  o treatment of system imbalances;

  o operational flow orders;

  o penalty revenue crediting; and

  o right of first refusal language.


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  On October 15, 2001, the FERC issued its order on Trailblazer's Order No. 637
compliance filing. The FERC approved Trailblazer's proposed language regarding
operational flow orders and rights of first refusal, but required Trailblazer to
make changes to its tariff related to the other issues listed above.

  On November 14, 2001, Trailblazer made its compliance filing pursuant to the
FERC's October 15, 2001 order and also filed for rehearing of the October 15,
2001 order. On April 16, 2003, the FERC issued its order on Trailblazer's
compliance filing and rehearing order. The FERC denied Trailblazer's requests
for rehearing and approved its compliance filing subject to modifications.

  Trailblazer made those modifications in a compliance filing submitted to the
FERC on May 16, 2003. On March 24, 2004, the FERC issued an order directing
Trailblazer to make relatively minor changes to its filing of May 16, 2003.
Trailblazer submitted its compliance filing on April 8, 2004. The FERC issued
an order accepting the April 8, 2004 filing on August 5, 2004. Under the FERC's
orders, limited aspects of Trailblazer's plan (revenue crediting) were
effective as of May 1, 2003. The entire Order No. 637 plan went into effect on
December 1, 2003.

  Trailblazer anticipates no adverse impact on its business as a result of the
implementation of Order No. 637. No issues remain outstanding as to
Trailblazer's Order 637 compliance program.

  Standards of Conduct Rulemaking

  FERC Order No. 2004

  On November 25, 2003, the FERC issued Order No. 2004, adopting new Standards
of Conduct to become effective February 9, 2004. Every interstate natural gas
pipeline was required to file a compliance plan by that date and was required to
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 natural gas pipeline's interaction with many more affiliates
(referred to as "energy affiliates"), including intrastate/Hinshaw natural gas
pipelines (in general, a Hinshaw pipeline is a pipeline that receives gas at or
within a state boundary, is regulated by an agency of that state, and all the
gas it transports is consumed within that state), processors and gatherers and
any company involved in natural gas or electric markets (including natural gas
marketers) even if they do not ship on the affiliated interstate natural gas
pipeline. Local distribution companies are excluded, however, if they do not
make sales to customers not physically attached to their system. The Standards
of Conduct require, among other things, separate staffing of interstate
pipelines and their energy affiliates (but support functions and senior
management at the central corporate level may be shared) and strict limitations
on communications from an interstate pipeline to an energy affiliate.

  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. 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 sales to customers not physically attached
to their system, to be excluded from the rule's definition of energy affiliate.
Separation from these entities would be the most burdensome requirement of the
new rules for us.

  On April 16, 2004, the FERC issued Order No. 2004-A. The FERC extended the
effective date of the new Standards of Conduct from June 1, 2004, to September
1, 2004. Otherwise, the FERC largely denied rehearing of Order No. 2004, but
provided further clarification or adjustment in several areas. The FERC
continued the exemption for local distribution companies which do not make
off-system sales, but clarified that the local distribution company exemption
still applies if the local distribution company is also a Hinshaw pipeline. The
FERC also clarified that a local distribution company can engage in certain
sales and other energy affiliate activities to the limited extent necessary to
support sales to customers located on its distribution system, and sales
necessary to remain in balance under pipeline tariffs, without becoming an
energy affiliate. The FERC declined to exempt natural gas producers. The FERC
also declined to exempt natural gas intrastate and Hinshaw pipelines, processors
and gatherers, but did clarify that such entities will not be energy affiliates
if they do not participate in gas or electric commodity markets, interstate
capacity markets (as capacity holder, agent or manager), or in financial
transactions related to such markets.

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<PAGE>


  The FERC also clarified further the personnel and functions which can be
shared by interstate natural gas pipelines and their energy affiliates,
including senior officers and risk management personnel, and the permissible
role of holding or parent companies and service companies. The FERC also
clarified that day-to-day operating information can be shared by interconnecting
entities. Finally, the FERC clarified that an interstate natural gas pipeline
and its energy affiliate can discuss potential new interconnects to serve the
energy affiliate, but subject to very onerous posting and record-keeping
requirements.

  On July 21, 2004, Kinder Morgan Interstate Gas Transmission LLC and
Trailblazer Pipeline Company filed additional joint requests with the interstate
natural gas pipelines owned by KMI asking for limited exemptions from certain
requirements of FERC Order 2004 and asking for an extension of the deadline for
full compliance with Order 2004 until 90 days after the FERC has completed
action on the pipelines' various rehearing and exemption requests. These
exemptions request relief from the independent functioning and information
disclosure requirements of Order 2004. The exemption requests propose to treat
as energy affiliates, within the meaning of Order 2004, two groups of employees:

  o individuals in the Choice Gas Commodity Group within KMI's retail
    operations; and

  o commodity sales and purchase personnel within our Texas intrastate natural
    gas operations.

  Order 2004 regulations governing relationships between interstate pipelines
and their energy affiliates would apply to relationships with these two groups.
Under these proposals, certain critical operating functions could continue to be
shared.

  On August 2, 2004, the FERC issued Order No. 2004-B. In this order, the FERC
extended the effective date of the new Standards of Conduct from September 1,
2004 to September 22, 2004. Also in this order, among other actions, the FERC
denied the request for rehearing made by the interstate pipelines of KMI and us
to clarify the applicability of the local distribution company and parent
company exemptions to them. In addition, the FERC denied the interstate
pipelines' request for a 90 day extension of time to comply with Order 2004.

  On September 20, 2004, the FERC issued an order which conditionally granted
the July 21, 2004 joint requests for limited exemptions from the requirements of
the Standards of Conduct described above. In that order, FERC directed Kinder
Morgan Interstate Gas Transmission LLC, Trailblazer Pipeline Company and the
affiliated interstate pipelines owned by KMI to submit compliance plans
regarding these exemptions within 30 days. These compliance plans were filed on
October 19, 2004, and set out certain steps taken by us to assure that employees
in the Choice Gas Commodity Group of KMI and the commodity sales and purchase
personnel of our Texas intrastate organizations do not have access to restricted
interstate natural gas pipeline information or receive preferential treatment as
to interstate natural gas pipeline services. The FERC will not enforce
compliance with the independent functioning requirement of the Standards of
Conduct as to these employees until 30 days after it acts on these compliance
filings. In all other respects, we were required to comply with the Standards of
Conduct as of September 22, 2004.

  We have implemented compliance with the Standards of Conduct as of September
22, 2004, subject to the exemptions described in the prior paragraph. Compliance
includes, among other things, the posting of compliance procedures and
organizational information for each interstate pipeline on its Internet website,
the posting of discount and tariff discretion information and the implementation
of independent functioning for energy affiliates not covered by the prior
paragraph (electric and gas gathering, processing or production affiliates).

  On December 21, 2004, the FERC issued Order No. 2004-C. In this order, the
FERC granted rehearing on certain issues and also clarified certain provisions
in the previous FERC 2004 orders. The primary impact on us from Order 2004-C is
the granting of rehearing and allowing local distribution companies to
participate in hedging activity related to on-system sales and still qualify for
exemption from being an energy affiliate.


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<PAGE>


  FERC Policy statement re: Use of Gas Basis Differentials for Pricing

  On July 25, 2003, the FERC issued a Modification to Policy Statement stating
that FERC regulated natural gas pipelines will, on a prospective basis, no
longer be permitted to use gas basis differentials to price negotiated rate
transactions. Effectively, we will no longer be permitted to use commodity price
indices to structure transactions on our FERC regulated natural gas pipelines.
Negotiated rates based on commodity price indices in existing contracts will be
permitted to remain in effect until the end of the contract period for which
such rates were negotiated. Moreover, in subsequent orders in individual
pipeline cases, the FERC has allowed negotiated rate transactions using pricing
indices so long as revenue is capped by the applicable maximum rate(s).
Rehearing on this aspect of the Modification to Policy Statement has been sought
by several pipelines, but the FERC has not yet acted on rehearing. Price indexed
contracts currently constitute an insignificant portion of our contracts on our
FERC regulated natural gas pipelines; consequently, we do not believe that this
Modification to Policy Statement will have a material impact on our operations,
financial results or cash flows.

  Accounting for Integrity Testing Costs

  On November 5, 2004, the FERC issued a Notice of Proposed Accounting Release
that would require FERC jurisdictional entities to recognize costs incurred in
performing pipeline assessments that are a part of a pipeline integrity
management program as maintenance expense in the period incurred. The proposed
accounting ruling was in response to the FERC's finding of diverse practices
within the pipeline industry in accounting for pipeline assessment activities.
The proposed ruling would standardize these practices. Specifically, the
proposed ruling clarifies the distinction between costs for a "one-time
rehabilitation project to extend the useful life of the system," which could be
capitalized, and costs for an "on-going inspection and testing or maintenance
program," which would be accounted for as maintenance and charged to expense in
the period incurred. Comments, along with responses to specific questions posed
by FERC concerning the Notice of Proposed Accounting Release, were due January
19, 2005. We filed our comments on January 19, 2005, asking the FERC to modify
the accounting release to allow capitalization of pipeline assessment costs
associated with projects involving 100 feet or more of pipeline being replaced
or recoated (including discontinuous sections) and to adopt an effective date
for the final rule which is no earlier than January 1, 2006.

  Selective Discounting

  On November 22, 2004, the FERC issued a notice of inquiry seeking comments on
its policy of selective discounting. Specifically, the FERC is asking parties to
submit comments and respond to inquiries regarding the FERC's practice of
permitting pipelines to adjust their ratemaking throughput downward in rate
cases to reflect discounts given by pipelines for competitive reasons - when the
discount is given to meet competition from another gas pipeline. Comments are
due March 2, 2005.

  Other Regulatory

   As discussed above, under "SFPP, L.P. - Federal Regulatory Commission
Proceedings," on July 20, 2004, the United States Court of Appeals for the
District of Columbia Circuit issued its opinion in BP West Coast Products, LLC
v. Federal Energy Regulatory Commission, No. 99-1020, On Petitions for Review of
Orders of the Federal Energy Regulatory Commission (Circuit opinion), addressing
in part the tariffs of SFPP, L.P. Among other things, the Circuit Court opinion
vacated the income tax allowance portion of the FERC opinion and order allowing
recovery in SFPP's rates for income taxes and remanded this and other matters
for further proceedings consistent with the Circuit Court opinion. By its terms,
the opinion only pertains to SFPP, L.P. and it is based on the record in that
case.

   However, on December 2, 2004, the FERC issued a Notice of Inquiry seeking
comments on the implications of the July 20, 2004 opinion of the Court of
Appeals for the District of Columbia Circuit in BP West Coast Producers, LLC, v.
FERC. In reviewing a series of orders involving SFPP, L.P., the court held,
among other things, that the FERC had not adequately justified its policy of
providing an oil pipeline limited partnership with an income tax allowance equal
to the proportion of its limited partnership interests owned by corporate
partners. The FERC is seeking comments on whether the court's ruling applies
only to the specific facts of the SFPP, L.P. proceeding, or also extends to
other capital structures involving partnerships and other forms of ownership.
Comments were due

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January 21, 2005.

  In addition to the matters described above, we may face additional challenges
to our rates in the future. Shippers on our pipelines do have rights to
challenge the rates we charge under certain circumstances prescribed by
applicable regulations. There can be no assurance that we will not face
challenges to the rates we receive for services on our pipeline systems in the
future. In addition, since many of our assets are subject to regulation, we are
subject to potential future changes in applicable rules and regulations that may
have an adverse effect on our business, financial position, results of
operations or cash flows.

  Union Pacific Railroad Company Easements

  SFPP, L.P. and Union Pacific Railroad Company (the successor to Southern
Pacific Transportation Company) are engaged in two proceedings to determine the
extent, if any, to which the rent payable by SFPP for the use of pipeline
easements on rights-of-way held by UPRR should be adjusted pursuant to existing
contractual arrangements for each of the ten year periods beginning January 1,
1994 and January 1, 2004 (Southern Pacific Transportation Company vs. Santa Fe
Pacific Corporation, SFP Properties, Inc., Santa Fe Pacific Pipelines, Inc.,
SFPP, L.P., et al., Superior Court of the State of California for the County of
San Francisco, filed August 31, 1994; and Union Pacific Railroad Company vs.
Santa Fe Pacific Pipelines, Inc., SFPP, L.P., Kinder Morgan Operating L.P. "D",
Kinder Morgan G.P., Inc., et al., Superior Court of the State of California for
the County of Los Angeles, filed July 28, 2004). In the second quarter of 2003,
the trial court set the rent for years 1994 - 2003 at approximately $5.0 million
per year as of January 1, 1994, subject to annual inflation increases throughout
the ten year period. UPRR has appealed this matter to the California Court of
Appeals, and oral arguments were heard on January 25, 2005.

  On August 17, 2004, SFPP was served with a lawsuit seeking to determine the
rent for the ten year period commencing January 1, 2004. A trial date has not
been set.

  Carbon Dioxide Litigation

  Kinder Morgan CO2 Company, L.P., Kinder Morgan G.P., Inc., and Cortez Pipeline
Company are among the named defendants in Shores, et al. v. Mobil Oil Corp., et
al., No. GC-99-01184 (Statutory Probate Court, Denton County, Texas filed
December 22, 1999) and First State Bank of Denton, et al. v. Mobil Oil Corp., et
al., No. 8552-01 (Statutory Probate Court, Denton County, Texas filed March 29,
2001). These cases were originally filed as class actions on behalf of classes
of overriding royalty interest owners (Shores) and royalty interest owners (Bank
of Denton) for damages relating to alleged underpayment of royalties on carbon
dioxide produced from the McElmo Dome Unit. Although classes were initially
certified at the trial court level, appeals resulted in the decertification
and/or abandonment of the class claims. In December 2004, the trial judge orally
announced his intention to dismiss both cases in response to motions filed by
defendants. Orders of dismissal have been submitted but have not, as yet, been
entered.

  On May 13, 2004, William Armor, one of the former plaintiffs in the Shores
matter whose claims were dismissed for improper venue by the Court of Appeals,
filed a new case alleging the same claims (in summary, seeking damages for
underpayment of royalties based on alleged breaches of contractual duties and
covenants, agency duties, civil conspiracy, and related claims) against the same
defendants previously sued in the Shores case, including Kinder Morgan CO2
Company, L.P. and Kinder Morgan Energy Partners, L.P. Armor v. Shell Oil
Company, et al, No. 04-03559 (14th Judicial District, Dallas County Court filed
May 13, 2004). Defendants filed their answers and special exceptions on June 4,
2004. Trial, if necessary, has been scheduled for July 25, 2005.

  Shell CO2 Company, Ltd., predecessor in interest to Kinder Morgan CO2 Company,
L.P., is among the named counter-claim defendants in Shell Western E&P Inc. v.
Gerald O. Bailey and Bridwell Oil Company; No. 98-28630 (215th Judicial District
Court, Harris County, Texas filed June 17, 1998) (the "SWEPI Action"). The
counter-claim plaintiffs are overriding royalty interest owners in the McElmo
Dome Unit and have sued seeking damages for underpayment of royalties on carbon
dioxide produced from the McElmo Dome Unit. The counter-claim plaintiffs have
asserted claims for fraud/fraudulent inducement, real estate fraud, negligent
misrepresentation, breach of fiduciary duty, breach of contract, negligence,
negligence per se, unjust enrichment, violation of the Texas Securities Act, and
open account. Counter-claim plaintiffs seek actual damages, punitive damages, an
accounting, and declaratory relief. The trial court granted a series of summary
judgment motions filed by counter-claim defendants

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on all of counter-plaintiffs' counter-claims except for the fraud-based claims.
In 2004, one of the counter-plaintiffs (Gerald Bailey) amended his counter-suit
to allege purported claims as a private relator under the False Claims Act and
antitrust claims. The federal government elected to not intervene in the False
Claims Act counter-suit. Kinder Morgan CO2 Company, L.P. intends to seek
dismissal of the False Claims Act and antitrust claims through appropriate
motions. No current trial date is set.

  On March 1, 2004, Bridwell Oil Company, one of the named defendants/
counter-claim plaintiffs in the SWEPI Action, filed a new matter in which it
asserts claims which are virtually identical to the counter-claims it asserts
against Shell CO2 Company, Ltd. in the SWEPI Action. Bridwell Oil Co. v. Shell
Oil Co. et al, No. 160,199-B (78th Judicial District, Wichita County Court filed
March 1, 2004). The defendants in this action include Kinder Morgan CO2 Company,
L.P., Kinder Morgan Energy Partners, L.P., various Shell entities, ExxonMobil
entities, and Cortez Pipeline Company. On June 25, 2004, defendants filed
answers, special exceptions, pleas in abatement, and motions to transfer venue
back to the Harris County District Court. The presiding judge in the Wichita
County case stated, in a December 10, 2004 letter decision, that he intended to
abate the case pending resolution of the SWEPI Action. A proposed order has been
submitted but, as yet, has not been entered.

  Kinder Morgan CO2 Company, L.P. and Cortez Pipeline Company are among the
named defendants in Celeste C. Grynberg, et al. v. Shell Oil Company, et al.,
No. 98-CV-43 (Colo. Dist. Ct., Montezuma County filed March 2, 1998). This case
involves claims by overriding royalty interest owners in the McElmo Dome and Doe
Canyon Units seeking damages for underpayment of royalties on carbon dioxide
produced from the McElmo Dome Unit, failure to develop carbon dioxide reserves
at the Doe Canyon Unit, and failure to develop hydrocarbons at both McElmo Dome
and Doe Canyon. The plaintiffs also possess a small working interest at Doe
Canyon. Plaintiffs claim breaches of contractual and potential fiduciary duties
owed by the defendants and also allege other theories of liability including
breach of covenants, civil theft, conversion, fraud/fraudulent concealment,
violation of the Colorado Organized Crime Control Act, deceptive trade
practices, and violation of the Colorado Antitrust Act. In addition to actual or
compensatory damages, plaintiffs seek treble damages, punitive damages, and
declaratory relief relating to the Cortez Pipeline tariff and the method of
calculating and paying royalties on McElmo Dome carbon dioxide. Plaintiffs'
motion for summary judgment concerning alleged underpayment of McElmo Dome
overriding royalties is currently pending before the Court. The parties are
continuing to engage in discovery. No trial date is currently set.

  J. Casper Heimann, Pecos Slope Royalty Trust and Rio Petro LTD, individually
and on behalf of all other private royalty and overriding royalty owners in the
Bravo Dome Carbon Dioxide Unit, New Mexico similarly situated v. Kinder Morgan
CO2 Company, L.P., No. 04-26-CL (8th Judicial District Court, Union County New
Mexico).

  This case involves a purported class action against Kinder Morgan CO2 Company,
L.P. alleging that defendant has failed to pay the full royalty and overriding
royalty ("royalty interests") on the true and proper settlement value of
compressed carbon dioxide produced from the Bravo Dome Unit in the period
beginning January 1, 2000. The complaint purports to assert claims for violation
of the New Mexico Unfair Practices Act, constructive fraud, breach of contract
and of the covenant of good faith and fair dealing, breach of the implied
covenant to market, and claims for an accounting, unjust enrichment, and
injunctive relief. The purported class is comprised of current and former
owners, during the period January 2000 to the present, who have private property
royalty interests burdening the oil and gas leases held by the defendant,
excluding the Commissioner of Public Lands, the United States of America, and
those private royalty interests that are not unitized as part of the Bravo Dome
Unit. The plaintiffs allege that they were members of a class previously
certified as a class action by the United States District Court for the District
of New Mexico in the matter Doris Feerer, et al. v. Amoco Production Company, et
al., USDC N.M. Civ. No. 95-0012 (the "Feerer Class Action"). Plaintiffs allege
that defendant's method of paying royalty interests is contrary to the
settlement of the Feerer Class Action. Defendant has filed a Motion to Compel
Arbitration of this matter pursuant to the arbitration provisions contained in
the Feerer Class Action Settlement Agreement, which motion is currently pending.
No date for arbitration or trial is currently set.

  In addition to the matters listed above, various audits and administrative
inquiries concerning Kinder Morgan CO2 Company L.P.'s royalty and tax payments
on carbon dioxide produced from the McElmo Dome Unit are currently ongoing.
These audits and inquiries involve various federal agencies, the State of
Colorado, the Colorado oil and gas commission, and Colorado county taxing
authorities.

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  RSM Production Company, et al. v. Kinder Morgan Energy Partners, L.P., et al.
(Cause No. 4519, in the District Court, Zapata County Texas, 49th Judicial
District).

  On October 15, 2001, Kinder Morgan Energy Partners, L.P. was served with the
First Supplemental Petition filed by RSM Production Corporation on behalf of the
County of Zapata, State of Texas and Zapata County Independent School District
as plaintiffs. Kinder Morgan Energy Partners, L.P. was sued in addition to 15
other defendants, including two other Kinder Morgan affiliates. Certain entities
we acquired in the Kinder Morgan Tejas acquisition are also defendants in this
matter. The Petition alleges that these taxing units relied on the reported
volume and analyzed heating content of natural gas produced from the wells
located within the appropriate taxing jurisdiction in order to properly assess
the value of mineral interests in place. The suit further alleges that the
defendants undermeasured the volume and heating content of that natural gas
produced from privately owned wells in Zapata County, Texas. The Petition
further alleges that the County and School District were deprived of ad valorem
tax revenues as a result of the alleged undermeasurement of the natural gas by
the defendants. On December 15, 2001, the defendants filed motions to transfer
venue on jurisdictional grounds. On June 12, 2003, plaintiff served discovery
requests on certain defendants. On July 11, 2003, defendants moved to stay any
responses to such discovery.

  United States of America, ex rel., Jack J. Grynberg v. K N Energy (Civil
Action No. 97-D-1233, filed in the U.S. District Court, District of Colorado).

  This action was filed on June 9, 1997 pursuant to the federal False Claims Act
and involves allegations of mismeasurement of natural gas produced from federal
and Indian lands. The Department of Justice has decided not to intervene in
support of the action. The complaint is part of a larger series of similar
complaints filed by Mr. Grynberg against 77 natural gas pipelines (approximately
330 other defendants). Certain entities we acquired in the Kinder Morgan Tejas
acquisition are also defendants in this matter. An earlier single action making
substantially similar allegations against the pipeline industry was dismissed by
Judge Hogan of the U.S. District Court for the District of Columbia on grounds
of improper joinder and lack of jurisdiction. As a result, Mr. Grynberg filed
individual complaints in various courts throughout the country. In 1999, these
cases were consolidated by the Judicial Panel for Multidistrict Litigation, and
transferred to the District of Wyoming. The multidistrict litigation matter is
called In Re Natural Gas Royalties Qui Tam Litigation, Docket No. 1293. Motions
to dismiss were filed and an oral argument on the motion to dismiss occurred on
March 17, 2000. On July 20, 2000, the United States of America filed a motion to
dismiss those claims by Grynberg that deal with the manner in which defendants
valued gas produced from federal leases, referred to as valuation claims. Judge
Downes denied the defendant's motion to dismiss on May 18, 2001. The United
States' motion to dismiss most of plaintiff's valuation claims has been granted
by the court. Grynberg has appealed that dismissal to the 10th Circuit, which
has requested briefing regarding its jurisdiction over that appeal.
Subsequently, Grynberg's appeal was dismissed for lack of appellate
jurisdiction. Discovery to determine issues related to the Court's subject
matter jurisdiction arising out of the False Claims Act is complete. Briefing
has been completed and oral arguments on jurisdiction have been set before the
Special Master for March 17 and 18, 2005. On May 7, 2003, Grynberg sought leave
to file a Third Amended Complaint, which adds allegations of undermeasurement
related to carbon dioxide production. Defendants have filed briefs opposing
leave to amend. Neither the Court nor the Special Master has ruled on Grynberg's
Motion to Amend.

  Mel R. Sweatman and Paz Gas Corporation  v. Gulf Energy Marketing, LLC, et al.

  On July 25, 2002, we were served with this suit for breach of contract,
tortious interference with existing contractual relationships, conspiracy to
commit tortious interference and interference with prospective business
relationship. Mr. Sweatman and Paz Gas Corporation claim that, in connection
with our acquisition of Tejas Gas, LLC, we wrongfully caused gas volumes to be
shipped on our Kinder Morgan Texas Pipeline system instead of our Kinder Morgan
Tejas system. Mr. Sweatman and Paz Gas Corporation allege that this action
eliminated profit on Kinder Morgan Tejas, a portion of which Mr. Sweatman and
Paz Gas Corporation claim they are entitled to receive under an agreement with a
subsidiary of ours acquired in the Tejas Gas acquisition. We filed a motion to
remove the case from venue in Dewitt County, Texas to Harris County, Texas, and
our motion was denied in a venue hearing in November 2002.


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  In a Second Amended Original Petition, Sweatman and Paz assert new and
distinct allegations against us, principally that we were a party to an alleged
commercial bribery committed by us, Gulf Energy Marketing, and Intergen inasmuch
as we, in our role as acquirer of Kinder Morgan Tejas, allegedly paid Intergen
to not renew the underlying Entex contracts belonging to the Tejas/Paz joint
venture. Moreover, new and distinct allegations of breach of fiduciary and
bribery of a fiduciary are also raised in this amended petition for the first
time.

  The parties have engaged in some discovery and depositions. At this stage of
discovery, we believe that our actions were justified and defensible under
applicable Texas law and that the decision not to renew the underlying gas sales
agreements was made unilaterally by persons acting on behalf of Entex. The
plaintiffs have moved for summary judgment asking the court to declare that a
fiduciary relationship existed for purposes of Sweatman's claims. We have moved
for summary judgment on the grounds that:

  o there is no cause-in-fact of the gas sales nonrenewals
    attributable to us; and

  o the defense of legal justification applies to the claims for
    tortuous interference.

  In September 2003 and then again in November 2003, Sweatman and Paz filed
their third and fourth amended petitions, respectively, asserting all of the
claims for relief described above. In addition, the plaintiffs asked that the
court impose a constructive trust on (i) the proceeds of the sale of Tejas and
(ii) any monies received by any Kinder Morgan entity for sales of gas to any
Entex/Reliant entity following June 30, 2002 that replaced volumes of gas
previously sold under contracts to which Sweatman and Paz had a participating
interest pursuant to the joint venture agreement between Tejas, Sweatman and
Paz. In October 2003, the court granted, and then rescinded its order after a
motion to reconsider heard on February 13, 2004, a motion for partial summary
judgment on the issue of the existence of a fiduciary duty.

  On October 27, 2004, the court granted a motion for partial summary judgment
in the defendants' favor, finding that, as a matter of law, Sweatman's interests
in four of the five gas sales contracts at issue terminated in 1992 after those
contracts were amended in their material terms, and thus falling outside the
joint venture itself. In various form, the plaintiffs have amended their
petition to allege various oral and implied joint venture agreements as well as
an oral partnership agreement. The claimants are asking for the imposition of a
constructive trust on the proceeds of gas sales contracts with Entex and its
affiliates that were entered into after the gas sales at issue were unilaterally
terminated by Entex on March 28. 2002, for which Sweatman blames us and our
agents and representatives.

  We believe this suit is without merit and we intend to defend the case
vigorously. We have moved for partial summary judgment on all of Sweatman's
claims, asserting that even in the light most favorable to Sweatman's
assertions, there is no issue of material fact on whether Sweatman even owned an
interest in the underlying gas sales agreements in dispute. That motion was
heard on August 13, 2004, and was granted on October 26, 2004 as to four of the
five gas sales contracts at issue, leaving for further determination at a later
time any remaining claims based upon other theories of recovery not dependent
upon the four gas sales agreements being joint venture property. We have also
filed a no-evidence motion for summary judgment on the plaintiffs' defamation
claims. Trial of the case is set preferentially for February 21, 2005.

  Maher et ux. v. Centerpoint Energy, Inc., Centerpoint Energy Resources Corp.,
Entex Gas Marketing Company, Kinder Morgan Texas Pipeline, L.P., Kinder Morgan
Energy Partners, L.P., Kinder Morgan G.P., Inc., Kinder Morgan Tejas Pipeline,
L.P., Kinder Morgan Tejas Pipeline, GP, Inc., Kinder Morgan Texas Pipeline GP,
Inc., Tejas Gas, LLC, Midcon Corp., Gulf Energy Marketing, LLC, Houston Pipeline
Company, L.P, HPL GP, LLC, and AEP Gas Marketing, L.P., No. 30875 (District
Court, Wharton County Texas).

  On October 21, 2002, Kinder Morgan Texas Pipeline, L.P. and Kinder Morgan
Energy Partners, L.P. were served with the above-entitled Complaint. A First
Amended Complaint was served on October 23, 2002, adding additional defendants
Kinder Morgan G.P., Inc., Kinder Morgan Tejas Pipeline GP, Inc., Kinder Morgan
Texas Pipeline GP, Inc., Tejas Gas, LLC and HPL GP, LLC. A Second Amended
Complaint was filed on January 6, 2003, which added additional proposed
plaintiff class representatives. A Third Amended Complaint was filed on February
4, 2005, which dropped the purported class action allegations and added
additional defendants, Midcon Corp. and Gulf Energy Marketing, LLC. The
Complaint purports to bring an action on behalf of three plaintiffs who

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purchased natural gas for residential purposes from the so-called "Reliant
Defendants" in Texas at any time during the period encompassing "at least the
last ten years."

  The Complaint alleges that Reliant Energy Resources Corp., by and through its
affiliates, has artificially inflated the price charged to residential consumers
for natural gas that it allegedly purchased from the non-Reliant defendants,
including the above-listed Kinder Morgan entities. The Complaint further alleges
that in exchange for Reliant Energy Resources Corp.'s purchase of natural gas at
above market prices, the non-Reliant defendants, including the above-listed
Kinder Morgan entities, sell natural gas to Entex Gas Marketing Company at
prices substantially below market, which in turn sells such natural gas to
commercial and industrial consumers and gas marketers at market price. The
Complaint purports to assert claims for fraud, violations of the Texas Deceptive
Trade Practices Act, and violations of the Texas Utility Code against some or
all of the Defendants, and civil conspiracy against all of the defendants, and
seeks relief in the form of, among other things, actual, exemplary and statutory
damages, civil penalties, interest, attorneys' fees and a constructive trust ab
initio on any and all sums which allegedly represent overcharges by Reliant and
Reliant Energy Resources Corp.

  On November 18, 2002, the Kinder Morgan defendants filed a Motion to Transfer
Venue and, Subject Thereto, Original Answer to the original Complaint. On
February 10, 2005, the Centerpoint defendants removed the case to the United
States District Court for the Southern District of Texas, Houston Division.
Based on the information available to date and our preliminary investigation,
the Kinder Morgan defendants believe that the claims against them are without
merit and intend to defend against them vigorously.

  Weldon Johnson and Guy Sparks , individually and as Representative of Others
Similarly Situated v. Centerpoint Energy, Inc. et. al., No. 04-327-2 (Circuit
Court, Miller County Arkansas).

  On October 8, 2004, plaintiffs filed the above-captioned matter against
numerous defendants including Kinder Morgan Texas Pipeline L.P.; Kinder Morgan
Energy Partners, L.P.; Kinder Morgan G.P., Inc.; KM Texas Pipeline, L.P.; Kinder
Morgan Texas Pipeline G.P., Inc.; Kinder Morgan Tejas Pipeline G.P., Inc.;
Kinder Morgan Tejas Pipeline, L.P.; Gulf Energy Marketing, LLC; Tejas Gas, LLC;
and Midcon Corp. (the "Kinder Morgan Defendants"). The Complaint purports to
bring a class action on behalf of those who purchased natural gas from the
Centerpoint defendants from October 1, 1994 to the date of class certification.

  The Complaint alleges that Centerpoint Energy, Inc., by and through its
affiliates, has artificially inflated the price charged to residential consumers
for natural gas that it allegedly purchased from the non-Centerpoint defendants,
including the above-listed Kinder Morgan entities. The Complaint further alleges
that in exchange for Centerpoint's purchase of such natural gas at above market
prices, the non-Centerpoint defendants, including the above-listed Kinder Morgan
entities, sell natural gas to Centerpoint's non-regulated affiliates at prices
substantially below market, which in turn sells such natural gas to commercial
and industrial consumers and gas marketers at market price. The Complaint
purports to assert claims for fraud, unlawful enrichment and civil conspiracy
against all of the defendants, and seeks relief in the form of actual, exemplary
and punitive damages, interest, and attorneys' fees. The Complaint was served on
the Kinder Morgan Defendants on October 21, 2004. On November 18, 2004, the
Centerpoint Defendants removed the case to the United States District Court,
Western District of Arkansas, Texarkana Division, Civ. Action No. 04-4154. On
January 26, 2005, the Plaintiffs moved to remand the case back to state court,
which motion is currently pending. On December 17, 2004, the Kinder Morgan
Defendants filed a Motion to Dismiss the Complaint, which motion is also
currently pending. Based on the information available to date and our
preliminary investigation, the Kinder Morgan Defendants believe that the claims
against them are without merit and intend to defend against them vigorously.

  Marie Snyder, et al v. City of Fallon, United States Department of the Navy,
Exxon Mobil Corporation, Kinder Morgan Energy Partners, L.P., Speedway Gas
Station and John Does I-X, No. cv-N-02-0251-ECR-RAM (United States District
Court, District of Nevada)("Snyder"); Frankie Sue Galaz, et al v. United States
of America, City of Fallon, Exxon Mobil Corporation, Kinder Morgan Energy
Partners, L.P., Berry Hinckley, Inc., and John Does I-X, No.
cv-N-02-0630-DWH-RAM (United States District Court, District of Nevada)("Galaz
I"); Frankie Sue Galaz, et al v. City of Fallon, Exxon Mobil Corporation, Kinder
Morgan Energy Partners, L.P., Kinder Morgan G.P., Inc., Kinder Morgan Las Vegas,
LLC, Kinder Morgan Operating Limited Partnership "D", Kinder Morgan Services
LLC, Berry Hinkley and Does I-X, No. CV03-03613 (Second Judicial District Court,
State of Nevada, County of Washoe) ("Galaz II); Frankie Sue Galaz, et al v. The
United States of America, the

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City of Fallon, Exxon Mobil Corporation, Kinder Morgan Energy Partners, L.P.,
Kinder Morgan G.P., Inc., Kinder Morgan Las Vegas, LLC, Kinder Morgan Operating
Limited Partnership "D", Kinder Morgan Services LLC, Berry Hinkley and Does I-X,
No.CVN03-0298-DWH-VPC (United States District Court, District of Nevada)("Galaz
III)

  On July 9, 2002, we were served with a purported Complaint for Class Action in
the Snyder case, in which the plaintiffs, on behalf of themselves and others
similarly situated, assert that a leukemia cluster has developed in the City of
Fallon, Nevada. The Complaint alleges that the plaintiffs have been exposed to
unspecified "environmental carcinogens" at unspecified times in an unspecified
manner and are therefore "suffering a significantly increased fear of serious
disease." The plaintiffs seek a certification of a class of all persons in
Nevada who have lived for at least three months of their first ten years of life
in the City of Fallon between the years 1992 and the present who have not been
diagnosed with leukemia.

  The Complaint purports to assert causes of action for nuisance and "knowing
concealment, suppression, or omission of material facts" against all defendants,
and seeks relief in the form of "a court-supervised trust fund, paid for by
defendants, jointly and severally, to finance a medical monitoring program to
deliver services to members of the purported class that include, but are not
limited to, testing, preventative screening and surveillance for conditions
resulting from, or which can potentially result from exposure to environmental
carcinogens," incidental damages, and attorneys' fees and costs.

  The defendants responded to the Complaint by filing Motions to Dismiss on the
grounds that it fails to state a claim upon which relief can be granted. On
November 7, 2002, the United States District Court granted the Motion to Dismiss
filed by the United States, and further dismissed all claims against the
remaining defendants for lack of Federal subject matter jurisdiction. Plaintiffs
filed a Motion for Reconsideration and Leave to Amend, which was denied by the
Court on December 30, 2002. Plaintiffs filed a Notice of Appeal to the United
States Court of Appeals for the 9th Circuit. On March 15, 2004, the 9th Circuit
affirmed the dismissal of this case.

  On December 3, 2002, plaintiffs filed an additional Complaint for Class Action
in the Galaz I matter asserting the same claims in the same court on behalf of
the same purported class against virtually the same defendants, including us. On
February 10, 2003, the defendants filed Motions to Dismiss the Galaz I Complaint
on the grounds that it also fails to state a claim upon which relief can be
granted. This motion to dismiss was granted as to all defendants on April 3,
2003. Plaintiffs have filed a Notice of Appeal to the United States Court of
Appeals for the 9th Circuit. On November 17, 2003, the 9th Circuit dismissed the
appeal, upholding the District Court's dismissal of the case.

  On June 20, 2003, plaintiffs filed an additional Complaint for Class Action
(the "Galaz II" matter) asserting the same claims in Nevada State trial court on
behalf of the same purported class against virtually the same defendants,
including us (and excluding the United States Department of the Navy). On
September 30, 2003, the Kinder Morgan defendants filed a Motion to Dismiss the
Galaz II Complaint along with a Motion for Sanctions. On April 13, 2004,
plaintiffs' counsel voluntarily stipulated to a dismissal with prejudice of the
entire case in State Court. The court has accepted the stipulation and the
parties are awaiting a final order from the court dismissing the case with
prejudice.

  Also on June 20, 2003, the plaintiffs in the previously filed Galaz matters
(now dismissed) filed yet another Complaint for Class Action in the United
States District Court for the District of Nevada (the "Galaz III" matter)
asserting the same claims in United States District Court for the District of
Nevada on behalf of the same purported class against virtually the same
defendants, including us. The Kinder Morgan defendants filed a Motion to Dismiss
the Galaz III matter on August 15, 2003. On October 3, 2003, the plaintiffs
filed a Motion for Withdrawal of Class Action, which voluntarily drops the class
action allegations from the matter and seeks to have the case proceed on behalf
of the Galaz family only. On December 5, 2003, the District Court granted the
Kinder Morgan defendants' Motion to Dismiss, but granted plaintiff leave to file
a second Amended Complaint. Plaintiff filed a Second Amended Complaint on
December 13, 2003, and a Third Amended Complaint on January 5, 2004. The Kinder
Morgan defendants filed a Motion to Dismiss the Third Amended Complaint on
January 13, 2004. The Motion to Dismiss was granted with prejudice on April 30,
2004. On May 7, 2004, Plaintiff filed a Notice of Appeal in the United States
Court of Appeals for the 9th Circuit, which appeal is currently pending.


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  Richard Jernee, et al v. Kinder Morgan Energy Partners, et al, No. CV03-03482
(Second Judicial District Court, State of Nevada, County of Washoe) ("Jernee").

  On May 30, 2003, a separate group of plaintiffs, individually and on behalf of
Adam Jernee, filed a civil action in the Nevada State trial court against us and
several Kinder Morgan related entities and individuals and additional unrelated
defendants ("Jernee"). Plaintiffs in the Jernee matter claim that defendants
negligently and intentionally failed to inspect, repair and replace unidentified
segments of their pipeline and facilities, allowing "harmful substances and
emissions and gases" to damage "the environment and health of human beings."
Plaintiffs claim that "Adam Jernee's death was caused by leukemia that, in turn,
is believed to be due to exposure to industrial chemicals and toxins."
Plaintiffs purport to assert claims for wrongful death, premises liability,
negligence, negligence per se, intentional infliction of emotional distress,
negligent infliction of emotional distress, assault and battery, nuisance,
fraud, strict liability, and aiding and abetting, and seek unspecified special,
general and punitive damages. The Kinder Morgan defendants filed Motions to
Dismiss the complaint on November 20, 2003, which Motions are currently pending.
In addition, plaintiffs and the defendant City of Fallon have appealed the Trial
Court's ruling on initial procedural matters concerning proper venue. On March
29, 2004, the Nevada Supreme Court stayed the action pending resolution of these
procedural matters on appeal. This appeal is currently pending.

  Floyd Sands, et al v. Kinder Morgan Energy Partners, et al, No. CV03-05326
(Second Judicial District Court, State of Nevada, County of Washoe) ("Sands").

  On August 28, 2003, a separate group of plaintiffs, represented by the counsel
for the plaintiffs in the Jernee matter, individually and on behalf of Stephanie
Suzanne Sands, filed a civil action in the Nevada State trial court against us
and several Kinder Morgan related entities and individuals and additional
unrelated defendants ("Sands"). Plaintiffs in the Sands matter claim that
defendants negligently and intentionally failed to inspect, repair and replace
unidentified segments of their pipeline and facilities, allowing "harmful
substances and emissions and gases" to damage "the environment and health of
human beings." Plaintiffs claim that Stephanie Suzanne Sands' death was caused
by leukemia that, in turn, is believed to be due to exposure to industrial
chemicals and toxins. Plaintiffs purport to assert claims for wrongful death,
premises liability, negligence, negligence per se, intentional infliction of
emotional distress, negligent infliction of emotional distress, assault and
battery, nuisance, fraud, strict liability, and aiding and abetting, and seek
unspecified special, general and punitive damages. The Kinder Morgan defendants
were served with the Complaint on January 10, 2004. On February 26, 2004, the
Kinder Morgan defendants filed a Motion to Dismiss and a Motion to Strike, which
motions are currently pending. In addition, plaintiffs and the defendant City of
Fallon have appealed the Trial Court's ruling on initial procedural matters
concerning proper venue and a peremptory challenge of the trial judge by the
plaintiffs. On April 27, 2004, the Nevada Supreme Court stayed the action
pending resolution of these procedural matters on appeal. This appeal is
currently pending.

  Based on the information available to date, our own preliminary investigation,
and the positive results of investigations conducted by State and Federal
agencies, we believe that the claims against us in these matters are without
merit and intend to defend against them vigorously.

  Meritage Homes Corp., Monterey Homes Construction, Inc., and Monterey Homes
Arizona, Inc. v. Kinder Morgan Energy Partners, L.P. and SFPP Limited
Partnership, No. CIV 05 021 TUCCKJ, United States District Court, Arizona.

  On January 28, 2005, Meritage Homes Corp. and its above-named affiliates filed
a Complaint in the above-entitled action against us and SFPP, LP. The Plaintiffs
are homebuilders who constructed a subdivision known as Silver Creek II located
in Tucson, Arizona. Plaintiffs allege that, as a result of a July 30, 2003
pipeline rupture and accompanying release of petroleum products, soil and
groundwater adjacent to, on and underlying portions of Silver Creek II became
contaminated. Plaintiffs allege that they have incurred and continue to incur
costs, damages and expenses associated with the delay of closings of home sales
within Silver Creek II and damage to their reputation and goodwill as a result
of the rupture and release. Plaintiffs' Complaint purports to assert claims for
negligence, breach of contract, trespass, nuisance, strict liability,
subrogation and indemnity, and negligence per se. Plaintiffs seek "no less than
$1,500,000 in compensatory damages and necessary response costs," a declaratory
judgment, interest, punitive damages and attorneys' fees and costs. We dispute
the legal and factual bases for many of Plaintiffs' claimed compensatory
damages, deny that punitive damages are appropriate under the facts, and intend
to vigorously defend this action.

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  Walnut Creek, California Pipeline Rupture

  On November 9, 2004, Mountain Cascade, Inc., a third-party contractor on a
water main replacement project hired by East Bay Municipal Utility District,
struck and ruptured an underground petroleum pipeline owned and operated by
SFPP, LP in Walnut Creek, California. An explosion occurred immediately
following the rupture that resulted in five fatalities and several injuries to
employees or contractors of Mountain Cascade. The incident is currently under
investigation by Cal/OSHA and the California State Fire Marshall's Office, and
we are cooperating with such investigations.

  Juana Lilian Arias, et. al v. Kinder Morgan, Inc., Kinder Morgan Energy
Partners, L.P., Mountain Cascade, Inc., and Does 1-30, No. RG05195567 (Superior
Court, Alameda County, California).

  The above-referenced complaint for personal injuries and wrongful death was
filed on January 26, 2005. Plaintiffs allege that Victor Javier Rodriguez was
killed as a result of the rupture by Mountain Cascade, Inc. of SFPP, LP's
petroleum pipeline in Walnut Creek, California and the resulting explosion and
fire. Plaintiffs allege that defendants failed to properly locate and mark the
location of the petroleum pipeline. The complaint purports to assert claims for
negligence, unfair competition, strict liability and intentional
misrepresentation. Plaintiffs seek unspecified general damages, incidental
damages, economic damages, disgorgement of profits, exemplary damages, interest,
attorneys' fees and costs.

  Marilu Angeles, et. al v. Kinder Morgan, Inc., Kinder Morgan Energy Partners,
L.P., Mountain Cascade, Inc., Does 1-30 and Mariel Hernandez, No. RG05195680
(Superior Court, Alameda County, California).

  The above-referenced complaint for personal injuries and wrongful death was
filed on January 26, 2005. Plaintiffs allege that Israel Hernandez was killed as
a result of the rupture by Mountain Cascade, Inc. of SFPP, LP's petroleum
pipeline in Walnut Creek, California and the resulting explosion and fire.
Plaintiffs allege that defendants failed to properly locate and mark the
location of the petroleum pipeline. The complaint purports to assert claims for
negligence, unfair competition, strict liability and intentional
misrepresentation. Plaintiffs seek unspecified general damages, incidental
damages, economic damages, disgorgement of profits, exemplary damages, interest,
attorneys' fees and costs.

  Jeremy and Johanna Knox v. Mountain  Cascade,  Inc, Kinder Morgan Energy
Partners of Houston, Inc., and Does 1 to 50, No. C 05-00281 (Superior Court,
Contra Costa County, California).

  The above-referenced complaint for personal injuries was filed on February 2,
2005. Plaintiffs allege that Jeremy Knox was injured as a result of the rupture
by Mountain Cascade, Inc. of SFPP, LP's petroleum pipeline in Walnut Creek,
California and the resulting explosion and fire. Plaintiffs allege that
defendants failed to properly locate and mark the location of the petroleum
pipeline. Plaintiffs assert claims for negligence, loss of consortium, and
exemplary damages in an unspecified amount.

  Based upon our initial investigation of the cause of the rupture of SFPP, LP's
petroleum pipeline by Mountain Cascade, Inc. and the resulting explosion and
fire, we intend to deny liability for the resulting deaths, injuries and
damages, to vigorously defend against such claims, and to seek contribution and
indemnity from the responsible parties.

  Marion County, Mississippi Litigation

  In 1968, Plantation Pipe Line Company discovered a release from its 12-inch
pipeline in Marion County, Mississippi. The pipeline was immediately repaired.
In 1998 and 1999, 62 lawsuits were filed on behalf of 263 plaintiffs in the
Circuit Court of Marion County, Mississippi. The majority of the claims are
based on alleged exposure from the 1968 release, including claims for property
damage and personal injury.

  During the fourth quarter of 2004, a settlement was reached and settlements
have been completed between almost all of the plaintiffs and Plantation. Five
remaining plaintiffs that did not participate in the settlements described above
have indicated in writing a willingness to settle with Plantation. It is
anticipated that all of the

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proceedings to complete the settlements will be completed by the end of the
first quarter of 2005. We believe that the ultimate resolution of these Marion
County, Mississippi cases will not have a material effect on our business,
financial position, results of operations or cash flows.

  Exxon Mobil Corporation v. GATX Corporation, Kinder Morgan Liquids Terminals,
Inc. and ST Services, Inc.

  On April 23, 2003, Exxon Mobil Corporation filed the Complaint in the Superior
Court of New Jersey, Gloucester County. We filed our answer to the Complaint on
June 27, 2003, in which we denied ExxonMobil's claims and allegations as well as
included counterclaims against ExxonMobil. The lawsuit relates to environmental
remediation obligations at a Paulsboro, New Jersey liquids terminal owned by
ExxonMobil from the mid-1950s through November 1989, by GATX Terminals Corp.
from 1989 through September 2000, and owned currently by ST Services, Inc. Prior
to selling the terminal to GATX Terminals, ExxonMobil performed an environmental
site assessment of the terminal required prior to sale pursuant to state law.
During the site assessment, ExxonMobil discovered items that required
remediation and the New Jersey Department of Environmental Protection issued an
order that required ExxonMobil to perform various remediation activities to
remove hydrocarbon contamination at the terminal. ExxonMobil, we understand, is
still remediating the site and has not been removed as a responsible party from
the state's cleanup order; however, ExxonMobil claims that the remediation
continues because of GATX Terminals' storage of a fuel additive, MTBE, at the
terminal during GATX Terminals' ownership of the terminal. When GATX Terminals
sold the terminal to ST Services, the parties indemnified one another for
certain environmental matters. When GATX Terminals was sold to us, GATX
Terminals' indemnification obligations, if any, to ST Services may have passed
to us. Consequently, at issue is any indemnification obligations we may owe to
ST Services in respect to environmental remediation of MTBE at the terminal. The
Complaint seeks any and all damages related to remediating MTBE at the terminal,
and, according to the New Jersey Spill Compensation and Control Act, treble
damages may be available for actual dollars incorrectly spent by the successful
party in the lawsuit for remediating MTBE at the terminal. The parties have
recently completed discovery. In October 2004, the judge assigned to the case
dismissed himself from the case based on a conflict, and the new judge has
ordered the parties to participate in mandatory mediation. The mediation is
scheduled for March 2005.

  Exxon Mobil Corporation v. Enron Gas Processing Co., Enron Corp., as party in
interest for Enron Helium Company, a division of Enron Corp., Enron Liquids
Pipeline Co., Enron Liquids Pipeline Operating Limited Partnership, Kinder
Morgan Operating L.P. "A," and Kinder Morgan, Inc., No. 2000-45252 (189th
Judicial District Court, Harris County, Texas)

  On September 1, 2000, Plaintiff Exxon Mobil Corporation filed its Original
Petition and Application for Declaratory Relief against Kinder Morgan Operating
L.P. "A," Enron Liquids Pipeline Operating Limited Partnership n/k/a Kinder
Morgan Operating L.P. "A," Enron Liquids Pipeline Co. n/k/a Kinder Morgan G.P.,
Inc., Enron Gas Processing Co. n/k/a ONEOK Bushton Processing, Inc., and Enron
Helium Company. Plaintiff added Enron Corp. as party in interest for Enron
Helium Company in its First Amended Petition and added Kinder Morgan, Inc. as a
Defendant. The claims against Enron Corp. were severed into a separate cause of
action. Plaintiff's claims are based on a Gas Processing Agreement entered into
on September 23, 1987 between Mobil Oil Corp. and Enron Gas Processing Company
relating to gas produced in the Hugoton Field in Kansas and processed at the
Bushton Plant, a natural gas processing facility located in Kansas. Plaintiff
also asserts claims relating to the Helium Extraction Agreement entered between
Enron Helium Company (a division of Enron Corp.) and Mobil Oil Corporation dated
March 14, 1988. Plaintiff alleges that Defendants failed to deliver propane and
to allocate plant products to Plaintiff as required by the Gas Processing
Agreement and originally sought damages of approximately $5.9 million.

  Plaintiff filed its Third Amended Petition on February 25, 2003. In its Third
Amended Petition, Plaintiff alleges claims for breach of the Gas Processing
Agreement and the Helium Extraction Agreement, requests a declaratory judgment
and asserts claims for fraud by silence/bad faith, fraudulent inducement of the
1997 Amendment to the Gas Processing Agreement, civil conspiracy, fraud, breach
of a duty of good faith and fair dealing, negligent misrepresentation and
conversion. As of April 7, 2003, Plaintiff alleged economic damages for the
period from November 1987 through March 1997 in the amount of $30.7 million. On
May 2, 2003, Plaintiff added claims for the period from April 1997 through
February 2003 in the amount of $12.9 million. On June 23, 2003, Plaintiff filed
a Fourth Amended Petition that reduced its total claim for economic damages to
$30.0 million.
On October 5, 2003,

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Plaintiff filed a Fifth Amended Petition that purported to add a cause of action
for embezzlement. On February 10, 2004, Plaintiff filed its Eleventh
Supplemental Responses to Requests for Disclosure that restated its alleged
economic damages for the period of November 1987 through December 2003 as
approximately $37.4 million. The matter went to trial on June 21, 2004. On June
30, 2004, the jury returned a unanimous verdict in favor of all defendants as to
all counts. Final Judgment was entered in favor of the defendants on August 19,
2004. The Plaintiff has stated that it is currently reviewing its appellate
options.

  Although no assurances can be given, we believe that we have meritorious
defenses to all of these actions, that, to the extent an assessment of the
matter is possible, we have established an adequate reserve to cover potential
liability, and that these matters will not have a material adverse effect on our
business, financial position, results of operations or cash flows.

  Proposed Office of Pipeline Safety Civil Penalty and Compliance Order

  On July 15, 2004, the U.S. Department of Transportation's Office of Pipeline
Safety ("OPS") issued a Proposed Civil Penalty and Proposed Compliance Order
(the "Proposed Order") concerning alleged violations of certain federal
regulations concerning our pipeline Integrity Management Program. The violations
alleged in the Proposed Order are based upon the results of inspections of our
Integrity Management Program at our products pipelines facilities in Orange,
California and Doraville, Georgia conducted in April and June of 2003,
respectively. As a result of the alleged violations, the OPS seeks to have us
implement a number of changes to our Integrity Management Program and also seeks
to impose a proposed civil penalty of $325,000. We have already addressed a
number of the concerns identified by the OPS and intend to continue to work with
the OPS to ensure that our Integrity Management Program satisfies all applicable
regulations. However, we dispute some of the OPS findings and disagree that
civil penalties are appropriate, and therefore have requested an administrative
hearing on these matters according to the U.S. Department of Transportation
regulations. A hearing date is expected to occur in the second quarter of 2005.

  Environmental Matters

  We are subject to environmental cleanup and enforcement actions from time to
time. In particular, the federal Comprehensive Environmental Response,
Compensation and Liability Act (CERCLA) generally imposes joint and several
liability for cleanup and enforcement costs on current or predecessor owners and
operators of a site, among others, without regard to fault or the legality of
the original conduct. Our operations are also subject to federal, state and
local laws and regulations relating to protection of the environment. Although
we believe our operations are in substantial compliance with applicable
environmental law and regulations, risks of additional costs and liabilities are
inherent in pipeline, terminal and carbon dioxide field and oil field
operations, and there can be no assurance that we will not incur significant
costs and liabilities. Moreover, it is possible that other developments, such as
increasingly stringent environmental laws, regulations and enforcement policies
thereunder, and claims for damages to property or persons resulting from our
operations, could result in substantial costs and liabilities to us.

  We are currently involved in the following governmental proceedings related to
compliance with environmental regulations associated with our assets and have
established a reserve to address the costs associated with the cleanup:

  o several ground water hydrocarbon remediation efforts under administrative
    orders or related state remediation programs issued by the California
    Regional Water Quality Control Board and several other state agencies for
    assets associated with SFPP, L.P.;

  o groundwater and soil remediation efforts under administrative orders issued
    by various regulatory agencies on those assets purchased from GATX
    Corporation, comprising Kinder Morgan Liquids Terminals LLC, CALNEV Pipe
    Line LLC and Central Florida Pipeline LLC;

  o groundwater and soil remediation efforts under administrative orders or
    related state remediation programs issued by various regulatory agencies on
    those assets purchased from ExxonMobil; ConocoPhillips; and Charter Triad,
    comprising Kinder Morgan Southeast Terminals, LLC.; and


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  o groundwater and soil remediation efforts under administrative orders or
    related state remediation programs issued by various regulatory agencies on
    those assets comprising Plantation Pipe Line Company, including a ground
    water remediation effort taking place between Chevron, Plantation Pipe Line
    Company and the Alabama Department of Environmental Management.

  Tucson, Arizona

  On July 30, 2003, SFPP, L.P. suffered a sudden and accidental rupture of one
of its liquid products pipelines in the vicinity of Tucson, Arizona. The rupture
resulted in the release of petroleum product into the soil and groundwater in
the immediate vicinity of the rupture.

  On September 11, 2003, the Arizona Department of Environmental Quality
("ADEQ") issued a Notice of Violation indicating that ADEQ "has reason to
believe" that SFPP violated certain Arizona statutes and rules due to the
discharge of petroleum product to the environment as a result of the pipeline
rupture. ADEQ asserted that such alleged violations could result in the
imposition of civil penalties against SFPP. SFPP timely responded to the Notice
of Violation, disputed its validity, and provided the information requested in
the Notice of Violation. According to ADEQ written policy, a Notice of Violation
is not an enforcement action, and is instead "an enforcement compliance
assurance tool used by ADEQ." ADEQ's policy also states that although ADEQ has
the "authority to issue appealable administrative orders compelling compliance,
a Notice of Violation has no such force or effect."

  On November 13, 2003, ADEQ sent a second Notice of Violation with respect to
the pipeline rupture and release, stating that ADEQ had reason to believe that a
violation of additional Arizona regulations had resulted from the discharge of
petroleum, because the petroleum had reached groundwater. ADEQ asserted that
such alleged violations could result in the imposition of civil penalties
against SFPP. SFPP timely responded to this second Notice of Violation, disputed
its validity, and provided the information requested in the second Notice of
Violation.

  On January 19, 2005, SFPP, L.P. and ADEQ announced a settlement with the terms
of the settlement set forth in a consent judgment filed with the Maricopa County
Superior Court. Under the terms of the settlement, we will pay $500,000 to the
State of Arizona in full settlement of any possible claims by the state arising
out of the release. The settlement expressly provides that we do not admit any
wrongdoing or violation of environmental law. We are currently evaluating the
long term costs of the cleanup. A substantial portion of those costs are
recoverable through insurance.

  Cordelia, California

  On April 28, 2004, we discovered a spill of diesel fuel into a marsh near
Cordelia, California from a section of pipeline on our Pacific Operations.
Current estimates indicate that the size of the spill was approximately 2,450
barrels. Upon discovery of the spill and notification to regulatory agencies, a
unified response was implemented with the United States Coast Guard, the
California Department of Fish and Game, the Office of Spill Prevention and
Response ("OSPR") and us. The damaged section of the pipeline has been removed
and replaced, and the pipeline resumed operations on May 2, 2004. We have
completed recovery of free flowing diesel from the marsh and completed an
enhanced biodegradation program for removal of the remaining constituents bound
up in soils. The property has been turned back to the owners for its stated
purpose. There will be ongoing monitoring under the oversight of the California
Regional Water Quality Control Board until the site conditions demonstrate there
are no further actions required. The circumstances surrounding the release and
impact thereof are currently under review by the OSPR and the United States
Environmental Protection Agency.

  San Diego, California

  In June 2004, we entered into discussions with the City of San Diego with
respect to impacted groundwater beneath the City's stadium property in San Diego
resulting from operations at the Mission Valley terminal facility. The City has
requested that SFPP work with the City as they seek to re-develop options for
the stadium area including future use of both groundwater aquifer and real
estate development. The City of San Diego and SFPP are working cooperatively
towards a settlement and a long term plan as SFPP continues to remediate the
impacted

                                      178
<PAGE>


groundwater. We do not expect the cost of any settlement and remediation plan to
be material. This site has been, and currently is, under the regulatory
oversight and order of the California Regional Water Quality Control Board.

  Baker, California

   In November 2004, our CALNEV pipeline, which transports refined petroleum
products from Colton, California to Las Vegas, Nevada, experienced a failure in
the line from external damage, resulting in a release of gasoline that affected
approximately two acres of land in the high desert administered by The Bureau of
Land Management, an agency within the U.S. Department of the Interior.
Remediation has been conducted and continues for product in the soils. All
agency requirements have been met and the site will be closed upon completion of
the soil remediation.

  Oakland, California

   In February 2005, we were contacted by the U.S. Coast Guard regarding a
potential release of jet fuel in the Oakland, California area. Our northern
California team responded and discovered that one of our product pipelines had
been damaged by a third party, which resulted in a release of jet fuel which
migrated to the storm drain system. We have coordinated the remediation of the
impacts from this release.

  Other Environmental

  On March 30, 2004, the Texas Commission on Environmental Quality (TCEQ) issued
a Notice of Enforcement Action related to our CO2 segment's Snyder Gas Plant. We
are currently in final settlement discussions with TCEQ regarding this issue and
do not expect the cost of any settlement to be material. In addition, we are
from time to time involved in civil proceedings relating to damages alleged to
have occurred as a result of accidental leaks or spills of refined petroleum
products, natural gas liquids, natural gas and carbon dioxide.

  Furthermore, our review of assets related to Kinder Morgan Interstate Gas
Transmission LLC indicates possible environmental impacts from petroleum and
used oil releases into the soil and groundwater at nine sites. Additionally, our
review of assets related to Kinder Morgan Texas Pipeline and Kinder Morgan Tejas
indicates possible environmental impacts from petroleum releases into the soil
and groundwater at nine sites. Further delineation and remediation of any
environmental impacts from these matters will be conducted. Reserves have been
established to address these issues.

  Additionally, we are involved with and have been identified as a potentially
responsible party in several federal and state superfund sites. Environmental
reserves have been established for those sites where our contribution is
probable and reasonably estimable.

  Although no assurance can be given, we believe that the ultimate resolution of
the environmental matters set forth in this note will not have a material
adverse effect on our business, financial position, results of operations or
cash flows. Many factors may change in the future affecting our reserve
estimates, such as regulatory changes, groundwater and land use near our sites,
and changes in cleanup technology. As of December 31, 2004, we have accrued an
environmental reserve of $40.9 million. Our reserve estimates range in value
from approximately $40.9 million to approximately $77.6 million, and we have
recorded a liability equal to the low end of the range.

  Other

  We are a defendant in various lawsuits arising from the day-to-day operations
of our businesses. Although no assurance can be given, we believe, based on our
experiences to date, that the ultimate resolution of such items will not have a
material adverse impact on our business, financial position, results of
operations or cash flows.


                                      179
<PAGE>


17.  Recent Accounting Pronouncements

  FASB Staff Position Nos. FAS 106-1 and FAS 106-2

  In January 2004, the Financial Accounting Standards Board issued FASB Staff
Position FAS 106-1, "Accounting and Disclosure Requirements Related to the New
Medicare Prescription Drug, Improvement and Modernization Act of 2003", referred
to in this report as the Act. This Staff Position permits a sponsor of a
post-retirement health care plan that provides a prescription drug benefit to
make a one-time election to postpone accounting for the effects of the Act.

  In May 2004, the FASB issued Staff Position FAS 106-2, "Accounting and
Disclosure Requirements Related to the Medicare Prescription Drug, Improvement
and Modernization Act of 2003," which supersedes Staff Position FAS 106-1
effective July 1, 2004. Staff Position FAS 106-2 provides transitional guidance
for accounting for the effects of the Act on the accumulated projected benefit
obligation and periodic post-retirement health care benefit expense. This Staff
Position does not have any immediate effect on our consolidated financial
statements.

  EITF 03-06

  In March 2004, the Emerging Issues Task Force issued Statement No. 03-06, or
EITF 03-06, "Participating Securities and the Two-Class Method under Financial
Accounting Standards Board Statement No. 128, Earnings Per Share." EITF 03-06
addresses a number of questions regarding the computation of earnings per share
by companies that have issued securities other than common stock that
contractually entitle the holder to participate in dividends and earnings of the
company when, and if, it declares dividends on its common stock. The Statement
also provides further guidance in applying the two-class method of calculating
earnings per share, clarifying what constitutes a participating security and how
to apply the two-class method of computing earnings per share once it is
determined that a security is participating, including how to allocate
undistributed earnings to such a security. EITF 03-06 was effective for fiscal
periods beginning after March 31, 2004. The adoption of EITF 03-06 did not
result in a change in our earnings per unit for any of the periods presented or
prior periods.

  SFAS No. 151

  In November 2004, the FASB issued SFAS No. 151, "Inventory Costs," an
amendment of Accounting Research Bulletin No. 43, Chapter 4, "Inventory
Pricing." This Statement clarifies that abnormal amounts of idle facility
expense, freight, handling costs, and wasted materials (spoilage) should be
recognized as current-period charges. In addition, the Statement requires that
allocation of fixed production overheads to the costs of conversion be based on
the normal capacity of the production facilities. The provisions of this
Statement are to be applied prospectively and are effective for inventory costs
incurred during fiscal years beginning after June 15, 2005. We do not expect the
adoption of this Statement to have any immediate effect on our consolidated
financial statements.

  SFAS No. 123R

  In December 2004, the FASB issued SFAS No. 123R (revised 2004), "Share-Based
Payment." This Statement amends SFAS No. 123, "Accounting for Stock-Based
Compensation," and requires companies to expense the value of employee stock
options and similar awards. Significant provisions of SFAS No. 123R include the
following:

  o share-based payment awards result in a cost that will be measured at fair
    value on the awards' grant date, based on the estimated number of awards
    that are expected to vest. Compensation cost for awards that vest would not
    be reversed if the awards expire without being exercised;

  o when measuring fair value, companies can choose an option-pricing model that
    appropriately reflects their specific circumstances and the economics of
    their transactions;

  o companies will recognize compensation cost for share-based payment awards as
    they vest, including the related tax effects. Upon settlement of share-based
    payment awards, the tax effects will be recognized in the income statement
    or additional paid-in capital; and


                                      180
<PAGE>


  o public companies are allowed to select from three alternative transition
    methods - each having different reporting implications.

  In October 2004, the FASB decided to delay by six months the effective date
for public companies to implement SFAS No. 123R (revised 2004). The new
Statement is now effective for public companies for interim and annual periods
beginning after June 15, 2005. Public companies with calendar year-ends will be
required to adopt SFAS No. 123R in the third quarter of 2005. We are currently
reviewing the effects of this accounting Statement; however, we have not granted
common unit options since May 2000 and we do not expect the adoption of this
Statement to have any immediate effect on our consolidated financial statements.

  SFAS No. 152

  In December 2004, the FASB issued SFAS No. 152, "Accounting for Real Estate
Time-Sharing Transactions." This Statement amends SFAS No. 66, "Accounting for
Sales of Real Estate" to reference the financial accounting and reporting
guidance for real estate time-sharing transactions that is provided in American
Institute of Certified Public Accountants Statement of Position No. 04-2,
"Accounting for Real Estate Time-Sharing Transactions", or SOP 04-2. SFAS No.
152 also amends SFAS No. 67, "Accounting for Costs and Initial Rental Operations
of Real Estate Projects," to state that the guidance for (a) incidental
operations and (b) costs incurred to sell real estate projects does not apply to
real estate time-sharing transactions. The accounting for those operations and
costs is subject to the guidance of SOP 04-2. SFAS No. 152 is effective for
financial statement for fiscal years beginning after June 15, 2005. We do not
expect the adoption of this Statement to have any immediate effect on our
consolidated financial statements.

  SFAS No. 153

  In December 2004, the FASB issued SFAS No. 153, "Exchanges of Nonmonetary
Assets." This Statement amends Accounting Principles Board Opinion No. 29,
"Accounting for Nonmonetary Transactions," which is based on the principal that
exchanges of nonmonetary assets should be measured based on the fair value of
the assets exchanged. However, APB No. 29 included certain exceptions to that
principal. SFAS No. 153 amends APB No. 29 to eliminate the exception for
nonmonetary exchanges of similar productive assets and replaces it with a
general exception for exchanges of nonmonetary assets that do not have
commercial substance. A nonmonetary exchange has commercial substance if the
future cash flows of the entity are expected to change significantly as a result
of the exchange. The provisions of this Statement shall be effective for
nonmonetary asset exchanges occurring in fiscal periods beginning after June 15,
2005. Earlier application is permitted and the Statement shall be applied
prospectively. We do not expect the adoption of this Statement to have any
immediate effect on our consolidated financial statements.

18.  Quarterly Financial Data (Unaudited)

<TABLE>
<CAPTION>
                                                                         Basic         Diluted
                              Operating    Operating                  Net Income     Net Income
                              Revenues      Income      Net Income     per Unit       per Unit
                              --------      ------      ----------     --------       --------
                                          (In thousands, except per unit amounts)
<S>                          <C>          <C>           <C>             <C>            <C>
2004
     First Quarter.....      $1,822,256   $ 225,142     $ 191,754       $ 0.52         $ 0.52
     Second Quarter....       1,957,182     231,364       195,218         0.51           0.51
     Third Quarter.....       2,014,659     252,836       217,342         0.59           0.59
     Fourth Quarter....       2,138,764     264,654       227,264         0.59           0.59
2003
     First Quarter(a)..      $1,788,838   $ 195,152     $ 170,478       $ 0.52         $ 0.52
     Second Quarter....       1,664,447     199,562       168,957         0.48           0.48
     Third Quarter.....       1,650,842     204,965       174,176         0.49           0.49
     Fourth Quarter....       1,520,195     207,010       183,726         0.51           0.51
----------
</TABLE>

(a) 2003 first quarter includes a benefit of $3,465 due to a cumulative effect
   adjustment related to a change in accounting for asset retirement
   obligations. Net income before cumulative effect of a change in accounting
   principle was $167,013 and basic and diluted net income before cumulative
   effect of a change in accounting principle was $0.50.

                                      181
<PAGE>


19.  Supplemental  Information on Oil and Gas Producing  Activities (Unaudited)

  The Supplementary Information on Oil and Gas Producing Activities is
presented as required by SFAS No. 69, "Disclosures about Oil and Gas Producing
Activities." The supplemental information includes capitalized costs related to
oil and gas producing activities; costs incurred for the acquisition of oil and
gas producing activities, exploration and development activities; and the
results of operations from oil and gas producing activities. Supplemental
information is also provided for per unit production costs; oil and gas
production and average sales prices; the estimated quantities of proved oil and
gas reserves; the standardized measure of discounted future net cash flows
associated with proved oil and gas reserves; and a summary of the changes in the
standardized measure of discounted future net cash flows associated with proved
oil and gas reserves.

  Our capitalized costs consisted of the following (in thousands):

            Capitalized Costs Related to Oil and Gas Producing Activities
                                                        December 31,
                                         --------------------------------------
Consolidated Companies(a)                    2004          2003          2002
                                         -----------   -----------   ----------
Wells and equipment, facilities and
  other..............................    $   815,311   $   601,744   $  198,082
Leasehold............................        315,100       234,996       47,787
                                         -----------   -----------   ----------
Total proved oil and gas properties..      1,130,411       836,740      245,869
Accumulated depreciation and
  depletion..........................       (174,802)      (72,572)     (27,164)
                                         -----------   -----------   ----------
Net capitalized costs................    $   955,609   $   764,168   $  218,705
                                         ===========   ===========   ==========
----------

(a) Amounts relate to Kinder Morgan CO2 Company, L.P. and Consolidated
   Subsidaries. Includes capitalized asset retirement costs and associated
   accumulated depreciation. There are no capitalized costs associated with
   unproved oil and gas properties for the periods reported.

                                                        December 31,
                                                        ------------
Equity Investee(a)                                          2002
                                                        ------------
Net capitalized costs..............................     $    60,257
                                                        ============
----------

(a) Amounts relate to our previous 15% ownership interest in MKM Partners, L.P.,
   which we accounted for under the equity method. MKM Partners, L.P. was
   dissolved on June 30, 2003. There are no capitalized costs associated with
   unproved oil and gas properties for the period reported.

  Our costs incurred for property acquisition, exploration and development were
as follows (in thousands):

         Costs Incurred in Exploration, Property Acquisitions and Development
                                                 Year Ended December 31,
                                         ---------------------------------------
Consolidated Companies(a)                    2004          2003          2002
                                         ------------  ------------  -----------
Property Acquisition
  Proved oil and gas properties.......   $       -     $   325,022   $       -
Development(b)........................      293,671        265,849      128,014

----------

(a) Amounts relate to Kinder Morgan CO2 Company, L.P. and Consolidated
   Subsidaries. There are no capitalized costs associated with unproved oil and
   gas properties for the periods reported. All capital expenditures were made
   to develop our proved oil and gas properties and no exploration costs were
   incurred for the periods reported.

(b) Includes all capitalized and expensed costs.

  For the years ended December 31, 2003 and 2002, we incurred development costs
related to our previous 15% equity interest in MKM Partners, L.P. in the amounts
of $1.8 million and $3.8 million, respectively.

  Our results of operations from oil and gas producing activities for each of
the years 2004, 2003 and 2002 are shown in the following table:




                                      182
<PAGE>



       Results of Operations for Oil and Gas Producing Activities
                                                          Consolidated
                                                           Companies(a)
                                                          --------------
  For the Year Ended December 31, 2004                    (In thousands)
  Revenues............................................... $    361,809
  Expenses:
  Production costs.......................................     (131,501)
  Other operating expenses...............................      (44,043)
  Depreciation, depletion and amortization expenses......     (104,147)
                                                          -------------
    Total expenses.......................................     (279,691)
                                                          -------------
  Results of operations for oil and gas producing
   activities............................................ $     82,118
                                                          =============
  For  the Year Ended December 31, 2003
  Revenues............................................... $    171,270
  Expenses:
  Production costs.......................................      (63,929)
  Other operating expenses(b)............................      (22,387)
  Depreciation, depletion and amortization expenses......      (47,404)
                                                          -------------
    Total expenses.......................................     (133,720)
                                                          -------------
  Results of operations for oil and gas producing
   activities............................................ $     37,550
                                                          =============
  For the Year Ended December 31, 2002
  Revenues............................................... $     84,744
  Expenses:
  Production costs.......................................      (38,449)
  Other operating expenses(b)............................      (11,123)
  Depreciation, depletion and amortization expenses......      (17,995)
                                                          -------------
    Total expenses.......................................      (67,567)
                                                          -------------
  Results of operations for oil and gas producing
   activities............................................ $     17,177
                                                          =============
  Equity Investee(c)
  For the Year Ended December 31, 2003................... $      3,682
                                                          =============
  For  the Year Ended December 31, 2002.................. $      7,806
                                                          =============
----------

(a) Amounts relate to Kinder Morgan CO2 Company, L.P. and Consolidated
   Subsidaries.

(b) Consists primarily of carbon dioxide expense.

(c) Amounts relate to our previous 15% ownership interest in MKM Partners, L.P.,
    which we accounted for under the equity method. MKM Partners, L.P. was
    dissolved on June 30, 2003.

  Operating statistics from our oil and gas producing activities for each of the
years 2004, 2003 and 2002 are shown in the following table:

<TABLE>
<CAPTION>
               Results of Operations for Oil and Gas Producing Activities - Unit Prices and Costs
                                                                           Year Ended December 31,
                                                                   2004            2003          2002
                                                               ------------   ------------   -----------
<S>                                                            <C>            <C>            <C>
  Consolidated Companies(a)
    Production costs per barrel of oil equivalent(b)(c)(d).       $    9.71     $     8.98     $    10.19
                                                               ============   ============   ============
    Production costs per total barrels of oil equivalent(e)       $    8.63     $     7.87     $     9.12
                                                               ============   ============   ============
    Crude oil production (MBbl/d)..........................            32.5           18.0            9.6
                                                               ============   ============   ============
    Natural gas liquids production (MBbl/d)(d).............             3.7            1.3            0.6
    Natural gas liquids production from gas plants(MBbl/d)(e)           4.0            2.4            1.5
                                                               ------------   ------------   ------------
      Total natural gas liquids production(MBbl/d).........             7.7            3.7            2.1
                                                               ============   ============   ============
    Natural gas production (MMcf/d)(d).....................             4.4            1.6            0.6
    Natural gas production from gas plants(MMcf/d)(e)......             3.9            2.0            1.5
                                                               ------------   ------------   ------------
      Total natural gas production(MMcf/d).................             8.3            3.6            2.1
                                                               ============   ============   ============
    Average sales prices including hedge gains/losses:
      Crude oil price per Bbl..............................       $   25.72     $    23.73     $    22.45
                                                               ============   ============   ============
      Natural gas liquids price per Bbl....................       $   31.37     $    22.49     $    23.20
                                                               ============   ============   ============
      Natural gas price per Mcf............................       $    5.27     $     4.40     $     1.80
                                                               ============   ============   ============
      Total natural gas liquids price per Bbl(e)...........       $   31.33     $    21.77     $    24.60
                                                               ============   ============   ============
      Total natural gas price per Mcf(e)...................       $    5.24     $     4.50     $     2.60
                                                               ============   ============   ============
    Average sales prices excluding hedge gains/losses:
       Crude oil price per Bbl.............................       $   40.91     $    31.26     $    25.22
                                                               ============   ============   ============
       Natural gas liquids price per Bbl...................       $   31.68     $    24.70     $    23.13
                                                               ============   ============   ============
       Natural gas price per Mcf...........................       $    5.27     $     4.40     $     1.80
                                                               ============   ============   ============
</TABLE>

                                      183
<PAGE>


----------

(a) Amounts relate to Kinder Morgan CO2 Company, L.P. and Consolidated
    Subsidaries.

(b) Computed using production costs, excluding transportation costs, as defined
    by the Securities and Exchange Commisson. Natural gas volumes were converted
    to barrels of oil equivalent (BOE) using a conversion factor of six mcf of
    natural gas to one barrel of oil.

(c) Production costs include labor, repairs and maintenance, materials,
    supplies, fuel and power, property taxes, severance taxes, and general and
    administrative expenses directly related to oil and gas producing
    activities.

(d) Includes only production attributable to leasehold ownership.

(e) Includes production attributable to our ownership in processing plants and
    third party processing agreements.

*   Less than 0.1 MMcf per day.


  The table below represents our estimate of proved crude oil, natural gas
liquids and natural gas reserves based upon our evaluation of pertinent
geological and engineering data in accordance with United States Securities and
Exchange Commission regulations. Estimates of proved reserves have been prepared
by our team of reservoir engineers and geoscience professionals and are reviewed
by members of our senior management with professional training in petroleum
engineering to ensure that we consistently apply rigorous professional standards
and the reserve definitions prescribed by the United States Securities and
Exchange Commission.

  Netherland, Sewell and Associates, Inc., independent oil and gas consultants,
have reviewed the estimates of proved reserves of natural gas, natural gas
liquids and crude oil that we have attributed to our net interest in oil and gas
properties as of December 31, 2004. Based upon their review of more than 99% of
our reserve estimates, it is their judgment that the estimates are reasonable in
the aggregate.

  We believe the geologic and engineering data examined provides reasonable
assurance that the proved reserves are recoverable in future years from known
reservoirs under existing economic and operating conditions. Estimates of proved
reserves are subject to change, either positively or negatively, as additional
information becomes available and contractual and economic conditions change.

  Proved oil and gas reserves are the estimated quantities of crude oil, natural
gas and natural gas liquids which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions, that is, prices and
costs as of the date the estimate is made. Prices include consideration of
changes in existing prices provided only by contractual arrangements, but not on
escalations based upon future conditions. Proved developed reserves are the
quantities of crude oil, natural gas liquids and natural gas expected to be
recovered through existing investments in wells and field infrastructure under
current operating conditions. Proved undeveloped reserves require additional
investments in wells and related infrastructure in order to recover the
production.

  During 2004, we filed estimates of our oil and gas reserves for the year 2003
with the Energy Information Administration of the U. S. Department of Energy on
Form EIA-23. The data on Form EIA-23 was presented on a different basis, and
included 100% of the oil and gas volumes from our operated properties only,
regardless of our net interest. The difference between the oil reserves reported
on Form EIA-23 and those reported in this report exceeds 5%.



                                      184
<PAGE>


                            Reserve Quantity Information
                                                     Consolidated Companies(a)
                                                     -------------------------
                                              Crude Oil     NGLs      Nat. Gas
                                               (MBbls)    (MBbls)    (MMcf)(d)
                                              ---------  ---------  -----------
Proved developed and undeveloped reserves:
As of December 31, 2001....................     12,284      1,879      6,746
  Revisions of previous estimates..........     60,927     14,009     10,932
  Production...............................     (3,505)      (230)      (228)
  Purchases of reserves in place...........      1,013        185        746
                                             ----------  ---------  ---------
As of December 31, 2002....................     70,719     15,843     18,196
  Revisions of previous estimates(b).......      2,037     (1,404)   (14,538)
  Production...............................     (6,579)      (444)      (582)
  Purchases of reserves in place...........     50,431      2,268        217
  Sales of reserves in place...............          -          -          -
                                             ----------  ---------  ---------
As of December 31, 2003....................    116,608     16,263      3,293
  Revisions of previous estimates..........     19,030      5,350       (120)
  Production...............................    (11,907)    (1,368)    (1,583)
                                             ----------  ---------  ---------
As of December 31, 2004....................    123,731     20,245      1,590
                                             ==========  =========  =========

Equity Investee(c)
As of December 31, 2001....................      4,629         44        136
As of December 31, 2002....................      5,454        362        370

Proved developed reserves:
As of December 31, 2001....................      8,699      1,341      4,951
As of December 31, 2002....................     15,918      3,211      5,149
As of December 31, 2003(b).................     64,879      8,160      2,551
As of December 31, 2004(b).................     71,307      8,873      1,357
----------

(a) Amounts relate to Kinder Morgan CO2 Company, L.P. and Consolidated
    Subsidaries.

(b) The downward revision in natural gas reserves was primarily attributable to
    natural gas reserves used as fuel on lease for the power generation
    facility.

(c) Amounts relate to our previous 15% ownership interest in MKM Partners, L.P.,
    which we accounted for under the equity method. MKM Partners, L.P. was
    dissolved on June 30, 2003.

(d) Natural gas reserves are computed at 14.65 pounds per square inch absolute
    and 60 degress fahrenheit.


  The standardized measure of discounted cash flows and summary of the changes
in the standardized measure computation from year-to-year are prepared in
accordance with SFAS No. 69. The assumptions that underly the computation of the
standardized measure of discounted cash flows may be summarized as follows:

  o the standardized measure includes our estimate of proved crude oil, natural
    gas liquids and natural gas reserves and projected future production volumes
    based upon year-end economic conditions;

  o pricing is applied based upon year-end market prices adjusted for fixed or
    determinable contracts that are in existence at year-end;

  o future development and production costs are determined based upon actual
    cost at year-end;

  o the standardized measure includes projections of future abandonment costs
    based upon actual costs at year-end; and

  o a discount factor of 10% per year is applied annually to the future net
    cash flows.



                                      185
<PAGE>



   Standardized Measure of Discounted Future Net Cash Flows Related to
                       Proved Oil and Gas Reserves
                                                            Consolidated
                                                            Companies(a)
                                                           --------------
                                                           (In thousands)
As of December 31, 2004
  Future cash inflows from production.................     $   5,799,658
  Future production costs.............................        (1,935,597)
  Future development costs(b).........................          (502,172)
                                                           --------------
    Undiscounted future net cash flows................         3,361,889
  10% annual discount.................................        (1,316,923)
                                                           --------------
    Standardized measure of discounted future net cash
     flows............................................     $   2,044,966
                                                           ==============

As of December 31, 2003
  Future cash inflows from production.................     $   4,149,369
  Future production costs.............................        (1,347,822)
  Future development costs(b).........................          (540,900)
                                                           --------------
    Undiscounted future net cash flows................         2,260,647
  10% annual discount.................................          (852,832)
                                                           --------------
    Standardized measure of discounted future net
     cash flows.......................................     $   1,407,815
                                                           ==============

As of December 31, 2002
  Future cash inflows from production.................     $   2,630,701
  Future production costs.............................        (1,355,947)
  Future development costs(b).........................          (470,256)
                                                           --------------
    Undiscounted future net cash flows................           804,498
  10% annual discount.................................          (290,386)
                                                           --------------
    Standardized measure of discounted future net cash
     flows............................................     $     514,112
                                                           ==============

Equity Investee(c)
As of December 31, 2002                                    $      55,352
                                                           ==============
----------

(a) Amounts relate to Kinder Morgan CO2 Company, L.P. and Consolidated
    Subsidaries.

(b) Includes abandonment costs.

(c) Amounts relate to our previous 15% ownership interest in MKM Partners, L.P.,
    which we accounted for under the equity method. MKM Partners, L.P. was
    dissolved on June 30, 2003.


  The following table represents our estimate of changes in the standardized
measure of discounted future net cash flows from proved reserves:



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<PAGE>



 Changes in the Standardized Measure of Discounted Future Net Cash Flows From
                          Proved Oil and Gas Reserves
                                                            Consolidated
                                                            Companies(a)
                                                           --------------
                                                           (In thousands)

Present value as of January 1, 2002...................     $      24,025
  Changes during the year:
    Revenues less production and other costs..........           (35,173)
    Net changes in prices, production and other costs.            91,715
    Development costs incurred........................           128,014
    Net changes in future development costs...........          (405,689)
    Purchases of reserves in place....................            12,019
    Revisions of previous quantity estimates..........           697,930
    Accretion of discount.............................             2,302
    Timing differences and other......................            (1,031)
                                                           --------------
  Net change for the year ............................           490,087
                                                           --------------
Present value as of December 31, 2002.................     $     514,112
  Changes during the year:
    Revenues less production and other costs..........           (84,954)
    Net changes in prices, production and other costs.           331,366
    Development costs incurred........................           265,849
    Net changes in future development costs...........          (309,843)
    Purchases of reserves in place....................           689,593
    Sales of reserves in place........................                 -
    Revisions of previous quantity estimates..........           (23,412)
    Accretion of discount.............................            51,183
    Timing differences and other......................           (26,079)
                                                           --------------
  Net change for the year ............................           893,703
                                                           --------------
Present value as of December 31, 2003.................     $   1,407,815
  Changes during the year:
    Revenues less production and other costs..........          (186,265)
    Net changes in prices, production and other costs.           324,260
    Development costs incurred........................           293,671
    Net changes in future development costs...........          (270,114)
    Revisions of previous quantity estimates..........           396,946
    Accretion of discount.............................           136,939
    Timing differences and other......................           (58,286)
                                                           --------------
  Net change for the year ............................           637,151
                                                           --------------
Present value as of December 31, 2004.................     $   2,044,966
                                                           ==============
----------

(a) Amounts relate to Kinder Morgan CO2 Company, L.P. and Consolidated
    Subsidaries.



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<PAGE>


                                   SIGNATURES

   Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.

                                  KINDER MORGAN ENERGY PARTNERS, L.P.
                                  (A Delaware Limited Partnership)

                                  By: KINDER MORGAN G.P., INC.,
                                  its General Partner

                                  By: KINDER MORGAN MANAGEMENT, LLC,
                                  its Delegate

                                  By:  /s/ C. Park Shaper
                                  ---------------------------------
                                  C. Park Shaper,
                                  Executive Vice President
                                  and Chief Financial Officer

Date: March 4, 2005

   Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons in the capacities and on
the dates indicated.

       Signature                     Title                             Date
       ---------                     -----                             ----

/s/ RICHARD D. KINDER     Chairman of the Board.  Chief            March 4, 2005
---------------------     Executive Officer and President
Richard D. Kinder         of Kinder Morgan Management, LLC,
                          Delegate of Kinder Morgan G.P.,
                          Inc.

/s/ EDWARD O. GAYLORD     Director of Kinder Morgan                March 4, 2005
---------------------
Edward O. Gaylord         Management, LLC, Delegate of
                          Kinder Morgan G.P., Inc.

/s/ GARY L. HULTQUIST     Director of Kinder Morgan                March 4, 2005
---------------------
Gary L. Hultquist         Management, LLC, Delegate of
                          Kinder Morgan G.P., Inc.

/s/ PERRY M. WAUGHTAL     Director of Kinder Morgan                March 4, 2005
---------------------
Perry M. Waughtal         Management, LLC, Delegate of
                          Kinder Morgan G.P., Inc.

/s/ C. PARK SHAPER        Director, Executive Vice President       March 4, 2005
---------------------     and Chief Financial Officer of
C. Park Shaper            Kinder Morgan Management, LLC,
                          Delegate of Kinder Morgan G.P., Inc.
                          (principal financial officer and
                          principal accounting officer)




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