> **Exhibit 99.1**

```

                          INDEX TO FINANCIAL STATEMENTS

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

Report of Independent Auditors........................................   92

Consolidated  Statements of Income for the years ended
December 31, 2003, 2002, and 2001.....................................   93

Consolidated  Statements of  Comprehensive  Income for the
years ended December 31, 2003, 2002, and 2001.........................   94

Consolidated Balance Sheets as of December 31, 2003 and 2002..........   95

Consolidated  Statements  of Cash Flows for the years
ended  December 31, 2003, 2002, and 2001..............................   96

Consolidated  Statements of Partners'  Capital for the
years ended December 31, 2003, 2002, and 2001.........................   97

Notes to Consolidated Financial Statements............................   98

                                       91
<PAGE>

                         Report of Independent Auditors

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

In our opinion, the consolidated financial statements listed in the accompanying
index present fairly, in all material respects, the financial position of Kinder
Morgan Energy Partners, L.P. and its subsidiaries (the Partnership) at December
31, 2003 and 2002, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 2003 in conformity with
accounting principles generally accepted in the United States of America. These
financial statements are the responsibility of the Partnership's management; our
responsibility is to express an opinion on these financial statements based on
our audits. We conducted our audits of these statements in accordance with
auditing standards generally accepted in the United States of America, which
require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

As discussed in Note 4 to the consolidated financial statements, the Partnership
changed its method of accounting for asset retirement obligations effective
January 1, 2003.

As discussed in Note 8 to the consolidated financial statements, the Partnership
changed its method of accounting for goodwill and other intangible assets
effective January 1, 2002.

As discussed in Note 14 to the consolidated financial statements, the
Partnership changed its method of accounting for derivative instruments and
hedging activities effective January 1, 2001.

/s/ PricewaterhouseCoopers LLP

Houston, Texas
March 3, 2004

                                       92
<PAGE>

<TABLE>
<CAPTION>

                    KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

                        CONSOLIDATED STATEMENTS OF INCOME

                                                                       Year Ended December 31,
                                                               --------------------------------------
                                                                  2003          2002          2001
                                                               ----------    ----------    ----------
                                                               (In thousands except per unit amounts)
<S>                                                            <C>           <C>           <C>
   Revenues
     Natural gas sales.....................................    $4,889,235    $2,740,518    $1,627,037
     Services..............................................     1,377,745     1,272,640     1,161,643
     Product sales and other...............................       357,342       223,899       157,996
                                                               ----------    ----------    ----------
                                                                6,624,322     4,237,057     2,946,676
                                                               ----------    ----------    ----------
   Costs and Expenses
     Gas purchases and other costs of sales................     4,880,118     2,704,295     1,657,689
     Operations and maintenance............................       397,723       376,479       352,407
     Fuel and power........................................       108,112        86,413        73,188
     Depreciation and amortization.........................       219,032       172,041       142,077
     General and administrative............................       150,435       122,205       113,540
     Taxes, other than income taxes........................        62,213        51,326        43,947
                                                               ----------    ----------    ----------
                                                                5,817,633     3,512,759     2,382,848
                                                               ----------    ----------    ----------

   Operating Income........................................       806,689       724,298       563,828

   Other Income (Expense)
     Earnings from equity investments......................        92,199        89,258        84,834
     Amortization of excess cost of
       equity investments..................................        (5,575)       (5,575)       (9,011)
     Interest, net.........................................      (181,357)     (176,460)     (171,457)
     Other, net............................................         7,601         1,698         1,962
   Minority Interest.......................................        (9,054)       (9,559)      (11,440)
                                                               ----------    ----------    ----------

   Income Before Income Taxes and Cumulative
     Effect of a Change in Accounting Principle............       710,503       623,660       458,716

   Income Taxes............................................        16,631        15,283        16,373
                                                               ----------    ----------    ----------

   Income Before Cumulative Effect of a Change
   in Accounting Principle.................................       693,872       608,377       442,343

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

   Net Income..............................................    $  697,337    $  608,377    $  442,343
                                                               ==========    ==========    ==========

   Calculation of Limited Partners'
     Interest in Net Income:
   Income Before Cumulative Effect of a
     Change in Accounting Principle........................    $  693,872    $  608,377    $  442,343
   Less: General Partner's interest........................      (326,489)     (270,816)     (202,095)
                                                               ----------    ----------    ----------
   Limited Partners' interest..............................       367,383       337,561       240,248
   Add: Limited Partners' interest in
     Change in Accounting Principle........................         3,430             -             -
                                                               ----------    ----------    ----------
   Limited Partners' interest in Net Income................    $  370,813    $  337,561    $  240,248
                                                               ==========    ==========    ==========

   Basic and Diluted Limited Partners'
   Net Income per Unit:
   Income Before Cumulative Effect of a
     Change in Accounting Principle........................    $      1.98   $     1.96    $     1.56
   Cumulative effect adjustment from change
     in accounting for asset retirement obligations........           0.02            -             -
                                                               -----------   ----------    ----------
   Net Income..............................................    $      2.00   $     1.96    $     1.56
                                                               ===========   ==========    ==========

   Weighted average number of units used in
     computation of Limited Partners' Net
     Income per Unit:
   Basic...................................................       185,384       172,017       153,901
                                                               ==========    ==========    ==========

   Diluted.................................................       185,494       172,186       154,110
                                                               ==========    ==========    ==========
</TABLE>

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

                                       93
<PAGE>

<TABLE>
<CAPTION>

                    KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

                      CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

                                                                 Year Ended December 31,
                                                           ----------------------------------
                                                              2003        2002        2001
                                                           ---------   ---------    ---------
                                                                     (In thousands)
<S>                                                        <C>         <C>          <C>
   Net Income..........................................    $ 697,337   $ 608,377    $ 442,343
   Cumulative effect transition adjustment.............           --          --      (22,797)
   Change in fair value of derivatives
     used for hedging purposes.........................     (192,618)   (116,560)      35,162
   Reclassification of change in fair
     value of derivatives to net income................       82,065       7,477       51,461
                                                           ---------   ---------    ---------
   Comprehensive Income................................    $ 586,784   $ 499,294    $ 506,169
                                                           =========   =========    =========
</TABLE>

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

                                       94
<PAGE>

              KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

                           CONSOLIDATED BALANCE SHEETS

                                                              December 31,
                                                        -----------------------
                                                            2003        2002
                                                        ----------   ----------
                          ASSETS                         (Dollars in thousands)
 Current Assets
   Cash and cash equivalents.........................    $  23,329   $   41,088
   Accounts and notes receivable
      Trade..........................................      562,974      457,583
      Related parties................................       27,587       17,907
   Inventories
      Products.......................................        7,214        4,722
      Materials and supplies.........................       10,783        7,094
   Gas imbalances
      Trade..........................................       36,449       21,595
      Related parties................................        9,084        3,893
   Gas in underground storage........................        8,160       11,029
   Other current assets..............................       19,942      104,479
                                                        ----------   ----------
                                                           705,522      669,390
 Property, Plant and Equipment, net..................    7,091,558    6,244,242
 Investments.........................................      404,345      451,374
 Notes receivable....................................        2,422        3,823
 Goodwill............................................      729,510      716,610
 Other intangibles, net..............................       13,202       17,324
 Deferred charges and other assets...................      192,623      250,813
                                                        ----------   ----------
 Total Assets........................................   $9,139,182   $8,353,576
                                                        ==========   ==========
                     LIABILITIES AND PARTNERS' CAPITAL
 Current Liabilities
   Accounts payable
      Trade..........................................    $ 477,783   $  373,368
      Related parties................................            -       43,742
   Current portion of long-term debt.................        2,248            -
   Accrued interest..................................       52,356       52,500
   Deferred revenues.................................       10,752        4,914
   Gas imbalances....................................       49,912       40,092
   Accrued other liabilities.........................      211,328      298,711
                                                        ----------   ----------
                                                           804,379      813,327
 Long-Term Liabilities and Deferred Credits
   Long-term debt
      Outstanding....................................    4,316,678    3,659,533
      Market value of interest rate swaps............      121,464      166,956
                                                        ----------   ----------
                                                         4,438,142    3,826,489
   Deferred revenues.................................       20,975       25,740
   Deferred income taxes.............................       38,106       30,262
   Asset retirement obligations......................       34,898            -
   Other long-term liabilities and deferred credits..      251,691      199,796
                                                        ----------   ----------
                                                         4,783,812    4,082,287
 Commitments and Contingencies (Notes 13 and 16)
 Minority Interest...................................       40,064       42,033
                                                        ----------   ----------
 Partners' Capital
   Common Units (134,729,258 and 129,943,218
     units issued and outstanding as of
     December 31, 2003 and 2002,
     respectively)...................................    1,946,116    1,844,553
   Class B Units (5,313,400 and 5,313,400
     units issued and outstanding as of
     December 31, 2003 and 2002,
     respectively)...................................      120,582      123,635
   i-Units (48,996,465 and 45,654,048
     units issued and outstanding as
     of December 31, 2003 and 2002,
     respectively)...................................    1,515,659    1,420,898
   General Partner...................................       84,380       72,100
   Accumulated other comprehensive loss..............     (155,810)     (45,257)
                                                        ----------   ----------
                                                         3,510,927    3,415,929
                                                        ----------   ----------
 Total Liabilities and Partners' Capital.............   $9,139,182   $8,353,576
                                                        ==========   ==========

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

                                       95
<PAGE>

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

                      CONSOLIDATED STATEMENTS OF CASH FLOWS

                                                                                       Year Ended December 31,
                                                                               --------------------------------------
                                                                                  2003          2002          2001
                                                                              -----------   -----------   -----------
                                                                                           (In thousands)
<S>                                                                           <C>           <C>           <C>
Cash Flows From Operating Activities
Net income................................................................    $   697,337   $   608,377   $   442,343
Adjustments to reconcile net income to net cash provided by operating
activities:
  Cumulative effect adj. from change in accounting for asset retirement
    obligations...........................................................         (3,465)           --            --
  Depreciation, depletion and amortization................................        219,032       172,041       142,077
  Amortization of excess cost of equity investments.......................          5,575         5,575         9,011
  Earnings from equity investments........................................        (92,199)      (89,258)      (84,834)
Distributions from equity investments.....................................         83,000        77,735        68,832
Changes in components of working capital:
  Accounts receivable.....................................................       (180,632)     (177,240)      174,098
  Other current assets....................................................         (1,858)       (7,583)       22,033
  Inventories.............................................................         (2,945)       (1,713)       22,535
  Accounts payable........................................................         92,702       288,712      (183,179)
  Accrued liabilities.....................................................          9,740        26,132       (47,792)
  Accrued taxes...........................................................         (4,904)        2,379         8,679
FERC rate reparations and refunds.........................................        (44,944)           --            --
Other, net................................................................         (7,923)      (35,462)        7,358
                                                                              -----------   -----------   -----------
Net Cash Provided by Operating Activities.................................        768,516       869,695       581,161
                                                                              -----------   -----------   -----------

Cash Flows From Investing Activities
Acquisitions of assets....................................................       (349,867)     (908,511)   (1,523,454)
Additions to property, plant and equip. for expansion and maintenance
  projects................................................................       (576,979)     (542,235)     (295,088)
Sale of investments, property, plant and equipment, net of removal costs..          2,090        13,912         9,043
Acquisitions of investments...............................................        (10,000)       (1,785)           --
Contributions to equity investments.......................................        (14,052)      (10,841)       (2,797)
Other.....................................................................          5,747        (1,420)       (6,597)
                                                                              -----------   -----------   -----------
Net Cash Used in Investing Activities.....................................       (943,061)   (1,450,880)   (1,818,893)
                                                                              -----------   -----------   -----------

Cash Flows From Financing Activities
Issuance of debt..........................................................      4,674,605     3,803,414     4,053,734
Payment of debt...........................................................     (4,014,296)   (2,985,322)   (3,324,161)
Loans to related party....................................................             --            --       (17,100)
Debt issue costs..........................................................         (5,204)      (17,006)       (8,008)
Proceeds from issuance of common units....................................        175,567         1,586         4,113
Proceeds from issuance of i-units.........................................             --       331,159       996,869
Contributions from General Partner........................................          4,181         3,353        11,716
Distributions to partners:
  Common units............................................................       (340,927)     (306,590)     (268,644)
  Class B units...........................................................        (13,682)      (12,540)       (8,501)
  General Partner.........................................................       (314,244)     (253,344)     (181,198)
  Minority interest.......................................................        (10,445)       (9,668)      (14,827)
Other, net................................................................          1,231         4,429        (2,778)
                                                                              -----------   -----------   -----------
Net Cash Provided by Financing Activities.................................        156,786       559,471     1,241,215
                                                                              -----------   -----------   -----------

Increase (Decrease) in Cash and Cash Equivalents..........................        (17,759)      (21,714)        3,483
Cash and Cash Equivalents, beginning of period............................         41,088        62,802        59,319
                                                                              -----------   -----------   -----------
Cash and Cash Equivalents, end of period..................................    $    23,329   $    41,088   $    62,802
                                                                              ===========   ===========   ===========
Noncash Investing and Financing Activities:
  Assets acquired by the issuance of units................................    $     2,000   $        --    $       --
  Assets acquired by the assumption of liabilities........................         36,187       213,861       293,871
Supplemental disclosures of cash flow information:
  Cash paid (received) during the year for
  Interest (net of capitalized interest)..................................        183,908       161,840       165,357
  Income taxes............................................................           (261)        1,464         2,168
</TABLE>

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

                                       96
<PAGE>

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

                  CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL

                                                        2003                       2002                      2001
                                              -------------------------  ------------------------  --------------------------
                                                  Units        Amount        Units       Amount        Units         Amount
                                              -----------   -----------  -----------  -----------  -----------    -----------
                                                                          (Dollars in thousands)
<S>                                           <C>           <C>          <C>          <C>          <C>            <C>
    Common Units:
      Beginning Balance..................     129,943,218   $ 1,844,553  129,855,018  $ 1,894,677  129,716,218    $ 1,957,357
      Net income.........................              --       265,423           --      254,934           --        203,559
      Units issued as consideration in the
        acquisition of assets............          51,490         2,000           --           --           --             --
      Units issued for cash..............       4,734,550       175,067       88,200        1,532      138,800          2,405
      Distributions......................              --      (340,927)          --     (306,590)          --       (268,644)
                                              -----------   -----------  -----------  -----------  -----------    -----------
      Ending Balance.....................     134,729,258     1,946,116  129,943,218    1,844,553  129,855,018      1,894,677

    Class B Units:
      Beginning Balance..................       5,313,400       123,635    5,313,400      125,750    5,313,400        125,961
      Net income.........................              --        10,629           --       10,427           --          8,335
      Units issued for cash..............              --            --           --           (2)          --            (44)
      Distributions......................              --       (13,682)          --      (12,540)          --         (8,502)
                                              -----------   -----------  -----------  -----------  -----------    -----------
      Ending Balance.....................       5,313,400       120,582    5,313,400      123,635    5,313,400        125,750

    i-Units:
      Beginning Balance..................      45,654,048     1,420,898   30,636,363    1,020,153           --             --
      Net income.........................              --        94,761           --       72,200           --         28,354
      Units issued for cash..............              --            --   12,478,900      328,545   29,750,000        991,799
      Distributions......................       3,342,417            --    2,538,785           --      886,363             --
                                              -----------   -----------  -----------  -----------  -----------    -----------
      Ending Balance.....................      48,996,465     1,515,659   45,654,048    1,420,898   30,636,363      1,020,153

    General Partner:
      Beginning Balance..................              --        72,100           --       54,628           --         33,749
      Net income.........................              --       326,524           --      270,816           --        202,095
      Units issued for cash..............              --            --           --           --           --            (18)
      Distributions......................              --      (314,244)          --     (253,344)          --       (181,198)
                                              -----------   -----------  -----------  -----------  -----------    -----------
      Ending Balance.....................              --        84,380           --       72,100           --         54,628

    Accumulated other comprehensive income:
      Beginning Balance..................              --       (45,257)          --       63,826           --             --
      Cumulative effect transition adj...              --            --           --           --           --        (22,797)
      Change in fair value of derivatives
        used for hedging purposes........              --      (192,618)          --     (116,560)          --         35,162
      Reclassification of change in fair
        value of derivatives to net
        Income...........................              --        82,065           --        7,477           --         51,461
                                              -----------   -----------  -----------  -----------  -----------    -----------
      Ending Balance.....................              --      (155,810)          --      (45,257)          --         63,826

    Total Partners' Capital..............     189,039,123   $ 3,510,927  180,910,666  $ 3,415,929  165,804,781    $ 3,159,034
                                              ===========   ===========  ===========  ===========  ===========    ===========
</TABLE>

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

                                       97
<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 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, avoiding 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 80 terminals. At December 31, 2003, KMI and its
consolidated subsidiaries owned, through its general and limited partner
interests, an approximate 19.0% 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 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

                                       98
<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, 2003, KMR owned approximately 25.9% 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, 2003, 2002 and 2001.

                                       99
<PAGE>

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

                                      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
                                     ------------   ---------------- ------------------ --------------  -------------

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

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

Year ended December 31, 2001....        $4,151           $3,641            $1,362           $(1,598)        $7,556
</TABLE>
----------

(1) Amount for 2002 represents the allowance recognized when we acquired IC
    Terminal Holdings Company and Consolidated Subsidiaries. Amount for 2001
    represents the allowance recognized when we acquired CALNEV Pipe Line LLC
    and Kinder Morgan Liquids Terminals LLC, as well as transfers from other
    accounts.

(2) Deductions represent the write-off of receivables and the revaluation of the
    allowance account.

   In addition, the balances of "Accrued other current liabilities" in our
accompanying consolidated balance sheets include amounts related to customer
prepayments of approximately $8.2 million as of December 31, 2003 and $38.7
million as of December 31, 2002.

   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 state 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.
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 of productive wells and
development dry holes, both tangible and intangible, as well as productive
acreage are capitalized and amortized on the unit-of-production method. In
addition, we engage in enhanced recovery techniques in which CO2 is injected
into certain producing oil reservoirs. The acquisition cost of this CO2 for the
SACROC unit is capitalized as part of our development costs when it is injected.
When CO2 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.

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<PAGE>

   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 must also 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.

   These accounting pronouncements require that 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 this initial transition impairment test in June
2002 and determined that our goodwill was not impaired as of January 1, 2002. We
have selected an impairment measurement test date of January 1 of each year and
we have determined that our goodwill was not impaired as of January 1, 2004.

   Prior to January 1, 2002, we amortized the excess cost over the underlying
net asset book value of our equity investments using the straight-line method
over the estimated remaining useful lives of the assets in accordance with
Accounting Principles Board Opinion No. 16 "Business Combinations." We amortized
this excess for undervalued depreciable assets over a period not to exceed 50
years and for intangible assets over a period not to exceed 40 years. For our
consolidated affiliates, we reported amortization of excess cost over fair value
of net assets (goodwill) as amortization expense in our accompanying
consolidated statements of income. For our investments accounted for under the
equity method but not consolidated, we reported amortization of excess cost of
investments as amortization of excess cost of equity investments in our
accompanying consolidated statements of income.

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   Our total unamortized excess cost over fair value of net assets in
consolidated affiliates was approximately $729.5 million as of December 31, 2003
and $716.6 million as of December 31, 2002. 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 December 31,
2003, and approximately $140.3 million as of December 31, 2002. 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 $189.7 million and $195.3 million
at December 31 2003 and 2002, respectively, representing the excess of the fair
market value of property, plant and equipment over its book value at the date of
acquisition was being amortized over a weighted average life of approximately
34 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, 2003, 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.

   Capitalized Interest

   We capitalize interest expense during the new construction or upgrade of
qualifying assets. Interest expense capitalized in 2003, 2002 and 2001 was $5.3
million, $5.8 million and $3.1 million, respectively.

   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

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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
canreasonably 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 utilize both internal staff and external experts to assist us in
identifying environmental issues and in estimating the costs and timing of
remediation efforts. Often, as the remediation evaluation and effort progresses,
additional information is obtained, requiring revisions to estimated costs.
These revisions are reflected in our income in the period in which they are
reasonably determinable. In December 2002, after a thorough review of potential
environmental issues that could impact our assets or operations, we recognized a
$0.3 million reduction in environmental expense and in our overall accrued
environmental liability, and we included this amount within "Other, net" in our
accompanying Consolidated Statement of Income for 2002. The $0.3 million income
item resulted from properly adjusting and realigning our environmental expenses
and accrued liabilities between our reportable business segments, specifically
between our Products Pipelines and our Terminals business segments. The $0.3
million reduction in environmental expense resulted from a $15.7 million loss in
our Products Pipelines business segment and a $16.0 million gain in our
Terminals business segment. 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 revise our
estimates, our earnings will be affected. In general, we expense legal costs as
incurred. When we identify specific litigation that is expected to continue for
a significant period of time and require substantial expenditures, we identify a
range of possible costs expected to be required to litigate the matter to a
conclusion or reach an acceptable settlement. If no amount within this range is
a better estimate than any other amount, we record a liability equal to the low
end of the range. Any such liability recorded is revised as better information
becomes available. For more information on our legal 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," a component
of 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.

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   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 terms.

   Minority Interest

   As of December 31, 2003, minority interest consists of the following:

   o the 1.0101% general partner interest in our 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, a Louisiana
     partnership owned 66 2/3% and controlled by Kinder Morgan Operating L.P.
     "C"; and

   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.

   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 the Partnership.

   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.

   Comprehensive Income

   Statement of Financial Accounting Standards No. 130, "Accounting for
Comprehensive Income," requires that enterprises report a total for
comprehensive income. For each of the years ended December 31, 2003, 2002 and
2001, 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.

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<PAGE>

   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.

   Two-for-one Common Unit Split

   On July 18, 2001, KMR, the delegate of our general partner, approved a
two-for-one split of its outstanding shares and our outstanding common units
representing limited partner interests in us. The common unit split entitled our
common unitholders to one additional common unit for each common unit held. Our
partnership agreement provides that when a split of our common units occurs, a
unit split of our Class B units and our i-units will be effected to adjust
proportionately the number of our Class B units and i-units. The issuance and
mailing of split units occurred on August 31, 2001 to unitholders of record on
August 17, 2001. All references to the number of KMR shares, the number of our
limited partner units and per unit amounts in our consolidated financial
statements and related notes, have been restated to reflect the effect of this
split for all periods presented.

   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 2001, 2002 and 2003, 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.

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<PAGE>
<TABLE>
<CAPTION>

                                                                              Allocation of Purchase Price
                                                           -------------------------------------------------------------------
                                                                                     (in millions)
                                                           -------------------------------------------------------------------
                                                                                   Property    Deferred
                                                             Purchase   Current     Plant &     Charges              Minority
  Ref.   Date                Acquisition                      Price      Assets    Equipment    & Other   Goodwill   Interest
  ----- ------  ------------------------------------------  ----------  --------  ----------   --------   --------   --------
<S>      <C>    <C>                                           <C>         <C>         <C>         <C>       <C>        <C>
  (1)    1/01   GATX Domestic Pipelines and Terminals.....    $1,233.4    $ 32.3      $928.7      $ 4.8     $267.6        -
  (2)    3/01   Pinney Dock & Transport LLC...............        51.7       2.0        32.4        0.5       16.8        -
  (3)    7/01   Bulk Terminals from Vopak.................        44.3         -        44.3          -          -        -
  (4)    7/01   Kinder Morgan Texas Pipeline..............       326.1         -       326.1          -          -        -
  (5)    8/01   The Boswell Oil Company...................        22.4       1.6        13.9          -        6.9        -
  (6)    11/01  Liquid Terminals from Stolt-Nielsen.......        70.8         -        70.7          -        0.1        -
  (7)    11/01  Interests in Snyder and Diamond M Plants..        20.9         -        20.9          -          -        -
  (8)    1/02   Kinder Morgan Materials Services LLC......        12.2       0.9        11.3          -          -        -
  (9)    1/02   66 2/3% Interest in Intl. MarineTerminals.        40.5       6.6        31.8        0.1          -      2.0
  (10)   1/02   Kinder Morgan Tejas.......................       881.5      56.5       674.1          -      150.9        -
  (11)   5/02   Milwaukee Bagging Operations..............         8.5       0.1         3.1          -        5.3        -
  (12)   5/02   Trailblazer Pipeline Company..............        80.1         -        41.7          -       15.0     23.4
  (13)   9/02   Owensboro Gateway Terminal................         7.7       0.0         4.3        0.1        3.3        -
  (14)   9/02   IC Terminal Holdings Company..............        17.7       0.1        14.3        3.3          -        -
  (15)   1/03   Bulk Terminals from M.J. Rudolph..........        31.3       0.1        18.2        0.1       12.9        -
  (16)   6/03   MKM Partners, L.P.........................        25.2         -        25.2          -          -        -
  (17)   8/03   Red Cedar Gathering Company...............        10.0         -           -       10.0          -        -
  (18)   10/03  Shell Products Terminals..................        20.0         -        20.0          -          -        -
  (19)   11/03  Yates Field Unit and Carbon Dioxide Assets       259.0       3.5       255.8          -          -     (0.3)
  (20)   11/03  MidTex Gas Storage Company, LLP...........        17.5         -        11.9          -          -      5.6
  (21)   12/03  ConocoPhillips Products Terminals.........        15.1         -        15.1          -          -        -
  (22)   12/03  Tampa, Florida Bulk Terminals.............    $   29.5        $-      $ 29.5         $-         $-       $-
</TABLE>

   (1) Domestic Pipelines and Terminals Businesses from GATX

   During the first quarter of 2001, we acquired GATX Corporation's domestic
pipeline and terminal businesses. The acquisition included:

   o Kinder Morgan Liquids Terminals LLC (formerly GATX Terminals Corporation),
     effective January 1, 2001;

   o Central Florida Pipeline LLC (formerly Central Florida Pipeline Company),
     effective January 1, 2001; and

   o CALNEV Pipe Line LLC (formerly CALNEV Pipe Line Company), effective March
     30, 2001.

   After the acquisitions, Kinder Morgan Liquids Terminals LLC's assets included
12 terminals, located across the United States, with storage capacity of
approximately 35.6 million barrels of refined petroleum products and chemicals.
Five of the terminals are included in our Terminals business segment, and the
remaining assets are included in our Products Pipelines business segment.
Central Florida Pipeline LLC consists of a 195-mile pipeline transporting
refined petroleum products from Tampa to the growing Orlando, Florida market.
CALNEV Pipe Line LLC consists of a 550-mile refined petroleum products pipeline
originating in Colton, California and extending into the growing Las Vegas,
Nevada market. The pipeline interconnects in Colton with our Pacific operations'
West Line pipeline segment. Our purchase price was approximately $1,233.4
million, consisting of $975.4 million in cash, $134.8 million in assumed debt
and $123.2 million in assumed liabilities.

   (2) Pinney Dock & Transport LLC

   Effective March 1, 2001, we acquired all of the equity interests in Pinney
Dock & Transport LLC, formerly Pinney Dock & Transport Company, for
approximately $51.7 million. The acquisition included a bulk product terminal
located in Ashtabula, Ohio on Lake Erie. The facility handles iron ore, titanium
ore, magnetite and other aggregates. Our purchase price consisted of
approximately $41.7 million in cash and approximately $10.0 million in

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<PAGE>

assumed liabilities. The $16.8 million of goodwill was assigned to our Terminals
business segment and the entire amount is expected to be deductible for tax
purposes.

   (3) Bulk Terminals from Vopak

   Effective July 10, 2001, we acquired certain bulk terminal businesses, which
were converted or merged into six single-member limited liability companies,
from Koninklijke Vopak N.V. (Royal Vopak) of The Netherlands. Acquired assets
included four bulk terminals. Two of the terminals are located in Tampa, Florida
and the other two are located in Fernandina Beach, Florida and Chesapeake,
Virginia. As a result of the acquisition, our bulk terminals portfolio gained
entry into the Florida market. Our purchase price was approximately $44.3
million, consisting of approximately $43.6 million in cash and approximately
$0.7 million in assumed liabilities.

   (4) Kinder Morgan Texas Pipeline

   Effective July 18, 2001, we acquired, from an affiliate of Occidental
Petroleum Corporation, K M Texas Pipeline, L.P., a partnership that owned a
natural gas pipeline system in the State of Texas. Prior to our acquisition of
this natural gas pipeline system, these assets were leased from a third-party
under an operating lease and operated by Kinder Morgan Texas Pipeline, L.P., a
business unit included in our Natural Gas Pipelines business segment. As a
result of this acquisition, we were released from lease payments of $40 million
annually from 2002 through 2005 and $30 million annually from 2006 through 2026.
The acquisition included 2,600 miles of pipeline that primarily transports
natural gas from south Texas and the Texas Gulf Coast to the greater
Houston/Beaumont area. In addition, we signed a five-year agreement to supply
approximately 90 billion cubic feet of natural gas to chemical facilities owned
by Occidental affiliates in the Houston area. Our purchase price was
approximately $326.1 million and the entire cost was allocated to property,
plant and equipment. We merged K M Texas Pipeline, L.P. into Kinder Morgan Texas
Pipeline, L.P. on August 1, 2002.

   (5) The Boswell Oil Company

   Effective August 31, 2001, we acquired from The Boswell Oil Company three
terminals located in Cincinnati, Ohio; Pittsburgh, Pennsylvania; and Vicksburg,
Mississippi. The Cincinnati and Pittsburgh terminals handle both liquids and
dry-bulk materials. The Vicksburg terminal is a break-bulk facility, primarily
handling paper and steel products. As a result of the acquisition, we continued
the expansion of our bulk terminal businesses and entered new markets. Our
purchase price was approximately $22.4 million, consisting of approximately
$18.0 million in cash, a $3.0 million one-year note payable and approximately
$1.4 million in assumed liabilities. The $6.9 million of goodwill was assigned
to our Terminals business segment and the entire amount is expected to be
deductible for tax purposes.

   (6) Liquids Terminals from Stolt-Nielsen

   In November 2001, we acquired certain liquids terminals in Chicago, Illinois
and Perth Amboy, New Jersey from Stolthaven Perth Amboy Inc., Stolthaven Chicago
Inc. and Stolt-Nielsen Transportation Group, Ltd. As a result of the
acquisition, we expanded our liquids terminals businesses into strategic
markets. The Perth Amboy facility provides liquid chemical and petroleum storage
and handling, as well as dry-bulk handling of salt and aggregates, with liquid
capacity exceeding 2.3 million barrels annually. We closed on the Perth Amboy,
New Jersey portion of this transaction on November 8, 2001. The Chicago terminal
handles a wide variety of liquid chemicals with a working capacity in excess of
0.7 million barrels annually. We closed on the Chicago, Illinois portion of this
transaction on November 29, 2001. Our purchase price was approximately $70.8
million, consisting of approximately $44.8 million in cash, $25.0 million in
assumed debt and $1.0 million in assumed liabilities. The $0.1 million of
goodwill was assigned to our Terminals business segment and the entire amount is
expected to be deductible for tax purposes.

   (7) Interests in Snyder and Diamond M Plants

   On November 14, 2001, we announced that KMCO2 had purchased Mission Resources
Corporation's interests in the Snyder Gasoline Plant and Diamond M Gas Plant. In
December 2001, KMCO2 purchased Torch E&P Company's interest in the Snyder
Gasoline Plant and entered into a definitive agreement to purchase Torch's
interest

                                      107
<PAGE>

in the Diamond M Gas Plant. We paid approximately $20.9 million for these
interests. All of these assets are located in the Permian Basin of West Texas.
As a result of the acquisition, we increased our ownership interests in both
plants, each of which process gas produced by the SACROC unit. The acquisition
expanded our carbon dioxide-related operations and complemented our working
interests in oil-producing fields located in West Texas. Currently, we own an
approximate 22% ownership interest in the Snyder Gasoline Plant and a 51%
ownership interest in the Diamond M Gas Plant. The acquired interests are
included as part of our CO2 business segment.

   (8) Kinder Morgan Materials Services LLC

   Effective January 1, 2002, we acquired all of the equity interests of Kinder
Morgan Materials Services LLC for an aggregate consideration of $12.2 million,
consisting of approximately $8.9 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 more than 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.

   (9) 66 2/3% Interest in International Marine Terminals

   Effective January 1, 2002, we acquired a 33 1/3% interest in International
Marine Terminals, referred to herein 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 eight 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.

   (10) 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 $881.5 million, consisting of $727.1
million in cash and the assumption of $154.4 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
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 $150.9 million of goodwill was assigned to our
Natural Gas Pipelines business segment and the entire amount is expected to be
deductible for tax purposes.

   (11) 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 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.

   (12) Trailblazer Pipeline Company

   On May 6, 2002, we acquired the remaining 33 1/3% ownership interest in
Trailblazer Pipeline Company 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.

                                      108
<PAGE>

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.

   (13) 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 expands 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.

   (14) 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.

   (15) 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 $29.9 million for
the Rudolph acquisition and this amount was included with "Other current assets"
on our accompanying consolidated balance sheet. In the first quarter of 2003, we
paid the remaining $1.4 million and we allocated our aggregate purchase price to
the appropriate asset and liability accounts. 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. 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,
and we include its operations in our Terminals business segment. 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.

   (16) MKM Partners, L.P.

   Effective June 1, 2003, we acquired the MKM joint venture's 12.75% ownership
interest in the SACROC 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%.

                                      109
<PAGE>

   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 and a 49.9% interest
in the Yates Fieldunit, 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.

   (17) 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.

   (18) 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. We plan 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.

   (19) 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 $259.0 million, consisting of $231.0 million in cash and the
assumption of $28.0 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; and

   o Marathon Carbon Dioxide Transportation Company. Marathon Carbon Dioxide
     Transportation Company owns a 65% ownership interest in the Pecos Carbon
     Dioxide Pipeline Company, which owns a 25-mile carbon dioxide pipeline.

   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 were included in our consolidated results and we recognized
the appropriate minority interest. The acquisition 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. The acquired operations are included as part of our CO2 business segment.
Our allocation of the purchase price to assets acquired, liabilities assumed and
minority interest is preliminary, pending final purchase price adjustments that
we expect to make in the first quarter of 2004.

   (20) MidTex Gas Storage Company, LLP

   Effective November 1, 2003, we acquired the remaining approximate 32%
ownership interest in MidTex Gas Storage Company, LLP from an affiliate of
NiSource Inc. Our combined purchase price was approximately $17.5 million,
including 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

                                      110
<PAGE>

in Matagorda County, Texas. The acquisition eliminated the third-party interest
in the operations of MidTex. MidTex's operations are included as part of our
Natural Gas Pipelines business segment. Our allocation of the purchase price to
assets acquired, liabilities assumed and minority interest is preliminary,
pending final purchase price adjustments that we expect to make in the first
quarter of 2004.

   (21) ConocoPhillips Products Terminals

   Effective December 11, 2003, we acquired seven refined petroleum products
terminals in the southeastern United States from ConocoPhillips Company and
Phillips Pipe Line Company. Our purchase price was approximately $15.1 million,
consisting of approximately $14.1 million in cash and $1.0 million in assumed
liabilities. The terminals are located in Charlotte and Selma, North Carolina;
Augusta and Spartanburg, South Carolina; Albany and Doraville, Georgia; and
Birmingham, Alabama. We will fully own and operate all of the terminals except
for the Doraville, Georgia facility, which is operated and owned 70% by Citgo.
We plan 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 acquisition broadens 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. Our
allocation of the purchase price to assets acquired and liabilities assumed is
preliminary, pending final purchase price adjustments that we expect to make in
the first quarter of 2004.

   (22) Tampa, Florida Bulk Terminals

   In December 2003, we acquired two bulk terminal facilities in Tampa, Florida
for an aggregate consideration of approximately $29.5 million, consisting of
$26.0 million in cash (including closing and related costs of approximately $1.1
million) and $3.5 million in assumed liabilities. We plan to invest an
additional $16.9 million in the facilities. The principal purchased asset was a
marine terminal acquired from a subsidiary of IMC Global, Inc. We also entered
into a long-term agreement with IMC to enable it to be the primary user of the
facility, which we will operate and refer to as the Kinder Morgan Tampaplex
terminal. The terminal sits on a 114-acre site, and serves as a storage and
receipt point for imported ammonia, as well as an export location for dry bulk
products, including fertilizer and animal feed. We closed on the Tampaplex
portion of this transaction on December 23, 2003. The second facility includes
assets from the former Nitram, Inc. bulk terminal, which we plan to use as an
inland bulk storage warehouse facility for overflow cargoes from our Port Sutton
import terminal. We closed on the Nitram portion of this transaction on December
10, 2003. The acquired operations are included as part of our Terminals business
segment and complement our existing business in the Tampa area by generating
additional fee-based income. Our allocation of the purchase price to assets
acquired and liabilities assumed is preliminary, pending final purchase price
adjustments that we expect to make in the first quarter of 2004.

   Pro Forma Information

   The following summarized unaudited pro forma consolidated income statement
information for the years ended December 31, 2003 and 2002, assumes that all of
the 2003 and 2002 acquisitions and joint ventures we have made since January 1,
2002, including the ones listed above, had occurred as of January 1, 2002. 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 the 2003 and 2002
acquisitions and joint ventures as of January 1, 2002 or the results that will
be attained in the future. Amounts presented below are in thousands, except for
the per unit amounts:
<TABLE>
<CAPTION>
                                                               Pro Forma Year Ended
                                                                   December 31,
                                                                2003            2002
                                                            ------------    ------------
                                                                    (Unaudited)
<S>                                                         <C>             <C>
 Revenues................................................   $  6,709,834    $  4,608,979
 Operating Income........................................        857,762         802,373
 Income Before Cumulative Effect of a Change in
  Accounting Principle...................................        736,598         673,766
 Net Income..............................................   $    740,063    $    673,766
 Basic and Diluted Limited Partners' Net Income per unit:
   Income  Before  Cumulative  Effect  of  a
    Change  in  Accounting Principle.....................   $       2.21    $       2.19
   Net Income............................................   $       2.23    $       2.19
</TABLE>

                                      111
<PAGE>

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 will be to change the method of accruing for oil production site restoration
costs related to our CO2 business segment. Prior to January 1, 2003, we
accounted for asset retirement obligations 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 $3.5 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 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 wells
that have been removed from service and to remove our surface wellhead equipment
and compressors. As of December 31, 2003, we have recognized asset retirement
obligations in the aggregate amount of $32.7 million relating to these
requirements at existing sites within our CO2 segment.

   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, 2003, we have recognized
asset retirement obligations in the aggregate amount of $3.0 million relating to
the businesses within our Natural Gas Pipelines segment.

   We have included $0.8 million of our total $35.7 million asset retirement
obligations as of December 31, 2003 with "Accrued other current liabilities" in
our accompanying consolidated balance sheet. The remaining $34.9

                                      112
<PAGE>

million obligation is reported separately as a non-current liability. 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 the twelve months ended December
31, 2003 is as follows (in thousands):

        Balance as of December 31, 2002............     $       -
        Initial ARO balance upon adoption..........          14,125
        Liabilities incurred.......................          12,911
        Liabilities settled........................          (1,056)
        Accretion expense..........................           1,028
        Revisions in estimated cash flows..........           8,700
                                                        -----------
        Balance as of December 31, 2003............     $    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):

<TABLE>
<CAPTION>
                                                                     Pro Forma Year Ended
                                                                          December 31,
                                                              -------------------------------------
                                                                 2003         2002         2001
                                                              -----------  -----------  -----------
                                                                           (Unaudited)
<S>                                                           <C>          <C>          <C>
Reported income before cumulative effect of a change in
  accounting principle...................................     $   693,872  $   608,377  $   442,343
Adjustments from change in accounting for asset
  retirement obligations.................................              --       (1,161)        (980)
                                                              -----------  -----------  -----------
Adjusted income before cumulative effect of a change in
  accounting principle...................................     $   693,872  $   607,216  $   441,363
                                                              ===========  ===========  ===========
Reported income before cumulative effect of a change in
  accounting principle per unit (fully diluted)..........     $      1.98  $      1.96  $      1.56
                                                              ===========  ===========  ===========
Adjusted income before cumulative effect of a change in
  accounting principle per unit (fully diluted)..........     $      1.98  $      1.95  $      1.55
                                                              ===========  ===========  ===========

                                                              Dec. 31,     Dec. 31,
                                                                2002         2001
                                                              -------      -------
Liability for asset retirement obligations.............       $14,125      $14,345
                                                              =======      =======
</TABLE>

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,
                                -------------------------------
                                   2003        2002       2001
                                --------    --------   --------
      Taxes currently payable:
        Federal..............   $    437    $ 15,855   $  9,058
        State................      1,131       3,116      1,192
        Foreign..............         25         147          -
                                --------    --------   --------
        Total................      1,593      19,118     10,250
      Taxes deferred:
        Federal..............     11,650      (3,280)     5,366
        State................      1,939        (555)       757
        Foreign..............      1,449           -          -
                                --------    --------   --------
        Total................     15,038      (3,835)     6,123
                                --------    --------   --------
      Total tax provision....   $ 16,631    $ 15,283   $ 16,373
                                ========    ========   ========
      Effective tax rate.....        2.3%        2.4%       3.5%

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

                                      113
<PAGE>

<TABLE>
<CAPTION>

                                                                    Year Ended December 31,
                                                                   2003       2002      2001
                                                                ---------  --------- -------
<S>                                                                <C>        <C>       <C>
    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%       0.6%      1.3%
      Income tax expense attributable to corporate equity           1.5%       1.6%      1.8%
    earnings................................................
      Income tax expense attributable to foreign corporate          0.2%       -         -
    earnings................................................
      State taxes...........................................        0.1%       0.2%      0.4%
                                                                --------   --------  --------
    Effective tax rate......................................        2.3%       2.4%      3.5%
                                                                ========   ========  ========
</TABLE>

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

                                                           December 31,
                                                        -----------------
                                                          2003     2002
                                                        -------  --------
 Deferred tax assets:
   Book accruals....................................    $ 1,424  $     97
   Net Operating Loss/Alternative minimum tax credits    10,797     3,556
                                                        -------  --------
 Total deferred tax assets..........................     12,221     3,653
 Deferred tax liabilities:
   Property, plant and equipment....................     50,327    33,915
                                                        -------  --------
 Total deferred tax liabilities.....................     50,327    33,915
                                                        -------  --------
 Net deferred tax liabilities.......................    $38,106  $ 30,262
                                                        =======  ========

   We had available, at December 31, 2003, approximately $0.3 million of
alternative minimum tax credit carryforwards, which are available indefinitely,
and $10.5 million of net operating loss carryforwards, which will expire between
the years 2004 and 2023. 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):
<TABLE>
<CAPTION>
                                                                         December 31,
                                                                       2003         2002
<S>                                                                <C>          <C>
  Natural gas, liquids and carbon dioxide pipelines...........     $ 3,458,736  $ 2,544,987
  Natural  gas,  liquids  and  carbon  dioxide  pipeline
   station equipment..........................................       2,908,273    2,801,729
  Coal and bulk tonnage transfer, storage and services........         359,088      281,713
  Natural gas and transmix processing.........................         100,778       98,094
  Other.......................................................         330,982      292,881
  Accumulated depreciation and depletion......................        (641,914)    (452,408)
                                                                   -----------  -----------
                                                                     6,515,943    5,566,996
  Land and land right-of-way..................................         339,579      340,507
  Construction work in process................................         236,036      336,739
                                                                   -----------  -----------
                                                                   $ 7,091,558  $ 6,244,242
                                                                   ===========  ===========
</TABLE>

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

                                                   2003       2002     2001
                                                ---------  --------- ------
        Depreciation and depletion expense..    $ 217,401  $171,461  $126,641

7.  Investments

   Our significant equity investments at December 31, 2003 consisted of:

   o Plantation Pipe Line Company (51%);

   o Red Cedar Gathering Company (49%);

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

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<PAGE>

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

   o Cortez Pipeline Company (50%); and

   o Heartland Pipeline Company (50%).

   In addition, we had an equity investment in International Marine Terminals
(33 1/3%) for one month of 2002. We acquired an additional 33 1/3% interest in
International Marine Terminals effective February 1, 2002, and after this date,
the financial results of IMT were no longer reported under the equity method.

   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, 2001, Kinder Morgan CO2 Company, L.P. acquired a 15% ownership
interest in MKM Partners, L.P., a joint venture with Marathon Oil Company. The
MKM joint venture was owned 85% by subsidiaries of Marathon Oil Company and 15%
by Kinder Morgan CO2 Company, L.P. 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.

   Finally, 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.

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

                                                          December 31,
                                                       -------------------
                                                         2003       2002
                                                       --------   --------
  Plantation Pipe Line Company.....................    $219,349   $212,300
  Red Cedar Gathering Company......................     114,176    106,422
  Thunder Creek Gas Services, LLC..................      37,245     36,921
  Coyote Gas Treating, LLC.........................      13,502     14,435
  Cortez Pipeline Company..........................      12,591     10,486
  Heartland Pipeline Company.......................       5,109      5,459
  MKM Partners, L.P................................           -     60,795
  All Others.......................................       2,373      4,556
                                                       --------   --------
  Total Equity Investments.........................    $404,345   $451,374
                                                       ========   ========

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

                                      115
<PAGE>

                                                Year Ended December 31,
                                            -------------------------------
                                              2003       2002        2001
                                            --------   --------    --------
   Plantation Pipe Line Company........     $ 27,983   $ 26,426    $ 25,314
   Cortez Pipeline Company.............       32,198     28,154      25,694
   Red Cedar Gathering Company.........       18,571     19,082      18,814
   MKM Partners, L.P...................        5,000      8,174       8,304
   Coyote Gas Treating, LLC............        2,608      2,651       2,115
   Thunder Creek Gas Services, LLC.....        2,833      2,154       1,629
   Heartland Pipeline Company..........          973        998         882
   All Others..........................        2,033      1,619       2,082
                                            --------   --------    --------
   Total...............................     $ 92,199   $ 89,258    $ 84,834
                                            ========   ========    ========
   Amortization of excess costs........     $ (5,575)  $ (5,575)   $ (9,011)
                                            ========   ========    ========

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

                                                               Year Ended December 31,
                                                          ---------------------------------
            Income Statement                                 2003        2002        2001
    -------------------------------                       ---------   ---------   ---------
<S>                                                       <C>         <C>         <C>
    Revenues..........................................    $ 467,871   $ 505,602   $ 449,259
    Costs and expenses.................................     295,931     309,291     280,100
                                                          ---------   ---------   ---------
    Earnings before extraordinary items and
      cumulative effect of a change in accounting
      principle........................................     171,940     196,311     169,159
                                                          =========   =========   =========
    Net income.........................................   $ 168,167   $ 196,311   $ 169,159
                                                          =========   =========   =========

</TABLE>
                                                December 31,
                   Balance Sheet               2003        2002
              ---------------------        ----------- --------
              Current assets............   $   93,709  $   83,410
              Non-current assets........      684,754   1,101,057
              Current liabilities.......      377,535     243,636
              Non-current liabilities...      209,468     374,132
              Partners'/owners' equity..   $  191,460  $  566,699

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 and $140.3 million of equity method goodwill at
December 31, 2003 and 2002, respectively.

   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,
                                        ---------------------
                                           2003        2002
                                        ---------   ---------
         Goodwill
         Gross carrying amount......    $ 743,652   $ 730,752
         Accumulated amortization...      (14,142)    (14,142)
                                        ---------   ---------
         Net carrying amount........      729,510     716,610
                                        ---------   ---------

         Lease value
         Gross carrying amount......        6,592       6,592
         Accumulated amortization...         (888)       (748)
                                        ---------   ---------
         Net carrying amount........        5,704       5,844
                                        ---------   ---------

                                      116
<PAGE>

                                             December 31,
                                        ---------------------
                                           2003        2002
                                        ---------   ---------
         Contracts and other
         Gross carrying amount......        7,801      11,719
         Accumulated amortization...         (303)       (239)
                                        ---------   ---------
         Net carrying amount........        7,498      11,480
                                        ---------   ---------

         Total intangibles, net.....    $ 742,712   $ 733,934
                                        =========   =========

Changes in the carrying amount of goodwill for each of the two years ended
December 31, 2002 and 2003 are summarized as follows (in thousands):
<TABLE>
<CAPTION>

                                   Products     Natural Gas         CO2
                                  Pipelines      Pipelines     Pipelines     Terminals       Total
                                  -----------   -----------    -----------   -----------   -----------
<S>                               <C>           <C>            <C>           <C>           <C>
   Balance as of Dec. 31, 2001    $   262,765   $    87,452    $    46,101   $   150,416   $   546,734
     Goodwill acquired                    417       165,906              -         3,553       169,876
     Impairment losses                      -             -              -             -             -
                                  -----------   -----------    -----------   -----------   -----------
   Balance as of Dec. 31, 2002    $   263,182   $   253,358    $    46,101   $   153,969   $   716,610
                                  ===========   ===========    ===========   ===========   ===========
     Goodwill acquired                      -             -              -        12,900        12,900
     Impairment losses                      -             -              -             -             -
                                  -----------   -----------    -----------   -----------   -----------
   Balance as of Dec. 31, 2003    $   263,182   $   253,358    $    46,101   $   166,869   $   729,510
                                  ===========   ===========    ===========   ===========   ===========
</TABLE>

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

                                         Year Ended December 31,
                                          2003      2002      2001
                                        --------  --------  ------
            Goodwill.................   $      -  $      -  $13,416
            Lease value..............        140       140    4,999
            Contracts and other......         64        40       60
                                        --------  --------  -------
            Total amortization.......   $    204  $    180  $18,475
                                        ========  ========  =======

   As of December 31, 2003, our weighted average amortization period for our
intangible assets is approximately 40 years. Our estimated amortization expense
for these assets for each of the next five fiscal years is approximately $0.2
million.

   Had SFAS No. 142 been in effect prior to January 1, 2002, our reported
limited partners' interest in net income and net income per unit would have been
as follows (in thousands, except per unit amounts):

<TABLE>
<CAPTION>
                                                                     Year Ended December 31,
                                                              ------------------------------------
                                                                 2003         2002          2001
                                                              ---------     ---------    ---------
<S>                                                           <C>           <C>          <C>
Reported limited partners' interest in net income             $ 370,813     $ 337,561    $ 240,248
Add: limited partners' interest in goodwill amortization             --            --       13,280
                                                              ---------     ---------    ---------

Adjusted limited partners' interest in net income             $ 370,813     $ 337,561    $ 253,528
                                                              =========     =========    =========
Basic limited partners' net income per unit:
  Reported net income                                         $    2.00     $    1.96    $    1.56
  Goodwill amortization                                              --            --         0.09
                                                              ---------     ---------    ---------
  Adjusted net income                                         $    2.00     $    1.96    $    1.65
                                                              =========     =========    =========

Diluted limited partners' net income per unit:
  Reported net income                                         $    2.00     $    1.96    $    1.56
  Goodwill amortization                                              --            --         0.09
                                                              ---------     ---------    ---------
  Adjusted net income                                         $    2.00     $    1.96    $    1.65
                                                              =========     =========    =========

</TABLE>

9.  Debt

   Our debt and credit facilities as of December 31, 2003, consisted primarily
of:

   o a $570 million unsecured 364-day credit facility due October 12, 2004;

   o a $480 million unsecured three-year credit facility due October 15, 2005;

                                      117
<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  $25 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 $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  $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  $87.9 million of Industrial Revenue Bonds with final maturities ranging
      from September 2019 to December 2024 (our subsidiary, Kinder Morgan
      Liquids Terminals LLC, is the obligor on the bonds);

   o  $23.7 million of tax-exempt bonds due 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 $1.05 billion short-term commercial paper program (supported by our
      credit facilities, the amount available for borrowing under our credit
      facilities is reduced by our outstanding commercial paper borrowings).

   None of our debt or credit facilities are 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 facilities is tied to
our credit ratings.

   Our outstanding short-term debt as of December 31, 2003 was $430.3 million.
The balance consisted of:

   o $426.1 million of commercial paper borrowings;

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

   o an offset of $0.8 million (which represents the net of other borrowings and
     the accretion of discounts on our senior note issuances).

   As of December 31, 2003, we intend and have the ability to refinance $428.1
million of our short-term debt on a long-term basis under our unsecured
long-term credit facility. Accordingly, such amount has been classified as
long-term debt in our accompanying consolidated balance sheet. Currently, we
believe our liquidity to be adequate.

                                      118
<PAGE>

The weighted average interest rate on allof our borrowings was approximately
4.4924% during 2003 and 5.015%during 2002.

   Credit Facilities

   On February 21, 2002, we obtained an unsecured 364-day credit facility, in
the amount of $750 million, expiring on February 20, 2003. The credit facility
was used to support the increase in our commercial paper program to $1.8 billion
for our acquisition of Kinder Morgan Tejas. Upon issuance of additional senior
notes in March 2002, this short-term credit facility was reduced to $200
million.

   In August 2002, upon the completion of our i-unit equity sale, we terminated,
under the terms of the agreement, our $200 million unsecured 364-day credit
facility that was due February 20, 2003. On October 16, 2002, we successfully
renegotiated our bank credit facilities by replacing our $750 million unsecured
364-day credit facility due October 23, 2002 and our $300 million unsecured
five-year credit facility due September 29, 2004 with two new credit facilities.
The two credit 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:

   o a $570 million unsecured 364-day credit facility due October 12, 2004; and

   o a $480 million unsecured three-year credit facility due October 15, 2005.

   Our credit facilities are with a syndicate of financial institutions.
Wachovia Bank, National Association is the administrative agent under both
credit facilities. There were no borrowings under either credit facility at
December 31, 2003. Interest on the two credit facilities 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 facilities at December
31, 2003 is reduced by:

   o a $23.7 million letter of credit that supports Kinder Morgan Operating L.P.
     "B"'s tax-exempt bonds;

   o a $28 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 $0.2 million letter of credit entered into on June 4, 2002 that supports
     a workers' compensation insurance policy; and

   o our outstanding commercial paper borrowings.

   In addition to our letters of credit outstanding as of December 31, 2003, in
early 2004 we issued a $50 million letter of credit to Morgan Stanley in support
of our hedging activities.

                                      119
<PAGE>

   Our three-year credit facility also permits us to obtain bids for fixed-rate
loans from members of the lending syndicate.

   Our credit facilities included the following restrictive covenants as of
December 31, 2003:

   o requirements to maintain certain financial ratios:

     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;

     o tangible net worth as of the last day of any fiscal quarter shall not be
       less than $2.1 billion; and

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

   o 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.

   Senior Notes

   On March 14, 2002, we closed a public offering of $750 million in principal
amount of senior notes, consisting of $450 million in principal amount of 7.125%
senior notes due March 15, 2012 at a price to the public of 99.535% per note,
and $300 million in principal amount of 7.75% senior notes due March 15, 2032 at
a price to the public of 99.492% per note. In the offering, we received
proceeds, net of underwriting discounts and commissions, of approximately $445.0
million for the 7.125% notes and $295.9 million for the 7.75% notes. We used the
proceeds to reduce our outstanding balance on our commercial paper borrowings.

   On March 22, 2002, we paid $200 million to retire the principal amount of our
floating rate senior notes that matured on that date. We borrowed the necessary
funds under our commercial paper program.

   Under an indenture dated August 19, 2002, and a first supplemental indenture
dated August 23, 2002, we completed a private placement of $750 million in debt
securities. The notes consisted of $500 million in principal amount of 7.30%
senior notes due August 15, 2033 and $250 million in principal amount of 5.35%
senior notes due August 15, 2007. In the offering, we received proceeds, net of
underwriting discounts and commissions, of approximately $494.7 million for the
7.30% senior notes and $248.3 million for the 5.35% senior notes. The proceeds
were used to reduce the borrowings under our commercial paper program. On
November 18, 2002, we exchanged these notes with substantially identical notes
that were registered under the Securities Act of 1933.

   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% per note. In the offering, we received proceeds, net of
underwriting discounts and commissions, of approximately $493.6 million. We used
the proceeds to reduce our outstanding balance on our commercial paper
borrowings.

   As of December 31, 2003, our liability balance due on the various series of
our senior notes was as follows (in millions):

          8.00% senior notes due March 15, 2005......  $   199.9
          5.35% senior notes due August 15, 2007.....      249.9
          6.30% senior notes due February 1, 2009....      249.6
          7.50% senior notes due November 1, 2010....      248.9
          6.75% senior notes due March 15, 2011......      698.5
          7.125% senior notes due March 15, 2012.....      448.3
          5.00% senior notes due December 15, 2013...      496.8

                                      120
<PAGE>

          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....................................  $ 3,688.8
                                                       =========

   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 debt and variable rate debt. As of
December 31, 2003, we have entered into interest rate swap agreements with a
notional principal amount of $2.1 billion for the purpose of hedging the
interest rate risk associated with our fixed and variable rate debt obligations.

   These 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. 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. For more information on our interest rate swaps, see Note 14.

   Commercial Paper Program

   On February 21, 2002, we increased our commercial paper program to provide
for the issuance of up to $1.8 billion. We entered into a $750 million unsecured
364-day credit facility to support this increase in our commercial paper
program, and we used the program's increase in available funds to close on the
Tejas acquisition. After the issuance of additional senior notes on March 14,
2002, we reduced our commercial paper program to $1.25 billion.

   On August 6, 2002, KMR issued in a public offering, an additional 12,478,900
of its shares, including 478,900 shares upon exercise by the underwriters of an
over-allotment option, at a price of $27.50 per share, less commissions and
underwriting expenses. The net proceeds from the offering were used to buy
i-units from us. After commissions and underwriting expenses, we received net
proceeds of approximately $331.2 million for the issuance of 12,478,900 i-units.
We used the proceeds from the i-unit issuance to reduce the borrowings under our
commercial paper program and, in conjunction with our issuance of additional
i-units and as previously agreed upon under the terms of our credit facilities,
we reduced our commercial paper program to provide for the issuance of up to
$975 million of commercial paper as of December 31, 2002. As of December 31,
2002, we had $220.0 million of commercial paper outstanding with an average
interest rate of 1.58%. On May 5, 2003, we increased the program to allow for
the borrowing of up to $1.05 billion of commercial paper. As of December 31,
2003, we had $426.1 million of commercial paper outstanding with an average
interest rate of 1.1803%.

   The borrowings under our commercial paper program were used to finance
acquisitions made during 2002 and 2003. The borrowings under our commercial
paper program reduce the borrowings allowed under our credit facilities.

   SFPP, L.P. Debt

   In December 2003, SFPP, L.P. prepaid the $37.1 million balance outstanding
under the Series F notes, plus $2.0 million for interest, as a result of its
taking advantage of certain optional prepayment provisions without penalty in
1999 and 2000.

   At December 31, 2002, the outstanding balance under SFPP, L.P.'s Series F
notes was $37.1 million. 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.

                                      121
<PAGE>

   Kinder Morgan Liquids Terminals LLC Debt

   Effective January 1, 2001, we acquired Kinder Morgan Liquids Terminals LLC
(see Note 3). As part of our purchase price, we assumed debt of $87.9 million,
consisting of five series of Industrial Revenue Bonds. The bonds consist 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 November 2001, we acquired a liquids terminal in Perth Amboy, New Jersey
from Stolthaven Perth Amboy Inc. and Stolt-Nielsen Transportation Group, Ltd.
(see Note 3). 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, 2003, the
interest rate was 0.9606%. We have an outstanding letter of credit issued by
Citibank in the amount of $25.3 million that backs-up the $25.0 million
principal amount of the bonds and $0.3 million of interest on the bonds for up
to 42 days computed at 12% on a per annum basis on the principal thereof.

   Central Florida Pipeline LLC Debt

   Effective January 1, 2001, we acquired Central Florida Pipeline LLC (see Note
3). 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, 2002, Central Florida's
outstanding balance under the senior notes was $30.0 million. In July 2003, we
made an annual repayment of $5.0 million and as of December 31, 2003, Central
Florida's outstanding balance under the senior notes was $25.0 million.

   Trailblazer Pipeline Company Debt

   As of December 31, 2001, Trailblazer Pipeline Company had a two-year
unsecured revolving credit facility with a bank syndicate. The facility provided
for loans of up to $85.2 million and had a maturity date of June 29, 2003. The
agreement provided for an interest rate of LIBOR plus a margin as determined by
certain financial ratios. Pursuant to the terms of the revolving credit
facility, Trailblazer Pipeline Company partnership distributions were restricted
by certain financial covenants. As of December 31, 2001, the outstanding balance
under Trailblazer's two-year revolving credit facility was $55.0 million, with a
weighted average interest rate of 2.875%, which reflected three-month LIBOR plus
a margin of 0.875%. In July 2002, we paid the $31.0 million outstanding balance
under Trailblazer's revolving credit facility and terminated the facility.

   Kinder Morgan Operating L.P. "B" Debt

   The $23.7 million principal amount of tax-exempt bonds due 2024 were issued
by the Jackson-Union Counties Regional Port District. These bonds bear interest
at a weekly floating market rate. During 2003, the weighted-average interest
rate on these bonds was 1.05% per annum, and at December 31, 2003, the interest
rate was 1.20%. We have an outstanding letter of credit issued under our credit
facilities that supports our tax-exempt bonds. The letter of credit reduces the
amount available for borrowing under our credit facilities.

                                      122
<PAGE>

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

   Maturities of Debt

   The scheduled maturities of our outstanding debt, excluding market value of
interest rate swaps, as of December 31, 2003, are summarized as follows (in
thousands):

                      2004........    $  430,348
                      2005........       204,349
                      2006........        43,903
                      2007........       253,917
                      2008........         3,940
                      Thereafter..     3,382,469
                                      ----------
                      Total.......    $4,318,926
                                      ==========

   Of the $430.3 million scheduled to mature in 2004, we intend and have the
ability to refinance $428.1 million on a long-term basis under our unsecured
long-term credit facility. Accordingly, this amount has been classified as
long-term debt in our accompanying consolidated balance sheet as of December 31,
2003.

   Fair Value of Financial Instruments

   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, 2003 and December 31, 2002 and is disclosed below.

   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.

                          December 31, 2003          December 31, 2002
                    -------------------------    -------------------------
                      Carrying      Estimated     Carrying      Estimated
                        Value      Fair Value       Value      Fair Value
                    -----------   -----------    -----------   -----------
                                        (In thousands)
      Total Debt    $ 4,318,926   $ 4,889,478    $ 3,659,533   $ 4,475,058

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 Employee Benefit Plan for
Employees of Hall-Buck Marine Services Company and the benefits under this plan
were based primarily upon years of service and final average pensionable
earnings. Benefit accruals were frozen as of December 31, 1998 for the Hall-Buck
plan. Effective December 31, 2000, the Hall-Buck plan, along with the K N
Energy, Inc. Retirement Plan for Bargaining Employees, was merged into the K N
Energy, Inc.

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Retirement Plan for Non-Bargaining Employees, with the Non-Bargaining Plan being
the surviving plan. The merged plan was renamed the Kinder Morgan, Inc.
Retirement Plan.

   Net periodic benefit costs and weighted-average assumptions for these plans
include the following components (in thousands):

                                             Other Post-retirement Benefits
                                            -------------------------------
                                             2003         2002        2001
                                            ------       ------      ------
       Net periodic benefit cost
       Service cost......................   $   41       $  165      $  120
       Interest cost.....................      807          906         804
       Expected return on plan assets....       --           --          --
       Amortization of prior service cost     (622)        (545)       (545)
       Actuarial gain....................        -            -         (27)
                                            ------       ------      ------
       Net periodic benefit cost.........   $  226       $  526      $  352
                                            ======       ======      ======

       Additional amounts recognized
         Curtailment (gain) loss.........   $   --       $   --      $   --
       Weighted-average assumptions as of
         December 31:
       Discount rate.....................     6.00%        6.50%       7.00%
       Expected return on plan assets....       --           --          --
       Rate of compensation increase.....      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
                                             --------------------------
                                               2003              2002
                                             --------          --------
   Change in benefit obligation
   Benefit obligation at Jan. 1........      $ 13,275          $ 13,368
   Service cost........................            41               165
   Interest cost.......................           807               906
   Participant contributions...........           144               143
   Amendments..........................          (190)             (493)
   Actuarial (gain) loss...............        (7,456)             (264)
   Benefits paid from plan assets......          (445)             (550)
                                             --------          --------
   Benefit obligation at Dec. 31.......      $  6,176          $ 13,275
                                             ========          ========

   Change in plan assets
   Fair value of plan assets at Jan. 1.      $     --          $     --
   Actual return on plan assets........            --                --
   Employer contributions..............           301               407
   Participant contributions...........           144               143
   Benefits paid from plan assets......          (445)             (550)
                                             --------          --------
   Fair value of plan assets at Dec. 31      $     --          $     --
                                             ========          ========

                                               Other Post-retirement
                                                      Benefits
                                             --------------------------
                                               2003              2002
                                             --------          --------
   Funded status.......................      $ (6,176)         $(13,275)
   Unrecognized net actuarial (gain)
   loss................................        (6,728)              729
   Unrecognized prior service (benefit)          (627)           (1,059)
   Adj. for 4th qtr. Employer
   contributions.......................            72               105
                                             --------          --------
   Accrued benefit cost................      $(13,459)         $(13,500)
                                             ========          ========

   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, an 11% annual rate of increase in the per capita cost of
covered health care benefits was assumed for 2004. 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):

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                                             1-Percentage     1-Percentage
                                            Point Increase   Point Decrease
                                            --------------   --------------
 Effect on total of service and
        interest cost components.........     $   78           $  (66)
 Effect on postretirement benefit
        obligation.......................     $  689           $ (575)

   Amounts recognized in our consolidated balance sheets consist of (in
thousands):

                                                     As of December 31,
                                                   2003             2002
                                               ------------     ------------
 Prepaid benefit cost......................              -                -
 Accrued benefit liability.................         (13,459)         (13,500)
 Intangible asset..........................              -                -
 Accumulated other comprehensive income....              -                -
                                               ------------     ------------
   Net amount recognized as of Dec. 31.....         (13,459)         (13,500)
                                               ============     ============

   We expect to contribute approximately $0.3 million to our post-retirement
benefit plans in 2004. The following benefit payments, which reflect expected
future service, as appropriate, are expected to be paid (in thousands):

              Other Post-retirement Benefits
             -------------------------------
             2004........        $       445
             2005........                445
             2006........                445
             2007........                445
             2008........                445
             2009-2013...              2,225
                                 -----------
             Total.......        $     4,450
                                 ===========

   Multiemployer Plans and Other Benefits

   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 $4.9 million for the year ended
2003 and $1.3 million for the year ended 2002.

   The Kinder Morgan Savings Plan, formerly the Kinder Morgan Retirement 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. In the first quarter of 2004, no discretionary
contributions were made to individual accounts for 2003. The total amount
charged to expense for our Savings Plan was $5.9 million during 2003 and $5.6
million during 2002. 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.

   Effective January 1, 2001, employees of KMGP Services Company, Inc. and KMI
became 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 will accrue benefits
through a personal retirement account in the Cash Balance Retirement Plan.
Employees with prior service and not grandfathered converted to the Cash Balance
Retirement Plan and were credited with the current fair value of any benefits
they had previously accrued through the defined benefit plan. Under the plan, we
make contributions on behalf of participating employees equal to 3% of eligible
compensation every pay period. In addition, discretionary contributions are made
to the plan based on our and KMI's performance. No additional contributions were
made for 2003 performance. Interest will be credited to the personal

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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, 2003, our partners' capital consisted of:

   o 134,729,258 common units;

   o 5,313,400 Class B units; and

   o 48,996,465 i-units.

   Together, these 189,039,123 units represent our limited partners' interest
and an effective 98% economic interest in us, exclusive of our general partner's
incentive distribution rights. Our general partner has an effective 2% interest
in us, excluding its incentive distribution rights. As of December 31, 2003, our
common unit total 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.

   As of December 31, 2002, our partners' capital consisted of:

   o 129,943,218 common units;

   o 5,313,400 Class B units; and

   o 45,654,048 i-units.

   Our total common units outstanding at December 31, 2002, consisted of
116,987,483 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 an additional 4,600,000 of our
common units, including 600,000 units upon exercise by the underwriters of an
over-allotment option, at a price of $39.35 per share, less commissions and
underwriting expenses. After commissions and underwriting expenses, we received
net proceeds of $173.3 million for the issuance of these common units. We used
the proceeds to reduce the borrowings under our commercial paper program.

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

   All of our Class B units were issued in December 2000. The Class B units are
similar to our common units except that they are not eligible for trading on the
New York Stock Exchange. We initially issued 29,750,000 i-units in May 2001. The
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, and controlling and managing the business and affairs of us,
our operating limited partnerships and their subsidiaries.

   On August 6, 2002, KMR issued in a public offering, an additional 12,478,900
of its shares, including 478,900 shares upon exercise by the underwriters of an
over-allotment option, at a price of $27.50 per share, less

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<PAGE>

commissions and underwriting expenses. The net proceeds from the offering were
used to buy additional i-units from us. After commissions and underwriting
expenses, we received net proceeds of approximately $331.2 million for the
issuance of 12,478,900 i-units. We used the proceeds from the i-unit issuance to
reduce the debt we incurred in our acquisition of Kinder Morgan Tejas during the
first quarter of 2002.

   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.
Furthermore, 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 cashwe 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
the same value as the cash payment on the common unit.

   The cash equivalent of distributions of i-units will be treated as if it had
actually been distributed for purposes of determining the distributions to our
general partner. We will not distribute the cash to the holders of our i-units
but will 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 811,625 i-units on November 14, 2003.
These additional i-units distributed were based on the $0.66 per unit
distributed to our common unitholders on that date. During the year ended
December 31, 2003, KMR received distributions of 3,342,417 i-units. These
additional i-units distributed were based on the $2.575 per unit distributed to
our common unitholders during 2003.

   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, 2003, 2002 and 2001, we declared
distributions of $2.63, $2.435 and $2.15 per unit, respectively. Our
distributions to unitholders for 2003, 2002 and 2001 required incentive
distributions to our general partner in the amount of $322.8 million, $267.4
million and $199.7 million, respectively. The increased incentive distributions
paid for 2003 over 2002 and 2002 over 2001 reflect the increase in amounts
distributed per unit as well as the issuance of additional units.

   On January 21, 2004, we declared a cash distribution of $0.68 per unit for
the quarterly period ended December 31, 2003. This distribution was paid on
February 13, 2004, to unitholders of record as of January 30, 2004. 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 $0.68
distribution per common unit. The number of i-units distributed was 778,309. For
each outstanding i-unit that KMR held, a fraction of an i-unit (0.015885) was
issued. The fraction was determined by dividing:

   o $0.68, the cash amount distributed per common unit

by

   o $42.807, the average of KMR's limited liability shares' closing market
     prices from January 13-27, 2004, 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 13, 2004 distribution required an incentive distribution to our
general partner in the amount of $85.8 million. Since this distribution was
declared after the end of the quarter, no amount is shown in our December 31,
2003 balance sheet as a Distribution Payable.

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<PAGE>

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.

   As of December 31, 2003, our general partner owned 1,724,000 common units,
representing approximately 0.91% 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.

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<PAGE>

   Typically, 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. For each outstanding i-unit, a
fraction of an i-unit will be issued. The fraction is calculated by dividing the
amount of cash being distributed per common unit by the average closing price of
KMR's shares over the ten consecutive trading days preceding the date on which
the shares begin to trade ex-dividend under the rules of the New York Stock
Exchange. The cash equivalent of distributions of i-units will be treated as if
it had actually been distributed 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, 2003, 2002 and 2001 were $322.8
million, $267.4 million and $199.7 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, 2003, KMI directly owned
8,838,095 common units and 5,313,400 Class B units, indirectly owned 4,117,640
common units owned by its consolidated affiliates, including our general partner
and owned 14,531,495 KMR shares, representing an indirect ownership interest of
14,531,495 i-units. Together, these units represent approximately 17.4% of our
outstanding limited partner units. Including both its general and limited
partner interests in us, at the 2003 distribution level, KMI received
approximately 51% of all quarterly distributions from us, of which approximately
41% 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, 2003, KMR, our general partner's delegate, remains the
sole owner of our 48,996,465 i-units.

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<PAGE>

   Asset Acquisitions

   Mexican Entity Transfer

   In the fourth quarter of 2002, KMI transferred to us its interests in Kinder
Morgan Natural Gas de Mexico, S. de R.L. de C.V., hereinafter referred to as KM
Mexico. KM Mexico is the entity through which we have developed the
Mexican portion of our Mier-Monterrey natural gas pipeline that connects to the
southern tip of Kinder Morgan Texas Pipeline, L.P.'s intrastate pipeline,
hereinafter referred to as the Monterrey pipeline. The Monterrey pipeline was
initially conceived at KMI in 1996 and between 1996 and 1998, KMI and its
subsidiaries paid, on behalf of KM Mexico, approximately $2.5 million in
connection with the Monterrey pipeline to explore the feasibility of and to
obtain permits for the Mexican portion of the pipeline. Following 1998, the
Monterrey pipeline was dormant at KMI.

   In December 2000, when KMI contributed to us Kinder Morgan Texas Pipeline,
L.P., the entity that had been primarily responsible for the Monterrey pipeline,
the Monterrey pipeline was still dormant (and thought likely to remain dormant
indefinitely). Consequently, KM Mexico was not contributed to us at that time.

   In 2002, Kinder Morgan Texas Pipeline, L.P. reassessed the Monterrey pipeline
and determined that the Monterrey pipeline was an economically feasible pipeline
for us. Accordingly, KMI's Board of Directors on the one hand, and KMR and our
general partner's Boards of Directors on the other hand, unanimously determined,
respectively, that KMI should transfer KM Mexico to us for approximately $2.5
million, the amount paid by KMI and its subsidiaries, on KM Mexico's behalf, in
connection with the Monterrey pipeline between 1996 and 1998.

   KMI 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. This amount has not changed as of December 31, 2003. KMI
would be obligated to perform under this guarantee only if we and/or our assets
were unable to satisfy our obligations.

   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 capital expenditures. NGPL
does not profit from or suffer loss related to its operation of Trailblazer
Pipeline Company's assets.

   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 $8.7 million of
fixed costs and $10.8 million of actual costs incurred for 2003, and $13.3
million of fixed costs and $2.8 million of actual costs incurred for 2002. 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 2004 will be approximately $19.8 million, which includes
$8.7 million of fixed costs (adjusted for inflation) and $11.1 million of actual
costs.

   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 have exactly matched 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

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<PAGE>

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 these assets.

   Retention Agreement

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

   Lines of Credit

   As of December 31, 2002, we had agreed to guarantee potential borrowings
under lines of credit available from Wachovia Bank, National Association,
formerly known as First Union National Bank, to Messrs. Thomas Bannigan, C. Park
Shaper, Joseph Listengart and James Street and Ms. Deborah Macdonald. Each of
these officers was primarily liable for any borrowing on his or her line of
credit, and if we made any payment with respect to an outstanding loan, the
officer on behalf of whom payment was made was required to surrender a
percentage of his or her options to purchase KMI common stock. Our obligations
under the guaranties, on an individual basis, generally did not exceed $1.0
million and such obligations, in the aggregate, did not exceed $1.9 million. As
of October 31, 2003, we had made no payments with respect to these lines of
credit and each line of credit was either terminated or refinanced without a
guarantee from us. We have no further guaranteed obligations with respect to any
borrowings by our officers.

   Other

   We own a 50% equity interest in Coyote Gas Treating, LLC, referred to herein
as Coyote Gulch. Coyote Gulch is a joint venture, and El Paso Field Services
Company owns the remaining 50% equity interest. We are the managing partner of
Coyote Gulch. As of December 31, 2003, Coyote's balance sheet has current notes
payable to each partner in the amount of $17.1 million. These notes are due on
June 30, 2004. At that time, the partners can either renew the notes or make
capital contributions which will enable Coyote to payoff the existing notes.

   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 Conflicts and 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.

                                      131
<PAGE>

13.  Leases and Commitments

   Operating Leases

   Including probable elections to exercise renewal options, the remaining terms
on our operating leases range from one to 39 years. Future commitments related
to these leases as of December 31, 2003 are as follows (in thousands):

                      2004......................   $  17,076
                      2005......................      14,955
                      2006......................      12,825
                      2007......................      11,623
                      2008......................      10,834
                      Thereafter................      35,440
                                                   ---------
                      Total minimum payments....   $ 102,753
                                                   =========

   We have not reduced our total minimum payments for future minimum sublease
rentals aggregating approximately $1.1 million. Total lease and rental expenses,
including related variable charges were $25.3 million for 2003, $21.6 million
for 2002 and $41.1 million for 2001.

   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, 2002, outstanding options for 263,600 common units had
been granted at an average exercise price of $17.25 per unit. Outstanding
options for 20,000 common units had been granted to 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, 2003, outstanding options for 129,050 common units had
been granted at an average exercise price of $17.46 per unit. Outstanding
options for 20,000 common units had been granted to two of Kinder Morgan G.P.,
Inc.'s three non-employee directors at an average exercise price of $20.58 per
unit.

   During 2002, 88,200 common unit options were exercised at an average price of
$17.77 per unit. The common units underlying these options had an average fair
market value of $34.24 per unit. During 2003, 134,550 common unit options 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.

   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 equal to the market price of the underlying common units at the grant date
and therefore, no compensation expense has been recorded. 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, is not material.

   Directors' Unit Appreciation Rights Plan

   On April 1, 2003, KMR's compensation committee established the Directors'
Unit Appreciation Rights Plan. Pursuant to this plan, each of KMR's three
non-employee directors is eligible to receive common unit appreciation rights.
The primary purpose of this plan is to promote the interests of our unitholders
by aligning the compensation of the non-employee members of the board of
directors of KMR with unitholders' interests. Secondly, since KMR's

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<PAGE>

success is dependent on its operation and management of our business and our
resulting performance, the plan is expected to align the compensation of the
non-employee members of the board with the interests of KMR's shareholders.

   Upon the exercise of unit appreciation rights, we will pay, within thirty
days of the exercise date, the participant an amount of cash equal to the
excess, if any, of the aggregate fair market value of the unit appreciation
rights exercised as of the exercise date over the aggregate award price of the
rights exercised. The fair market value of one unit appreciation right as of the
exercise date will be equal to the closing price of one common unit on the New
York Stock Exchange on that date. The award price of one unit appreciation right
will be equal to the closing price of one common unit on the New York Stock
Exchange on the date of grant. Each unit appreciation right granted under the
plan will be exercisable only for cash and will be evidenced by a unit
appreciation rights agreement.

   All unit appreciation rights granted vest on the six-month anniversary of the
date of grant. If a unit appreciation right is not exercised in the ten year
period following the date of grant, the unit appreciation right will expire and
not be exercisable after the end of such period. In addition, if a participant
ceases to serve on the board for any reason prior to the vesting date of a unit
appreciation right, such unit appreciation right will immediately expire on the
date of cessation of service and may not be exercised. The plan is administered
by KMR's compensation committee. The total number of unit appreciation rights
authorized under the plan is 500,000. KMR's board has sole discretion to
terminate the plan at any time with respect to unit appreciation rights which
have not previously been granted to participants.

   On April 1, 2003, the date of adoption of the plan, each of KMR's three
non-employee directors were granted 7,500 unit appreciation rights. In addition,
10,000 unit appreciation rights will be granted to each of KMR's three
non-employee directors during the first meeting of the board each January.
Accordingly, each non-employee director received an additional 10,000 unit
appreciation rights on January 21, 2004. As of December 31, 2003, 52,500 unit
appreciation rights had been granted. No unit appreciation rights were exercised
during 2003.

   Contingent Debt

   We apply the disclosure provisions of FASB 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 FASB 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 owners of
Cortez Pipeline Company (Kinder Morgan CO2 Company, L.P. - 50% owner; a
subsidiary of Exxon Mobil Corporation - 37% owner; and Cortez Vickers Pipeline
Company - 13% owner) are required, on a 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 owners 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 owners
further severally guarantee, on a percentage basis, the obligations of the
Cortez Pipeline Company owners 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 guaranty obligations jointly
and severally through December 31, 2006 for Cortez Capital Corporation's debt
programs in place as of April 1, 2000.

   As of December 31, 2003, the debt facilities of Cortez Capital Corporation
consisted of:

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<PAGE>

   o $95 million of Series D notes due May 15, 2013;

   o a $175 million short-term commercial paper program; and

   o a $175 million committed revolving credit facility due December 22, 2004
     (to support the above-mentioned $175 million commercial paper program).

   As of December 31, 2003, Cortez Capital Corporation had $135.7 million of
commercial paper outstanding with an interest rate of 1.12%, the average
interest rate on the Series D notes was 7.04% and there were no borrowings
under the credit facility.

   Plantation Pipeline Company Debt

   On April 30, 1997, Plantation Pipeline Company entered into a $10 million,
ten-year floating-rate term credit agreement. We, as an owner of Plantation
Pipeline Company, severally guarantee this debt on a pro rata basis equivalent
to our respective 51% ownership interest. During 1999, this agreement was
amended to reduce the maturity date by three years. The $10 million is
outstanding as of December 31, 2003.

   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 under joint and several liability. The principal is
to be repaid in seven equal installments beginning on October 31, 2004 and
ending on October 31, 2010. The $55 million is outstanding as of December 31,
2003.

   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.

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. Through KMI, 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. The fair value of these 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.

                                      134
<PAGE>

   Pursuant to our management's approved policy, we are to engage in these
activities only as a hedging mechanism against price volatility associated with:

   o pre-existing or anticipated physical natural gas, natural gas liquids and
     crude oil sales;

   o pre-existing or anticipated physical carbon dioxide sales that have pricing
     tied to crude oil prices;

   o natural gas purchases; and

   o system use and storage.

   Our risk management activities are only used in order to protect our profit
margins and our risk management policies prohibit us from engaging in
speculative trading. Commodity-related activities of our risk management group
are monitored by our Risk Management Committee, which is charged with the review
and enforcement of our management's risk management policy.

   Certain of our business activities expose us to foreign currency
fluctuations. However, due to the limited size of this exposure, we do not
believe the risks associated with changes in foreign currency will have a
material adverse effect on our business, financial position, results of
operations or cash flows. Accordingly, as of December 31, 2003, no financial
instruments were used to limit the effects of foreign exchange rate fluctuations
on our financial results. In February 2004, we entered into a single $17.0
million foreign currency call option that expires on December 31, 2004.

   Our derivatives hedge our commodity price risks involving 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. To be considered effective, 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 is reported in earnings immediately.

   As a result of our adoption of SFAS No. 133, as discussed in Note 2, we
recorded a cumulative effect adjustment in other comprehensive income of $22.8
million representing the fair value of our derivative financial instruments
utilized for hedging activities as of January 1, 2001. During the year ended
December 31, 2001, $16.6 million of this initial adjustment was reclassified to
earnings as a result of hedged sales and purchases during the period. During
2001, we reclassified a total of $51.5 million to earnings as a result of hedged
sales and purchases during the period.

   The gains and losses included in "Accumulated other comprehensive income
(loss)" in the accompanying consolidated balance sheets are reclassified into
earnings as the hedged sales and purchases take place. Approximately $65.4
million of the Accumulated other comprehensive loss balance of $155.8 million
representing unrecognized net losses on derivative activities as of December 31,
2003 is expected to be reclassified into earnings during the next twelve months.
During the twelve months ended December 31, 2003, we reclassified $82.1 million
of Accumulated other comprehensive income into earnings. This amount includes
the balance of $45.3 million representing unrecognized net losses on derivative
activities as of December 31, 2002. For each of the years ended December 31,
2003, 2002 and 2001, no gains or losses were reclassified into earnings as a
result of the discontinuance of cash flow hedges due to a determination that the
forecasted transactions will no longer occur by the end of the originally
specified time period.

   Purchases or sales of commodity contracts require a dollar amount to be
placed in margin accounts. In addition, through KMI, 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 $10.3 million as of
December 31, 2003 and $1.9 million as of December 31, 2002. Our margin deposits
associated with over-the-counter swap partners were $7.7 million as of December
31, 2003 and $0.0 million as of December 31, 2002.

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<PAGE>

   We recognized a gain of $0.5 million during 2003, a gain of $0.7 million
during 2002 and a loss of $1.3 million during 2001 as a result of ineffective
hedges. All of these amounts are reported within the captions "Gas purchases and
other costs of sales" or "Operations and maintenance" in our accompanying
Consolidated Statements of Income. For each of the years ended December 31,
2003, 2002 and 2001, 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. As of December 31, 2003, the balance
in "Other current assets" on our consolidated balance sheet included $18.2
million related to risk management hedging activities, and the balance in
"Accrued other current liabilities" included $90.4 million related to risk
management hedging activities. As of December 31, 2002, the balance in "Other
current assets" on our consolidated balance sheet included $57.9 million related
to risk management hedging activities, and the balance in "Accrued other current
liabilities" included $101.3 million related to risk management hedging
activities. As of December 31, 2003, the balance in "Deferred charges and other
assets" included $2.7 million related to risk management hedging activities, and
the balance in "Other long-term liabilities and deferred credits" included
$101.5 million related to risk management hedging activities. As of December 31,
2002, the balance in "Deferred charges and other assets" included $5.7 million
related to risk management hedging activities, and the balance in "Other
long-term liabilities and deferred credits" included $8.5 million related to
risk management hedging activities.

   Given our portfolio of businesses as of December 31, 2003, 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. In addition, crude oil
contracts have been sold to hedge anticipated carbon dioxide purchases and sales
that have pricing tied to crude oil prices. 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, 2003, 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 2009.

   As of December 31, 2003, our commodity contracts and over-the-counter swaps
and options (in thousands) consisted of the following:
<TABLE>
<CAPTION>

                                                                      Over the
                                                                      Counter
                                                                     Swaps and
                                                        Commodity     Options
                                                        Contracts    Contracts      Total
                                                       ----------    ---------   ----------
                                                                (Dollars in thousands)
<S>                                                    <C>           <C>         <C>
  Deferred Net (Loss) Gain........................     $    5,261    $(178,480)  $ (173,219)
  Contract Amounts-- Gross........................     $   68,934    $ 954,313   $1,023,247
  Contract Amounts-- Net..........................     $   (3,687)   $(890,105)  $ (893,792)

                                                               (Number of contracts(1))
  Natural Gas
    Notional Volumetric Positions: Long...........            663          588        1,251
    Notional Volumetric Positions: Short..........           (670)      (2,369)      (3,039)
    Net Notional Totals to Occur in 2004..........             (7)      (1,756)      (1,763)
    Net Notional Totals to Occur in 2005 and Beyond            --          (25)         (25)
  Crude Oil
    Notional Volumetric Positions: Long...........             --          336          336
    Notional Volumetric Positions: Short..........             --      (37,418)     (37,418)
    Net Notional Totals to Occur in 2004..........             --      (10,854)     (10,854)
    Net Notional Totals to Occur in 2005 and Beyond            --      (26,228)     (26,228)
  Natural Gas Liquids
    Notional Volumetric Positions: Long...........             --           --           --
    Notional Volumetric Positions: Short..........             --         (460)        (460)
    Net Notional Totals to Occur in 2004..........             --         (336)        (336)
    Net Notional Totals to Occur in 2005 and Beyond            --         (124)        (124)
</TABLE>
----------

                                      136
<PAGE>

(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 December 31, 2003 we 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.

   During the fourth quarter of 2001, we determined that Enron Corp. was no
longer likely to honor the obligations it had to us in conjunction with
derivatives we were accounting for as hedges under SFAS No. 133. Upon making
that determination, we:

   o ceased to account for those derivatives as hedges;

   o entered into new derivative transactions on substantially similar terms
     with other counterparties to replace our position with Enron;

   o designated the replacement derivative positions as hedges of the exposures
     that had been hedged with the Enron positions; and

   o recognized a $6.0 million loss (included with "General and administrative
     expenses" in our accompanying Consolidated Statement of Operations for
     2001) in recognition of the fact that it was unlikely that we would be paid
     the amounts then owed under the contracts with Enron.

   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 debt and variable rate debt. As of
December 31, 2003 and December 31, 2002, we were a party to interest rate swap
agreements with a notional principal amount of $2.1 billion and $1.95 billion,
respectively, for the purpose of hedging the interest rate risk associated with
our fixed and variable rate debt obligations.

   As of December 31, 2003, a notional principal amount of $2.0 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 $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.

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<PAGE>

   These swap agreements have termination dates that correspond to the maturity
dates of the related series of senior notes, therefore, as of December 31, 2003,
the maximum length of time over which we have hedged a portion of our exposure
to the variability in future cash flows associated with interest rate risk is
through August 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 at March 15, 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 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, 2003, 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. Prior to March 2002, this swap was
designated a hedge of our $200 million Floating Rate Senior Notes, which were
retired (repaid) in March 2002. Subsequent to the repayment of our Floating Rate
Senior Notes, the swaps were 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. As of December 31, 2003, we
recognized an asset of $129.6 million and a liability of $8.1 million for the
$121.5 million net fair value of our swap agreements, and we included these
amounts with "Deferred charges and other assets" and "Other long-term
liabilities and deferred credits" on our accompanying balance sheet. The
offsetting entry to adjust the carrying value of the debt securities whose fair
value was being hedged was recognized as "Market value of interest rate swaps"
on our accompanying balance sheet. As of December 31, 2002, we recognized an
asset of $179.1 million and a liability of $12.1 million for the $167.0 million
net fair value of our swap agreements, and we included these amounts with
"Deferred charges and other assets" and "Other long-term liabilities and
deferred credits" on our accompanying balance sheet. The offsetting entry to
adjust the carrying value of the debt securities whose fair value was being
hedged was recognized as "Market value of interest rate swaps" on our
accompanying balance sheet.

   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 (see Note 1):

   o Products Pipelines;

   o Natural Gas Pipelines;

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<PAGE>

   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, which exclude general and
administrative expenses, third-party debt costs, interest income and expense and
minority interest. Our reportable segments are strategic business units that
offer different products and services. Each segment is managed separately
because each segment involves different products and marketing strategies.

   Our Products Pipelines segment derives its revenues primarily from the
transportation and terminaling of refined petroleum products, including
gasoline, diesel fuel, jet fuel and natural gas liquids. Our Natural Gas
Pipelines segment derives its revenues primarily from the 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):
                                                2003       2002        2001
                                             ---------- ----------- ----------
          Revenues
            Products Pipelines.............  $  585,376 $  576,542  $  605,392
            Natural Gas Pipelines..........   5,316,853  3,086,187   1,869,315
            CO2............................     248,535    146,280     122,094
            Terminals......................     473,558    428,048     349,875
                                             ---------- ----------- ----------
            Total consolidated revenues....  $6,624,322 $4,237,057  $2,946,676
                                             ========== ==========  ==========

       Operating expenses(a)
         Products Pipelines................  $  169,526 $  169,782  $  240,537
         Natural Gas Pipelines.............   4,967,531  2,784,278   1,665,852
         CO2...............................      82,055     50,524      44,973
         Terminals.........................     229,054    213,929     175,869
                                             ---------- ----------  ----------
         Total consolidated operating
          expenses.........................  $5,448,166 $3,218,513  $2,127,231
                                             ========== ==========  ==========
(a)Includes natural gas purchases and other costs of sales, operations and
   maintenance expenses, fuel and power expenses and taxes, other than income
   taxes.

        Earnings from equity investments
          Products Pipelines...............  $   30,948 $   28,998   $  28,278
          Natural Gas Pipelines............      24,012     23,887      22,558
          CO2..............................      37,198     36,328      33,998
          Terminals........................          41         45          --
                                             ---------- ----------  ----------
          Total consolidated equity
            earnings.......................  $   92,199 $   89,258  $   84,834
                                             ========== ==========  ==========
          Amortization of excess cost of equity investments
            Products Pipelines.............  $    3,281 $    3,281  $    5,592
            Natural Gas Pipelines..........         277        277       1,402
            CO2............................       2,017      2,017       2,017
            Terminals......................          --         --          --
                                             ---------- ----------  ----------
            Total consol. amortization of    $    5,575 $    5,575  $    9,011
                                             ========== ==========  ==========
          excess cost of invests...........

        Other, net-income (expense)(a)
          Products Pipelines...............  $    6,471 $  (14,000) $      440
          Natural Gas Pipelines............       1,082         36         749
          CO2..............................         (40)       112         547
          Terminals........................          88     15,550         226
                                             ---------- ----------  ----------
          Total consolidated Other,
           net-income (expense)............  $    7,601 $    1,698  $    1,962
                                             ========== ==========  ==========
(a) 2002 amounts include environmental expense adjustments resulting in a $15.7
    million loss to our Products Pipelines business segment and a $16.0 million
    gain to our Terminals business segment.

                                      139
<PAGE>

      Income tax benefit (expense)
        Products Pipelines.................  $  (11,669)$  (10,154) $   (9,653)
        Natural Gas Pipelines..............      (1,066)      (378)         --
        CO2................................         (39)        --          --
        Terminals..........................      (3,857)    (4,751)     (6,720)
                                             ---------- ----------  ----------
        Total consolidated income tax
         benefit (expense).................  $  (16,631)$  (15,283) $  (16,373)
                                             ========== ==========  ==========
      Segment earnings before
      depreciation, depletion,
      amortization and amortization of
      excess cost of equity investments
        Products Pipelines.................  $   441600 $  411,604  $  383,920
        Natural Gas Pipelines..............     373,350    325,454     226,770
        CO2................................     203,599    132,196     111,666
        Terminals..........................     240,776    224,963     167,512
                                             ---------- ----------  ----------
        Total  segment  earnings  before
         DD&A(a)...........................   1,259,325  1,094,217     889,868
        Consolidated depreciation and
         amortization......................    (219,032)  (172,041)   (142,077)
        Consolidated amortization of
         excess cost of invests............      (5,575)    (5,575)     (9,011)
        Interest and corporate
         administrative expenses(b)........    (337,381)  (308,224)   (296,437)
                                             ---------- ----------  ----------
        Total consolidated net income......  $  697,337 $  608,377  $  442,343
                                             ========== ==========  ==========

(a)  Includes revenues, earnings from equity investments, income taxes and
     other, net, less operating expenses.
(b)  Includes interest and debt expense, general and administrative expenses,
     minority interest expense and cumulative effect adjustment from a change in
     accounting principle (2003 only).

<TABLE>
<CAPTION>
<S>                                                 <C>             <C>             <C>
Segment earnings
  Products Pipelines.............................   $     370,974   $     343,935   $     312,464
  Natural Gas Pipelines..........................         319,288         276,766         193,804
  CO2............................................         140,755         100,983          92,087
  Terminals......................................         203,701         194,917         140,425
                                                    -------------   -------------   -------------
  Total segment earnings.........................       1,034,718         916,601         738,780
  Interest and corporate administrative expenses.        (337,381)       (308,224)       (296,437)
                                                    -------------   -------------   -------------
  Total consolidated net income..................   $     697,337   $     608,377   $     442,343
                                                    =============   =============   =============

   Assets at December 31
     Products Pipelines..........................   $   3,198,107   $   3,088,799   $   3,095,899
     Natural Gas Pipelines.......................       3,253,792       3,121,674       2,058,836
     CO2.........................................       1,177,645         613,980         503,565
     Terminals...................................       1,368,279       1,165,096         990,760
                                                    -------------   ------------    -------------
     Total segment assets........................       8,997,823       7,989,549       6,649,060
     Corporate assets(a).........................         141,359         364,027          83,606
                                                    -------------   ------------    -------------
     Total consolidated assets...................   $   9,139,182   $   8,353,576   $   6,732,666
                                                    =============   =============   =============
(a) Includes cash, cash equivalents and certain unallocable deferred charges.

Depreciation, depletion and amortization
  Products Pipelines...........................     $      67,345   $      64,388   $      65,864
  Natural Gas Pipelines........................            53,785          48,411          31,564
  CO2..........................................            60,827          29,196          17,562
  Terminals....................................            37,075          30,046          27,087
                                                    -------------   -------------   -------------
  Total consol. depreciation, depletion and
   amortiz.....................................     $     219,032   $     172,041   $     142,077
                                                    =============   =============   =============
Investments at December 31
  Products Pipelines...........................     $     226,680   $     220,203   $     225,561
  Natural Gas Pipelines........................           164,924         157,778         146,566
  CO2..........................................            12,591          71,283          68,232
  Terminals....................................               150           2,110             159
                                                    -------------   -------------   -------------
  Total consolidated investments...............     $     404,345   $     451,374   $     440,518
                                                    =============   =============   =============

Capital expenditures
  Products Pipelines...........................     $      94,727   $      62,199   $      84,709
  Natural Gas Pipelines........................           101,679         194,485          86,124
  CO2..........................................           272,177         163,183          65,778
  Terminals....................................           108,396         122,368          58,477
                                                    -------------   -------------   -------------
  Total consolidated capital expenditures......     $     576,979   $     542,235   $     295,088
                                                    =============   =============   =============
</TABLE>

                                      140
<PAGE>

   We do not attribute interest income or interest expense to any of our
reportable business segments. For each of the years ended December 31, 2003,
2002 and 2001, we reported (in thousands) total consolidated interest revenue of
$1,420, $1,819 and $4,473, respectively. For each of the years ended December
31, 2003, 2002 and 2001, we reported (in thousands) total consolidated interest
expense of $182,777, $178,279 and $175,930, respectively.

   Our total operating revenues are derived from a wide customer base. For each
of the years ended December 31, 2003, 2002 and 2001, one customer accounted for
more than 10% of our total consolidated revenues. Total transactions within our
Natural Gas Pipelines segment in 2003 and 2002 with CenterPoint Energy accounted
for 16.84% and 15.6% of our total consolidated revenues during 2003 and 2002,
respectively. Total transactions within our Natural Gas Pipelines and Terminals
segment in 2001 with the Reliant Energy group of companies, including the
entities which became CenterPoint Energy in October 2002, accounted for 20.2% of
our total consolidated revenues during 2001.

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 herein 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 non-discriminatory.
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, expands 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, 2003, 2002 and 2001, 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 herein 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. 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.

   The complainants in the proceedings before the FERC have alleged a variety of
grounds for finding "substantially changed circumstances." Applicable rules and
regulations in this field are vague, relevant factual issues are complex, and
there is little precedent available regarding the factors to be considered or
the method of analysis to be employed in making a determination of
"substantially changed circumstances." If SFPP rates previously "grandfathered"
under the Energy Policy Act lose their "grandfathered" status and are found to
be unjust and unreasonable, shippers may be entitled to prospective rate
reductions and complainants may be entitled to reparations for periods from the
date of their respective complaint to the date of the implementation of the new
rates.

   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 SFPP on the
interstate portion of its pipelines (see OR96-2 section below for further
discussion). In his phase one initial decision, the administrative law judge
recommended that the FERC "ungrandfather" SFPP's interstate rates and found most
of SFPP's rates at issue to be unjust and unreasonable. The administrative law
judge has indicated that a phase two initial decision will address prospective
rates and whether reparations are necessary.

                                      141
<PAGE>

   Initial decisions have no force or effect and must be reviewed by the FERC.
The FERC is not obliged to follow any of the administrative law judge's findings
and can accept or reject this initial decision in whole or in part. In addition,
as stated above, the facts are complex, the rules and regulations in this area
are vague and little precedent exists. The FERC is now considering the phase one
initial decision and will consider the phase two initial decision when it is
issued and briefed by the parties. If the FERC ultimately finds, after reviewing
both initial decisions, that these rates should be "ungrandfathered" and are
unjust and unreasonable, they could be lowered prospectively and complaining
shippers could be entitled to reparations for prior periods. We do not expect
any impact on our rates relating to this matter before early 2005.

   We currently believe that these FERC complaints seek approximately $154
million in tariff reparations and prospective annual tariff reductions, the
aggregate average annual impact of which would be approximately $45 million. As
the length of time from the filing of the complaints increases, the amounts
sought by complainants in tariff reparations will likewise increase until a
determination of reparations owed is made by the FERC. 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
administrative law judge's initial decision does not change our estimate of what
the complainants seek. Furthermore, even if "substantially changed
circumstances" are found to exist, we believe that the resolution of these FERC
complaints will be for amounts substantially less than the amounts sought and
that the resolution of such matters will not have a material adverse effect on
our business, financial position, results of operations or cash flows.

   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 those proceedings.

   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 "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.

   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 "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

                                      142
<PAGE>

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 payments of $44.9 million in 2003 for
reparations and refunds under order from the FERC.

   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. The Court of Appeals is expected to
issue its decision in the first or second quarter of 2004.

   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.

                                      143
<PAGE>

   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 for
service on the Sepulveda line is just and reasonable. That issue is currently
pending before the administrative law judge in the Docket No. OR96-2, et al.
proceeding. The procedural schedule in this remanded matter is currently
suspended pending issuance of the phase two initial decision in the Docket No.
OR96-2, et al. proceeding (see below).

   OR96-2; OR97-2; OR98-1. et al. proceedings. In October 1996, Ultramar 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 Diamond Shamrock Corporation 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 the 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 RHC 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. The initial decision indicated that
a phase two initial decision will address prospective rates and whether
reparations are necessary. Issuance of the phase two initial decision is
expected sometime in the first quarter of 2004.

   SFPP has filed a brief on exceptions to the FERC that contests the findings
in the initial decision. SFPP's opponents have responded to SFPP's brief. The
FERC is now considering the phase one initial decision and will consider the
phase two initial decision when it is issued and briefed by the parties. If the
FERC ultimately finds, after reviewing both initial decisions, that these rates
should be "ungrandfathered" and are unjust and unreasonable, they could be
lowered prospectively and complaining shippers could be entitled to reparations
for prior periods. We do not expect any impact on our rates relating to this
matter before early 2005.

   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

                                      144
<PAGE>

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. 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 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 outcome
of the appeal of the Docket No. OR92-8, et al. proceeding.

   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.

   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 is anticipated within the third quarter of
2004.

   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 are
expected to be resolved by the CPUC by the third quarter of 2004.

                                      145
<PAGE>

   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 during the third quarter of 2004.

   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

   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 also includes a number of non-rate tariff
changes. By an order issued December 31, 2002, FERC effectively bifurcated the
proceeding. The rate change was accepted to be effective on January 1, 2003,
subject to refund and a hearing. Most of the non-rate tariff changes were
suspended until June 1, 2003, subject to refund and a technical conference
procedure.

   Trailblazer sought rehearing of the FERC order with respect to the refund
condition on the rate decrease. On April 15, 2003, the FERC granted
Trailblazer's rehearing request to remove the refund condition that had been
imposed in the December 31, 2002 Order. Certain intervenors have sought
rehearing as to the FERC's acceptance of certain non-rate tariff provisions. A
prehearing conference on the rate issues was held on January 16, 2003, where a
procedural schedule was established.

   The technical conference on non-rate issues was held on February 6, 2003.
Those 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 these issues as discussed at the technical conference were filed
by parties in March 2003. On May 23, 2003, FERC issued an order deciding
non-rate tariff issues and denying rehearing of its prior order. In the May 23,
2003 order, 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 10 years (in lieu of the current 5 years); and

   o accepted Trailblazer's withdrawal of daily imbalance charges.

   The referenced order did the following:

   o allowed shortened notice periods for suspension of service, but required at
     least 30 days notice for service termination;

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   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 have sought rehearing of the May 23, 2003
order. Trailblazer made its compliance filing on June 20, 2003. Under the May
23, 2003 order, these tariff changes are effective as of May 23, 2003, except
that Trailblazer has filed to make the revised credit procedures effective
August 15, 2003.

   With respect to the on-going rate review phase of the case, direct testimony
was filed by FERC Staff and Indicated Shippers on May 22, 2003 and
cross-answering testimony was filed by Indicated Shippers on June 19, 2003.
Trailblazer's answering testimony was filed on July 29, 2003.

   On September 22, 2003, Trailblazer filed an offer of settlement with the
FERC. Under the settlement, if approved by the FERC, Trailblazer's rate would be
reduced effective January 1, 2004, from about $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. We do not expect the settlement to have a material effect on
our consolidated revenues in 2004 or in subsequent periods.

   FERC Order 637

   Kinder Morgan Interstate Gas Transmission LLC

   On June 15, 2000, Kinder Morgan Interstate Gas Transmission LLC made its
filing to comply with FERC's Orders 637 and 637-A. That filing contained KMIGT's
compliance plan to implement the changes required by the FERC dealing with the
way business is conducted on interstate natural gas pipelines. All interstate
natural gas pipelines were required to make such compliance filings, according
to a schedule established by the FERC. From October 2000 through June 2001,
KMIGT held a series of technical and phone conferences to identify issues,
obtain input, and modify its Order 637 compliance plan, based on comments
received from FERC staff and other interested parties and shippers. On June 19,
2001, KMIGT received a letter from the FERC encouraging it to file revised
pro-forma tariff sheets, which reflected the latest discussions and input from
parties into its Order 637 compliance plan. KMIGT made such a revised Order 637
compliance filing on July 13, 2001. The July 13, 2001 filing contained little
substantive change from the original pro-forma tariff sheets that KMIGT
originally proposed on June 15, 2000. On October 19, 2001, KMIGT received an
order from the FERC, addressing its July 13, 2001 Order 637 compliance plan. In
the Order addressing the July 13, 2001 compliance plan, KMIGT's plan was
accepted, but KMIGT was directed to make several changes to its tariff, and in
doing so, was directed that it could not place the revised tariff into effect
until further order of the FERC. KMIGT filed its compliance filing with the
October 19, 2001 Order on November 19, 2001 and also filed a request for
rehearing/clarification of the FERC's October 19, 2001 Order on November 19,
2001. Several parties protested the November 19, 2001 compliance filing. KMIGT
filed responses to those protests on December 14, 2001.

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   On May 22, 2003, KMIGT received an Order on Rehearing and Compliance Filing
(May 2003 Order) from the FERC, addressing KMIGT's November 19, 2001 filed
request for rehearing and filing to comply with the directives of the October
19, 2001 Order. The May 2003 Order granted in part and denied in part KMIGT's
request for rehearing, and directed KMIGT to file certain revised tariff sheets
consistent with the May 2003 Order's directives. On June 20, 2003, KMIGT
submitted its compliance filing reflecting revised tariff sheets in accordance
with the FERC's directives. Consistent with the May 2003 Order, KMIGT's
compliance filing reflected tariff sheets with proposed effective dates of June
1, 2003 and December 1, 2003. Those sheets with a proposed effective date of
December 1, 2003 concern tariff provisions necessitating computer system
modifications.

   On November 21, 2003, KMIGT received a Letter Order (November 21 Order) from
the FERC accepting the tariff sheets submitted in the June 20, 2003 compliance
filing. In accordance with the November 21 Order, KMIGT commenced full
implementation of Order No. 637 on December 1, 2003. KMIGT's actual operating
experience under the full requirements of Order No. 637 is limited. However, we
believe that these matters will not have a material adverse effect on our
business, financial position, results of operations or cash flows.

   Separately, numerous petitioners, including KMIGT, have filed appeals in
respect of Order 637 in the D.C. Circuit, potentially raising a wide array of
issues related to Order 637 compliance. Initial briefs were filed on April 6,
2001, addressing issues contested by industry participants. Oral arguments on
the appeals were held before the court in December 2001. On April 5, 2002, the
D.C. Circuit issued an order largely affirming Order Nos. 637, et seq. The D.C.
Circuit remanded the FERC's decision to impose a 5-year cap on bids that an
existing shipper would have to match in the right of first refusal process. The
D.C. Circuit also remanded the FERC's decision to allow forward-hauls and
backhauls to the same point. Finally, the D.C. Circuit held that several aspects
of the FERC's segmentation policy and its policy on discounting at alternate
points were not ripe for review. The FERC requested comments from the industry
with respect to the issues remanded by the D.C. Circuit. They were due July 30,
2002.

   On October 31, 2002, the FERC issued an order in response to the D.C.
Circuit's remand of certain Order 637 issues. The order:

   o eliminated the requirement of a 5-year cap on bid terms that an existing
     shipper would have to match in the right of first refusal process, and
     found that no term matching cap is necessary given existing regulatory
     controls;

   o affirmed FERC's policy that a segmented transaction consisting of both a
     forwardhaul up to contract demand and a backhaul up to contract demand to
     the same point is permissible; and

   o accordingly required, under Section 5 of the Natural Gas Act, pipelines
     that the FERC had previously found must permit segmentation on their
     systems to file tariff revisions within 30 days to permit such segmented
     forwardhaul and backhaul transactions to the same point.

   On December 23, 2002, KMIGT filed revised tariff provisions (in a separate
docket) in compliance with the October 31, 2002 Order concerning the elimination
of the right of first refusal five-year term matching cap. In an order issued
January 22, 2003, the FERC approved such revised tariff provisions to be
effective January 23, 2003.

   Trailblazer Pipeline Company

   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;

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   o operational flow orders;

   o penalty revenue crediting; and

   o right of first refusal language.

   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 order of October 15, 2001 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 the compliance filing subject to modifications that
must be made within 30 days of the order.

   Trailblazer made those modifications in a further compliance filing on May
 16, 2003. Certain shippers have filed a limited protest regarding that
 compliance filing. That filing is pending FERC action. Under the FERC orders,
 limited aspects of Trailblazer's plan (revenue crediting) were effective as of
 May 1, 2003. The entire plan went into effective on December 1, 2003.

   Trailblazer anticipates no adverse impact on its business as a result of the
 implementation of Order No. 637.

   Standards of Conduct Rulemaking

  On September 27, 2001, the FERC issued a Notice of Proposed Rulemaking in
Docket No. RM01-10 in which it proposed new rules governing the interaction
between an interstate natural gas pipeline and its affiliates. If adopted as
proposed, the Notice of Proposed Rulemaking could be read to limit
communications between Kinder Morgan Interstate Gas Transmission LLC,
Trailblazer and their respective affiliates. In addition, the Notice could be
read to require separate staffing of Kinder Morgan Interstate Gas Transmission
LLC and its affiliates, and Trailblazer and its affiliates. Comments on the
Notice of Proposed Rulemaking were due December 20, 2001. Numerous parties,
including Kinder Morgan Interstate Gas Transmission LLC, have filed comment on
the Proposed Standards of Conduct Rulemaking. On May 21, 2002, the FERC held a
technical conference dealing with the FERC's proposed changes in the Standard of
Conduct Rulemaking. On June 28, 2002, Kinder Morgan Interstate Gas Transmission
LLC and numerous other parties filed additional written comments under a
procedure adopted at the technical conference.

   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. 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.

   On November 25, 2003, the FERC issued Order No. 2004, adopting new Standards
of Conduct to become effective February 9, 2004. Every interstate pipeline must
file a compliance plan by that date and must be in full compliance with the
Standards of Conduct by June 1, 2004. The primary change from existing
regulation is to make such standards applicable to an interstate pipeline's
interaction with many more affiliates (referred to as "energy affiliates"),
including intrastate/Hinshaw pipelines, processors and gatherers and any company
involved in natural gas or electric markets (including natural gas marketers)
even if they do not ship on the affiliated interstate pipeline. Local
distribution companies are excluded, however, if they do not make off-system
sales. The Standards of Conduct require, among other things, separate staffing
of interstate pipelines and their energy affiliates (but support functions and
senior management at the central corporate level may be shared) and strict
limitations on communications from the interstate pipeline to an energy
affiliate.

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

   On February 11, 2004, the FERC approved a final rule in Docket No. RM03-8-000
requiring jurisdictional entities to file quarterly financial reports with the
FERC. Electric utilities, natural gas companies, and licensees will file Form
3-Q, while oil pipeline companies will submit Form 6-Q. The final rule also
adopts some minimal changes to the annual financial reports filed with the FERC.
The final rule modifies the Notice of Proposed Rulemaking by eliminating the
management discussion and analysis section from both the quarterly and annual
reports, and eliminating the use of fourth quarter data in the annual report. In
addition, the final rule eliminates the cash management notification requirement
adopted in FERC Order No. 634-A. The FERC said it will also use the quarterly
financial information when reviewing the adequacy of traditional cost-based
rates. The first quarterly reports for major public utilities, licensees, and
natural gas companies will be due on July 9, 2004. The first quarterly reports
for non-major public utilities, licensees, natural gas companies, and all oil
pipeline companies will be due on July 23, 2004. After the transition period,
major public utilities, licensees and natural gas companies will file quarterly
reports 60 days after the end of the quarter; non-major public utilities,
licensees, natural gas companies, and all oil pipeline companies will file 70
days after the end of the quarter.

   Cash Management

   The FERC also issued a Notice of Proposed Rulemaking in Docket No.
RM02-14-000 in which it proposed new regulations for cash management practices,
including establishing limits on the amount of funds that can be swept from a
regulated subsidiary to a non-regulated parent company. Kinder Morgan Interstate
Gas Transmission LLC filed comments on August 28, 2002. On June 26, 2003, FERC
issued an interim rule to be effective August 7, 2003, under which regulated
companies are required to document cash management arrangements and
transactions. The interim rule does not include a proposed rule that would have
required regulated companies, as a prerequisite to participation in cash
management programs, to maintain a proprietary capital ratio of 30% and an
investment grade credit rating. On October 22, 2003, the FERC issued its final
rule amending its regulations effective November 2003 which, among other things,
requires FERC-regulated entities to file their cash management agreements with
the FERC and to notify the FERC within 45 days after the end of the quarter when
their proprietary capital ratio drops below 30%, and when it subsequently
returns to or exceeds 30%. KMIGT and Trailblazer filed their cash management
agreements with the FERC on or before the deadline, which was December 10, 2003.
We believe that these matters, as finally adopted, will not have a material
adverse effect on our business, financial position, results of operations or
cash flows.

   Other Regulatory

   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.

   Southern Pacific Transportation Company Easements

   SFPP, L.P. and Southern Pacific Transportation Company are engaged in a
judicial reference proceeding to determine the extent, if any, to which the rent
payable by SFPP for the use of pipeline easements on rights-of-way held by SPTC
should be adjusted pursuant to existing contractual arrangements (Southern
Pacific Transportation
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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). In the second quarter
of 2003, the trial court set the rent at approximately $5.0 million per year as
of January 1, 1994. SPTC has appealed the matter to the California Court of
Appeals.

   Carbon Dioxide Litigation

   Kinder Morgan CO2 Company, L.P. directly or indirectly through its ownership
interest in the Cortez Pipeline Company, along with other entities, has been
named as a defendant with several others in a series of lawsuits in the United
States District Court in Denver, Colorado and certain state courts in Colorado
and Texas. The plaintiffs include several private royalty, overriding royalty
and working interest owners at the McElmo Dome (Leadville) Unit in southwestern
Colorado. Plaintiffs in the Colorado state court action also are overriding
royalty interest owners in the Doe Canyon Unit. Plaintiffs seek to also
represent classes of claimants composed of all private and governmental royalty,
overriding royalty and working interest owners, and governmental taxing
authorities who have an interest in the carbon dioxide produced at the McElmo
Dome Unit. Plaintiffs claim they and the members of any classes that might be
certified have been damaged because the defendants have maintained a low price
for carbon dioxide in the enhanced oil recovery market in the Permian Basin and
maintained a high cost of pipeline transportation from the McElmo Dome Unit to
the Permian Basin. Plaintiffs claim breaches of contractual and potential
fiduciary duties owed by defendants and also allege other theories of liability
including:

   o common law fraud;

   o fraudulent concealment; and

   o negligent misrepresentation.

   In addition to actual or compensatory damages, certain plaintiffs are seeking
punitive or trebled damages as well as declaratory judgment for various forms of
relief, including the imposition of a constructive trust over the defendants'
interests in the Cortez Pipeline and the Partnership. These cases are: CO2
Claims Coalition, LLC v. Shell Oil Co., et al., No. 96-Z-2451 (U.S.D.C. Colo.
filed 8/22/96); Rutter & Wilbanks et al. v. Shell Oil Co., et al., No. 00-Z-1854
(U.S.D.C. Colo. filed 9/22/00); Watson v. Shell Oil Co., et al., No. 00-Z-1855
(U.S.D.C. Colo. filed 9/22/00); Ainsworth et al. v. Shell Oil Co., et al., No.
00-Z-1856 (U.S.D.C. Colo. filed 9/22/00); Shell Western E&P Inc. v. Bailey, et
al., No 98-28630 (215th Dist. Ct. Harris County, Tex. filed 6/17/98); Shores, et
al. v. Mobil Oil Corporation, et al., No. GC-99-01184 (Texas Probate Court,
Denton County filed 12/22/99); First State Bank of Denton v. Mobil Oil
Corporation, et al., No. PR-8552-01 (Texas Probate Court, Denton County filed
3/29/01); and Celeste C. Grynberg v. Shell Oil Company, et al., No. 98-CV-43
(Colo. Dist. Ct., Montezuma County filed 3/21/98).

   At a hearing conducted in the United States District Court for the District
of Colorado on April 8, 2002, the Court orally announced that it had approved
the certification of proposed plaintiff classes and approved a proposed
settlement in the CO2 Claims Coalition, LLC, Rutter & Wilbanks, Watson, and
Ainsworth cases. The Court entered a written order approving the Settlement on
May 6, 2002. Plaintiffs counsel representing Shores, et al. appealed the court's
decision to the 10th Circuit Court of Appeals. On December 26, 2002, the 10th
Circuit Court of Appeals affirmed in all respects the District Court's Order
approving settlement. On March 24, 2003, the plaintiffs' counsel in the Shores
matter filed a Petition for Writ of Certiorari in the United States Supreme
Court seeking to have the Court review and overturn the decision of the 10th
Circuit Court of Appeals. On June 9, 2003, the United States Supreme Court
denied the Writ of Certiorari. On July 16, 2003, the settlement in the CO2
Claims Coalition, LLC, Rutter & Wilbanks, Watson, and Ainsworth cases became
final. Following the decision of the 10th Circuit, the plaintiffs and defendants
jointly filed motions to abate the Shell Western E&P Inc., Shores and First
State Bank of Denton cases in order to afford the parties time to discuss
potential settlement of those matters. These Motions were granted on February 6,
2003. In the Celeste C. Grynberg case, the parties are currently engaged in
discovery.

   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

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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.

   Will Price, et al. v. Gas Pipelines, et al., (f/k/a Quinque Operating
Company et al. v. Gas Pipelines, et al.)

   Stevens County, Kansas District Court, Case No. 99 C 30. In May, 1999, three
plaintiffs, Quinque Operating Company, Tom Boles and Robert Ditto, filed a
purported nationwide class action in the Stevens County, Kansas District Court
against some 250 natural gas pipelines and many of their affiliates. The
District Court is located in Hugoton, Kansas. Certain entities we acquired in
the Kinder Morgan Tejas acquisition are also defendants in this matter. The
Petition (recently amended) alleges a conspiracy to underpay royalties, taxes
and producer payments by the defendants' undermeasurement of the volume and
heating content of natural gas produced from nonfederal lands for more than
twenty-five years. The named plaintiffs purport to adequately represent the
interests of unnamed plaintiffs in this action who are comprised of the nation's
gas producers, state taxing agencies and royalty, working and overriding owners.
The plaintiffs seek compensatory damages, along with statutory penalties, treble
damages, interest, costs and fees from the defendants, jointly and severally.
This action was originally filed on May 28, 1999 in Kansas State Court in
Stevens County, Kansas as a class action against approximately 245 pipeline
companies and their affiliates, including certain Kinder Morgan entities.
Subsequently, one of the defendants removed the action to Kansas Federal
District Court and the case was styled as Quinque Operating Company, et al. v.
Gas Pipelines, et al., Case No. 99-1390-CM, United States District Court for the
District of Kansas. Thereafter, we filed a motion with the Judicial Panel for
Multidistrict Litigation to consolidate this action for pretrial purposes with
the Grynberg False Claim Act cases referred to below, because of common factual
questions. On April 10, 2000, the MDL Panel ordered that this case be
consolidated with the Grynberg federal False Claims Act cases discussed below.
On January 12, 2001, the Federal District Court of Wyoming issued an oral ruling
remanding the case back to the State Court in Stevens County, Kansas. The Court
in Kansas has issued a case management order addressing the initial phasing of
the case. In this initial phase, the court will rule on motions to dismiss
(jurisdiction and sufficiency of pleadings), and if the action is not dismissed,
on class certification. Merits discovery has been stayed. The defendants filed a
motion to dismiss on grounds other than personal jurisdiction, which was denied
by the Court in August, 2002. The Motion to Dismiss for lack of Personal
Jurisdiction of the nonresident defendants has been briefed and is pending. The
current named plaintiffs are Will Price, Tom Boles, Cooper Clark Foundation and
Stixon Petroleum, Inc. Quinque Operating Company has been dropped from the
action as a named plaintiff. On April 10, 2003, the court issued its decision
denying plaintiffs' motion for class certification. On July 8, 2003, a hearing
was held on the motion to amend the complaint. On July 28, 2003, the Court
granted leave to amend the complaint. The amended complaint does not list us or
any of our affiliates as defendants. Additionally, a new complaint was filed and
that complaint does not list us or any of our affiliates as defendants. We will
continue to monitor these matters.

   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
Claim 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

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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. Discovery is
now underway to determine issues related to the Court's subject matter
jurisdiction, arising out of the False Claims Act. On May 7, 2003, Grynberg
sought leave to file a Third Amended Complaint, which adds allegations of
undermeasurement related to CO2 production. Defendants have filed briefs
opposing leave 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 have 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.

   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. We believe this suit
is without merit and we intend to defend the case vigorously.

   Maher et ux. v. Centerpoint Energy, Inc. d/b/a Reliant Energy, Incorporated,
Reliant Energy Resources Corp., Entex Gas Marketing Company, Kinder Morgan Texas
Pipeline, L.P., Kinder Morgan Energy Partners, L.P., Houston Pipeline Company,
L.P. and AEP Gas Marketing, L.L.C., 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

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Pipeline GP, Inc., Tejas Gas, LLC and HPL GP, LLC. The First Amended Complaint
purports to bring a class action on behalf of those Texas residents who
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, inter alia, 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 First Amended Complaint. The
parties are currently engaged in preliminary discovery. 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 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 have filed a Notice of Appeal to the
United States Court of Appeals for the 9th Circuit, which appeal is currently
pending.

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   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 October 4, 2003,
plaintiffs' counsel agreed in writing to dismiss the Galaz II matter, but has
since withdrawn his agreement without explanation. The Kinder Morgan defendants'
Motion to Dismiss and Motion for Sanctions are currently pending.

   Also on June 20, 2003, the plaintiffs in the Galaz matters 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, 2003, which Motion
is currently pending.

   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.

   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

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were served with the Complaint on January 10, 2004, and are planning to file a
Motion to Dismiss on February 26, 2004.

   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 the Snyder matter,
the three Galaz matters, the Jernee matter and the Sands matter are without
merit and intend to defend against them vigorously.

   Marion County, Mississippi Litigation

   In 1968, Plantation 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.

   A settlement has been reached between most of the plaintiffs and Plantation.
It is anticipated that all of the proceedings to complete the settlement will be
completed by the end of the first quarter of 2004. 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 are currently involved in
discovery.

   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

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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 November 1987 through March 1997 in the amount of $30.7 million. On May
2, 2003, Plaintiff added claims for the period 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, 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 parties have completed
discovery and the matter is scheduled for trial on April 26, 2004. Based on the
information available to date in our investigation, the Kinder Morgan Defendants
believe that the claims against them are without merit and intend to defend
against them vigorously.

   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.

   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, 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
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 one cleanup ordered by the United States Environmental Protection Agency
     related to ground water contamination in the vicinity of SFPP's storage
     facilities and truck loading terminal at Sparks, Nevada;

   o several ground water hydrocarbon remediation efforts under administrative
     orders issued by the California Regional Water Quality Control Board and
     two other state agencies;

   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; and

   o a ground water remediation effort taking place between Chevron, Plantation
     Pipe Line Company and the Alabama Department of Environmental Management.

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   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 indicates possible
environmental impacts from petroleum releases into the soil and groundwater at
six sites. Further delineation and remediation of any environmental impacts from
these matters will be conducted. Reserves have been established to address the
closure of these issues.

   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. As of December 31, 2003, we have recorded a total reserve for
environmental claims in the amount of $39.6 million. However, we were not able
to reasonably estimate when the eventual settlements of these claims will occur.

   Other

   We are a defendant in various lawsuits arising from the day-to-day operations
of our businesses. Although no assurance can be given, we believe, based on our
experiences to date, that the ultimate resolution of such items will not have a
material adverse impact on our business, financial position, results of
operations or cash flows.

17.  New Accounting Pronouncements

   FIN 46 (revised December 2003)

   In December 2003, the Financial Accounting Standards Board issued
Interpretation (FIN) No. 46 (revised December 2003), "Consolidation of Variable
Interest Entities." This interpretation of Accounting Research Bulletin No. 51,
"Consolidated Financial Statements", addresses consolidation by business
enterprises of variable interest entities, which have one or more of the
following characteristics:

   o the equity investment at risk is not sufficient to permit the entity to
     finance its activities without additional subordinated financial support
     provided by any parties, including the equity holders;

   o the equity investors lack one or more of the following essential
     characteristics of a controlling financial interest:

     o the direct or indirect ability to make decisions about the entity's
       activities thorough voting rights or similar rights;

     o the obligation to absorb the expected losses of the entity; and

     o the right to receive the expected residual returns of the entity; and

   o the equity investors have voting rights that are not proportionate to their
     economic interests, and the activities of the entity involve or are
     conducted on behalf of an investor with a disproportionately small voting
     interest.

   The objective of this Interpretation is not to restrict the use of variable
interest entities but to improve financial reporting by enterprises involved
with variable interest entities. The FASB believe that if a business enterprise
has a controlling financial interest in a variable interest entity, the assets,
liabilities, and results of the activities of the variable interest entity
should be included in consolidated financial statements with those of the
business enterprise.

   This Interpretation explains how to identify variable interest entities and
how an enterprise assesses its interests in a variable interest entity to decide
whether to consolidate that entity. It requires existing unconsolidated variable
interest entities to be consolidated by their primary beneficiaries if the
entities do not effectively disperse risks

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among parties involved. Variable interest entities that effectively disperse
risks will not be consolidated unless a single party holds an interest or
combination of interests that effectively recombines risks that were previously
dispersed.

   An enterprise that consolidates a variable interest entity is the primary
beneficiary of the variable interest entity. The primary beneficiary of a
variable interest entity is the party that absorbs a majority of the entity's
expected losses, receives a majority of its expected residual returns, or both,
as a result of holding variable interests, which are the ownership, contractual,
or other monetary interests in an entity that change with changes in the fair
value of the entity's net assets excluding variable interests. The primary
beneficiary of a variable interest entity is required to disclose:

   o the nature, purpose, size and activities of the variable interest entity;

   o the carrying amount and classification of consolidated assets that are
     collateral for the variable interest entity's obligations; and

   o any lack of recourse by creditors (or beneficial interest holders) of a
     consolidated variable interest entity to the general credit of the primary
     beneficiary.

   In addition, an enterprise that holds significant variable interests in a
variable interest entity but is not the primary beneficiary is required to
disclose:

   o the nature, purpose, size and activities of the variable interest entity;

   o its exposure to loss as a result of the variable interest holder's
     involvement with the entity; and

   o the nature of its involvement with the entity and date when the involvement
     began

   Application of this Interpretation is required in financial statements of
public entities that have interests in variable interest entities or potential
variable interest entities commonly referred to as special-purpose entities for
periods ending after December 15, 2003. Application by public entities (other
than small business issuers) for all other types of entities is required in
financial statements for periods ending after March 15, 2004. We continue to
evaluate the effect from the adoption of this Statement on our consolidated
financial statements.

   SFAS No. 132 (revised 2003)

   In December 2003, the Financial Accounting Standards Board issued SFAS No.
132 (revised 2003), "Employers' Disclosures about Pensions and Other
Postretirement Benefits." The Statement revises and improves employers'
financial statement disclosures about defined benefit pension plans and other
postretirement benefit plans. The Statement does not change the measurement or
recognition of those plans and retains the disclosures required by the original
SFAS No. 132, which standardized the disclosure requirements for pensions and
other postretirement benefits to the extent practicable and required additional
information on changes in the benefit obligations and fair values of plans
assets.

   The revised Statement requires additional disclosures to those in the
original SFAS No. 132 about the assets, obligations, cash flows, and net
periodic benefit cost of defined benefit pension plans and other defined benefit
postretirement plans. The additional disclosures have been added in response to
concerns expressed by users of financial statements; those disclosures include
information describing the types of plan assets, investment strategy,
measurement date(s), plan obligations, cash flows, and components of net
periodic benefit cost recognized during annual and interim periods.

   Specifically, the additional requirements improve disclosures of relevant
accounting information by providing more information about the plan assets
available to finance benefit payments, the obligations to pay benefits, and an
entity's obligation to fund the plan, thus improving the information's
predictive value. Due to certain similarities between defined benefit pension
arrangements and arrangements for other postretirement benefits, the revised
Statement requires similar disclosures about postretirement benefits other than
pensions.

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   Some of the required disclosures include the following:

   o plan assets by category (i.e., debt, equity, real estate);
   o investment policies and strategies;

   o target allocation percentages or target ranges for plan asset categories;

   o projections of future benefit payments;

   o estimates of future contributions to fund pension and other postretirement
     benefit plans; and

   o interim disclosures of items such as (1) net periodic benefit cost
     recognized during the period, including service cost, interest cost,
     expected return on plan assets, prior service cost, and gain/loss due to
     settlement or curtailment and (2) employer contributions paid and expected
     to be paid, if significantly revised from the amounts previously disclosed.

   This revised statement is effective for financial statements with fiscal
years ending after December 15, 2003. The interim period disclosures required by
this Statement are effective for interim periods beginning after December 15,
2003. Disclosure of estimated future benefit payments required by portions of
this revised Statement is effective for fiscal years ending after June 15, 2004.
The disclosures for earlier annual periods presented for comparative purposes
should be restated for:

   o the percentages of each major category of plan assets held;

   o the accumulated benefit obligation; and

   o the assumptions used in the accounting for the plans.

   However, if obtaining this information relating to earlier periods in not
practicable, the notes to the financial statements should include all available
information and identify the information not available. We do not expect the
adoption of this Statement to have any immediate effect on our consolidated
financial statements.

   SFAS No. 149

   In April 2003, the Financial Accounting Standards Board issued SFAS No. 149,
"Amendment of Statement 133 on Derivative Instruments and Hedging Activities."
This Statement amends and clarifies accounting for derivative instruments,
including certain derivative instruments embedded in other contracts, and for
hedging activities under SFAS No. 133.

   The new guidance amends SFAS No. 133 for decisions made:

   o as part of the Derivatives Implementation Group process that effectively
     required amendments to SFAS No. 133;

   o in connection with other Board projects dealing with financial instruments;
     and

   o regarding implementation issues raised in relation to the application of
     the definition of a derivative, particularly regarding the meaning of an
     "underlying" and the characteristics of a derivative that contains
     financing components.

   The amendments set forth in SFAS No. 149 are intended to improve financial
reporting by requiring that contracts with comparable characteristics be
accounted for similarly. In particular, this Statement clarifies under what
circumstances a contract with an initial net investment meets the
characteristics of a derivative as discussed in SFAS No. 133. In addition, it
clarifies when a derivative contains a financing component that warrants special

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reporting in the statement of cash flows. SFAS No. 149 amends certain other
existing pronouncements. These changes are intended to result in more consistent
reporting of contracts that are derivatives in their entirety or that contain
embedded derivatives that warrant separate accounting.

   This Statement is effective for contracts entered into or modified after June
30, 2003, except as stated below and for hedging relationships designated after
June 30, 2003. We will apply this guidance prospectively. We do not expect the
adoption of this Statement to have any immediate effect on our consolidated
financial statements.

   We will continue to apply the provisions of this Statement that relate to
SFAS No. 133 Implementation Issues that have been effective for fiscal quarters
that began prior to June 15, 2003, in accordance with their respective effective
dates. In addition, certain provisions relating to forward purchases or sales of
"when-issued" securities or other securities that do not yet exist, will be
applied to existing contracts as well as new contracts entered into after June
30, 2003.

   SFAS No. 150

   In May 2003, the Financial Accounting Standards Board issued SFAS No. 150,
"Accounting for Certain Financial Instruments with Characteristics of both
Liabilities and Equity." This Statement establishes standards for how an issuer
classifies and measures certain financial instruments with characteristics of
both liabilities and equity. It requires that an issuer classify a financial
instrument that is within its scope as a liability (or an asset in some
circumstances). Many of those instruments were previously classified as equity.

   SFAS No. 150 requires an issuer to classify the following instruments as
liabilities (or assets in some circumstances):

   o a financial instrument issued in the form of shares that is mandatorily
     redeemable - that embodies an unconditional obligation requiring the issuer
     to redeem it by transferring its assets at a specified or determinable date
     (or dates) or upon an event that is certain to occur;

   o a financial instrument, other than an outstanding share, that, at
     inception, embodies an obligation to repurchase the issuer's equity shares,
     or is indexed to such an obligation, and that requires or may require the
     issuer to settle the obligation by transferring assets (for example, a
     forward purchase contract or written put option on the issuer's equity
     shares that is to be physically settled or net cash settled); and

   o a financial instrument that embodies an unconditional obligation, or a
     financial instrument other than an outstanding share that embodies a
     conditional obligation, that the issuer must or may settle by issuing a
     variable number of its equity shares, if, at inception, the monetary value
     of the obligation is based solely or predominantly on any of the following:

     o  a fixed monetary amount known at inception, for example, a payable
        settleable with a variable number of the issuer's equity shares;

     o  variations in something other than the fair value of the issuer's equity
        shares, for example, a financial instrument indexed to the Standard &
        Poor 500 and settleable with a variable number of the issuer's equity
        shares; or

     o  variations inversely related to changes in the fair value of the
        issuer's equity shares, for example, a written put option that could be
        net share settled.

   The requirements of this Statement apply to issuers' classification and
measurement of freestanding financial instruments, including those that comprise
more than one option or forward contract. This Statement does not apply to
features that are embedded in a financial instrument that is not a derivative in
its entirety. It also does not affect the classification or measurement of
convertible bonds, puttable stock, or other outstanding shares that are
conditionally redeemable. This Statement also does not address certain financial
instruments indexed partly to the issuer's equity shares and partly, but not
predominantly, to something else.

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   This Statement is effective for financial instruments entered into or
modified after May 31, 2003, and otherwise is effective at the beginning of the
first interim period beginning after June 15, 2003, except for mandatorily
redeemable financial instruments of nonpublic entities. It is to be implemented
by reporting the cumulative effect of a change in accounting principle for
financial instruments created before the issuance date of the Statement and
still existing at the beginning of the interim period of adoption. Restatement
is not permitted. We will apply this guidance prospectively. We do not expect
the adoption of this Statement to have any immediate effect on our consolidated
financial statements.

   SAB No. 104

   On December 17, 2003, the staff of the Securities and Exchange Commission
issued Staff Accounting Bulletin No. 104, "Revenue Recognition," which
supersedes SAB No. 101, "Revenue Recognition in Financial Statements." SAB No.
104's primary purpose is to rescind the accounting guidance contained in SAB No.
101 related to multiple-element revenue arrangements that was superseded as a
result of the issuance of Emerging Issues Task Force Issues No. 00-21,
"Accounting for Revenue Arrangements with Multiple Deliverables." Additionally,
SAB No. 104 rescinds the SEC's related "Revenue Recognition in Financial
Statements Frequently Asked Questions and Answers" issued with SAB No. 101 that
had been codified in SEC Topic 13, "Revenue Recognition." While the wording of
SAB No. 104 has changed to reflect the issuance of EITF No. 00-21, the revenue
recognition principles of SAB No. 101 remain largely unchanged by the issuance
of SAB No. 104, which was effective upon issuance. The adoption of SAB No. 104
did not have a material effect on our financial position or results of
operations.

   Other

   In October 2003, the FASB voted to begin in 2005 requiring companies to
charge stock option costs against earnings. The new standard would mandate
expensing stock option awards just like any other form of compensation. A final
rule is expected to be formally issued in the second half of 2004. Besides the
effective date of the new rule, the FASB also decided to require companies to
use one method for making a transition toward expensing options. The transition
method decided on calls for companies to expense all at once previously granted
options as well as options issued in the year companies make the accounting
switch. In the proposed standard, companies would have the option to restate
prior results to reflect option expense. A reason for restatement would be a
company's desire for a fair year-to-year earnings comparison. If a company
chooses not to restate, it would have to recognize the cost of previously issued
but unvested options in 2005. At the current time, the FASB has not decided on
specific disclosure requirements.

18.  Subsequent Events

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

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

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