<PAGE>

                                                                    EXHIBIT 99.1

                         INDEX TO FINANCIAL STATEMENTS

<Table>
<S>                                                           <C>
                                                              PAGE
                                                              ----
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
Report of Independent Accountants...........................   75
Consolidated Statements of Income for the years ended
  December 31, 2001, 2000, and 1999.........................   76
Consolidated Statements of Comprehensive Income for the
  years ended December 31, 2001, 2000, and 1999.............   77
Consolidated Balance Sheets for the years ended December 31,
  2001 and 2000.............................................   78
Consolidated Statements of Cash Flows for the years ended
  December 31, 2001, 2000, and 1999.........................   79
Consolidated Statements of Partners' Capital for the years
  ended December 31, 2001, 2000, and 1999...................   80
Notes to Consolidated Financial Statements..................
</Table>

                                        74
<PAGE>

                       REPORT OF INDEPENDENT ACCOUNTANTS

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, 2001 and 2000, and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 2001 in conformity with accounting principles generally accepted in the
United States of America. In addition, in our opinion, the financial statement
schedule appearing under Item 14(a)(2) on page 71 presents fairly, in all
material respects, the information set forth therein when read in conjunction
with the related consolidated financial statements. These financial statements
and financial statement schedule are the responsibility of the Partnership's
management; our responsibility is to express an opinion on these financial
statements and financial statement schedule 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 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
February 15, 2002

                                        75
<PAGE>

              KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

                       CONSOLIDATED STATEMENTS OF INCOME

<Table>
<Caption>
                                                                     YEAR ENDED DECEMBER 31,
                                                             ---------------------------------------
                                                                 2001          2000          1999
                                                             ------------   -----------   ----------
                                                             (IN THOUSANDS EXCEPT PER UNIT AMOUNTS)
<S>                                                          <C>            <C>           <C>
Revenues
  Natural gas sales........................................   $1,583,817     $  10,196     $     --
  Services.................................................      997,845       643,772      393,131
  Product sales and other..................................      365,014       162,474       35,618
                                                              ----------     ---------     --------
                                                               2,946,676       816,442      428,749
                                                              ----------     ---------     --------
Costs and Expenses
  Gas purchases and other costs of sales...................    1,657,689       124,641       16,241
  Operations and maintenance...............................      356,654       164,379       95,121
  Fuel and power...........................................       73,188        43,216       31,745
  Depreciation and amortization............................      142,077        82,630       46,469
  General and administrative...............................       99,009        60,065       35,612
  Taxes, other than income taxes...........................       54,231        25,950       16,154
                                                              ----------     ---------     --------
                                                               2,382,848       500,881      241,342
                                                              ----------     ---------     --------
Operating Income...........................................      563,828       315,561      187,407
Other Income (Expense)
  Earnings from equity investments.........................       84,834        71,603       42,918
  Amortization of excess cost of equity investments........       (9,011)       (8,195)      (4,254)
  Interest, net............................................     (171,457)      (93,284)     (52,605)
  Other, net...............................................        1,962        14,584       14,085
  Gain on sale of equity interest, net of special
     charges...............................................           --            --       10,063
Minority Interest..........................................      (11,440)       (7,987)      (2,891)
                                                              ----------     ---------     --------
Income Before Income Taxes and Extraordinary Charge........      458,716       292,282      194,723
Income Taxes...............................................       16,373        13,934        9,826
                                                              ----------     ---------     --------
Income Before Extraordinary Charge.........................      442,343       278,348      184,897
Extraordinary Charge on Early Extinguishment of Debt.......           --            --       (2,595)
                                                              ----------     ---------     --------
Net Income.................................................   $  442,343     $ 278,348     $182,302
                                                              ==========     =========     ========
Calculation of Limited Partners' Interest in Net Income:
Income Before Extraordinary Charge.........................   $  442,343     $ 278,348     $184,897
Less: General Partner's interest in Net Income.............     (202,095)     (109,470)     (56,273)
                                                              ----------     ---------     --------
Limited Partners' net Income before Extraordinary Charge...      240,248       168,878      128,624
Less: Extraordinary Charge on Early Extinguishment of
  Debt.....................................................           --            --       (2,595)
                                                              ----------     ---------     --------
Limited Partners' Net Income...............................   $  240,248     $ 168,878     $126,029
                                                              ==========     =========     ========
Basic Limited Partners' Net Income per Unit:
Income before Extraordinary Charge.........................   $     1.56     $    1.34     $   1.31
Extraordinary Charge.......................................           --            --         (.02)
                                                              ----------     ---------     --------
Net Income.................................................   $     1.56     $    1.34     $   1.29
                                                              ==========     =========     ========
Weighted Average Units Outstanding.........................      153,901       126,212       97,948
                                                              ==========     =========     ========
Diluted Limited Partners' Net Income per Unit:
Income before Extraordinary Charge.........................   $     1.56     $    1.34     $   1.31
Extraordinary Charge.......................................           --            --         (.02)
                                                              ----------     ---------     --------
Net Income.................................................   $     1.56     $    1.34     $   1.29
                                                              ==========     =========     ========
Weighted Average Units Outstanding.........................      154,110       126,300       97,986
                                                              ==========     =========     ========
</Table>

  The accompanying notes are an integral part of these consolidated financial
                                  statements.
                                        76
<PAGE>

              KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

                CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

<Table>
<Caption>
                                                                 YEAR ENDED DECEMBER 31,
                                                              ------------------------------
                                                                2001       2000       1999
                                                              --------   --------   --------
                                                                      (IN THOUSANDS)
<S>                                                           <C>        <C>        <C>
Revenues
  Net Income................................................  $442,343   $278,348   $182,302
  Cumulative effect transition adjustment...................   (22,797)        --         --
  Change in fair value of derivatives used for hedging
     purposes...............................................    35,162         --         --
  Reclassification of change in fair value of derivatives to
     net income.............................................    51,461         --         --
                                                              --------   --------   --------
  Comprehensive Income......................................  $506,169   $278,348   $182,302
                                                              ========   ========   ========
</Table>

  The accompanying notes are an integral part of these consolidated financial
                                  statements.
                                        77
<PAGE>

              KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

                          CONSOLIDATED BALANCE SHEETS

<Table>
<Caption>
                                                                   DECEMBER 31,
                                                              -----------------------
                                                                 2001         2000
                                                              ----------   ----------
                                                                  (IN THOUSANDS)
<S>                                                           <C>          <C>
                                       ASSETS

Current Assets
  Cash and cash equivalents.................................  $   62,802   $   59,319
  Accounts and notes receivable
     Trade..................................................     215,860      345,065
     Related parties........................................      52,607        3,384
  Inventories
     Products...............................................       2,197       24,137
     Materials and supplies.................................       6,212        4,972
  Gas imbalances............................................      15,265       26,878
  Gas in underground storage................................      18,214       27,481
  Other current assets......................................     194,886       20,025
                                                              ----------   ----------
                                                                 568,043      511,261
                                                              ----------   ----------
Property, Plant and Equipment, net..........................   5,082,612    3,306,305
Investments.................................................     440,518      417,045
Notes receivable............................................       3,095        9,101
Intangibles, net............................................     563,397      345,305
Deferred charges and other assets...........................      75,001       36,193
                                                              ----------   ----------
TOTAL ASSETS................................................  $6,732,666   $4,625,210
                                                              ==========   ==========

                          LIABILITIES AND PARTNERS' CAPITAL
Current Liabilities
  Accounts payable
     Trade..................................................  $  111,853   $  293,268
     Related parties........................................       9,235        8,255
  Current portion of long-term debt.........................     560,219      648,949
  Accrued interest..........................................      34,099       18,592
  Deferred revenues.........................................       2,786       43,978
  Gas imbalances............................................      34,660       48,834
  Accrued other liabilities.................................     209,852       37,080
                                                              ----------   ----------
                                                                 962,704    1,098,956
                                                              ----------   ----------
Long-Term Liabilities and Deferred Credits
  Long-term debt............................................   2,231,574    1,255,453
  Deferred revenues.........................................      29,110        1,503
  Deferred income taxes.....................................      38,544        2,487
  Other.....................................................     246,464       91,575
                                                              ----------   ----------
                                                               2,545,692    1,351,018
                                                              ----------   ----------
Commitments and Contingencies (Notes 13 and 16)
Minority Interest...........................................      65,236       58,169
                                                              ----------   ----------
Partners' Capital
  Common Units (129,855,018 and 129,716,218 units issued and
     outstanding at December 31, 2001 and 2000,
     respectively)..........................................   1,894,677    1,957,357
  Class B Units (5,313,400 and 5,313,400 units issued and
     outstanding at December 31, 2001 and 2000,
     respectively)..........................................     125,750      125,961
  i-Units (30,636,363 and 0 units issued and outstanding at
     December 31, 2001 and 2000, respectively)..............   1,020,153           --
  General Partner...........................................      54,628       33,749
  Accumulated other comprehensive income....................      63,826           --
                                                              ----------   ----------
                                                               3,159,034    2,117,067
                                                              ----------   ----------
TOTAL LIABILITIES AND PARTNERS' CAPITAL.....................  $6,732,666   $4,625,210
                                                              ==========   ==========
</Table>

  The accompanying notes are an integral part of these consolidated financial
                                  statements.
                                        78
<PAGE>

              KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

                     CONSOLIDATED STATEMENTS OF CASH FLOWS

<Table>
<Caption>
                                                                     YEAR ENDED DECEMBER 31,
                                                              -------------------------------------
                                                                 2001          2000         1999
                                                              -----------   -----------   ---------
                                                                     (DOLLARS IN THOUSANDS)
<S>                                                           <C>           <C>           <C>
Cash Flows From Operating Activities
Net income..................................................  $   442,343   $   278,348   $ 182,302
Adjustments to reconcile net income to net cash provided by
  operating activities:
  Extraordinary charge on early extinguishment of debt......           --            --       2,595
  Depreciation and amortization.............................      142,077        82,630      46,469
  Amortization of excess cost of equity investments.........        9,011         8,195       4,254
  Earnings from equity investments..........................      (84,834)      (71,603)    (42,918)
  Distributions from equity investments.....................       68,832        47,512      33,686
  Gain on sale of equity interest, net of special charges...           --            --     (10,063)
  Changes in components of working capital:
    Accounts receivable.....................................      174,098         6,791     (12,358)
    Other current assets....................................       22,033        (6,872)         --
    Inventories.............................................       22,535        (1,376)     (2,817)
    Accounts payable........................................     (183,179)       (8,374)     (9,515)
    Accrued liabilities.....................................      (47,692)       26,479      11,106
    Accrued taxes...........................................        8,679        (1,302)        497
  Rate refunds settlement...................................         (100)      (52,467)         --
  Other, net................................................        7,358        (6,394)    (20,382)
                                                              -----------   -----------   ---------
Net Cash Provided by Operating Activities...................      581,161       301,567     182,856
                                                              -----------   -----------   ---------
Cash Flows From Investing Activities
  Acquisitions of assets....................................   (1,523,454)   (1,008,648)      5,678
  Additions to property, plant and equipment for expansion
    and maintenance projects................................     (295,088)     (125,523)    (82,725)
  Sale of investments, property, plant and equipment, net of
    removal costs...........................................        9,043        13,412      43,084
  Acquisitions of investments...............................           --       (79,388)   (161,763)
  Other.....................................................       (9,394)        2,581        (800)
                                                              -----------   -----------   ---------
Net Cash Used in Investing Activities.......................   (1,818,893)   (1,197,566)   (196,526)
                                                              -----------   -----------   ---------
Cash Flows From Financing Activities
  Issuance of debt..........................................    4,053,734     2,928,304     550,287
  Payment of debt...........................................   (3,324,161)   (1,894,904)   (333,971)
  Loans to related party....................................      (17,100)           --          --
  Debt issue costs..........................................       (8,008)       (4,298)     (3,569)
  Proceeds from issuance of common units....................        4,113       171,433          68
  Proceeds from issuance of i-units.........................      996,869            --          --
  Contributions from General Partner........................       11,716         7,434         146
  Distributions to partners
    Common units............................................     (268,644)     (194,691)   (135,835)
    Class B units...........................................       (8,501)           --          --
    General Partner.........................................     (181,198)      (91,366)    (52,674)
    Minority interest.......................................      (14,827)       (7,533)     (2,316)
  Other, net................................................       (2,778)          887        (149)
                                                              -----------   -----------   ---------
Net Cash Provided by Financing Activities...................    1,241,215       915,266      21,987
                                                              -----------   -----------   ---------
Increase in Cash and Cash Equivalents.......................        3,483        19,267       8,317
Cash and Cash Equivalents, beginning of period..............       59,319        40,052      31,735
                                                              -----------   -----------   ---------
Cash and Cash Equivalents, end of period....................  $    62,802   $    59,319   $  40,052
                                                              ===========   ===========   =========
Noncash Investing and Financing Activities:
  Contribution of net assets to partnership investments.....  $        --   $        --   $      20
  Assets acquired by the issuance of units..................           --       179,623     420,850
  Assets acquired by the assumption of liabilities..........      293,871       333,301     111,509
Supplemental disclosures of cash flow information:
  Cash paid during the year for
  Interest (net of capitalized interest)....................      165,357        88,821      48,222
  Income taxes..............................................        2,168         1,806         529
</Table>

  The accompanying notes are an integral part of these consolidated financial
                                  statements.
                                        79
<PAGE>

              KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

                  CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL

<Table>
<Caption>
                                                   2001                       2000                       1999
                                         ------------------------   ------------------------   ------------------------
                                            UNITS        AMOUNT        UNITS        AMOUNT        UNITS        AMOUNT
                                         -----------   ----------   -----------   ----------   -----------   ----------
                                                                     (DOLLARS IN THOUSANDS)
<S>                                      <C>           <C>          <C>           <C>          <C>           <C>
Common Units:
  Beginning Balance....................  129,716,218   $1,957,357   118,274,274   $1,759,142    97,643,380   $1,348,591
  Net income...........................           --      203,559            --      168,878            --      126,029
  Units issued as consideration in the
    acquisition of assets or
    businesses.........................           --           --     2,428,344       53,050    20,640,294      420,610
  Units issued for cash................      138,800        2,405     9,013,600      170,978         4,000           68
  Distributions........................           --     (268,644)           --     (194,691)           --     (135,835)
  Repurchases..........................           --           --            --           --       (13,400)        (321)
                                         -----------   ----------   -----------   ----------   -----------   ----------
  Ending Balance.......................  129,855,018    1,894,677   129,716,218    1,957,357   118,274,274    1,759,142
Class B Units:
  Beginning Balance....................    5,313,400      125,961            --           --            --           --
  Net income...........................           --        8,335            --           --            --           --
  Units issued as consideration in the
    acquisition of assets or
    businesses.........................           --           --     5,313,400      125,961            --           --
  Units issued for cash................           --          (44)           --           --            --           --
  Distributions........................           --       (8,502)           --           --            --           --
                                         -----------   ----------   -----------   ----------   -----------   ----------
  Ending Balance.......................    5,313,400      125,750     5,313,400      125,961            --           --
i-Units:
  Beginning Balance....................           --           --            --           --            --           --
  Net income...........................           --       28,354            --           --            --           --
  Units issued for cash................   29,750,000      991,799
  Distributions........................      886,363           --            --           --            --           --
  Repurchases..........................           --           --            --           --            --           --
                                         -----------   ----------   -----------   ----------   -----------   ----------
  Ending Balance.......................   30,636,363    1,020,153            --           --            --           --
General Partner:
  Beginning Balance....................           --       33,749            --       15,656            --       12,072
  Net income...........................           --      202,095            --      109,470            --       56,273
  Units issued as consideration in the
    acquisition of assets or
    businesses.........................           --           --            --          (11)           --          (15)
  Units issued for cash................           --          (18)           --           --            --
  Distributions........................           --     (181,198)           --      (91,366)           --      (52,674)
  Repurchases..........................           --           --            --           --            --           --
                                         -----------   ----------   -----------   ----------   -----------   ----------
  Ending Balance.......................           --       54,628            --       33,749            --       15,656
Accumulated other comprehensive income:
  Beginning Balance....................           --           --            --           --            --           --
  Cumulative effect transition adj. ...           --      (22,797)           --           --            --           --
  Change in fair value of derivatives
    used for hedging purposes..........           --       35,162            --           --            --           --
  Reclassification of change in fair
    value of derivatives to net
    income.............................           --       51,461            --           --            --           --
                                         -----------   ----------   -----------   ----------   -----------   ----------
  Ending Balance.......................           --       63,826            --           --            --           --
Total Partners' Capital................           --   $3,159,034            --   $2,117,067            --   $1,774,798
                                         ===========   ==========   ===========   ==========   ===========   ==========
</Table>

  The accompanying notes are an integral part of these consolidated financial
                                  statements.
                                        80
<PAGE>

1.  ORGANIZATION

  GENERAL

     Kinder Morgan Energy Partners, L.P., the "Partnership", is a Delaware
limited partnership formed in August 1992. We are a publicly traded limited
partnership managing a diversified portfolio of midstream energy assets. We
provide services to our customers and increase value for our unitholders
primarily through the following activities:

     - transporting, storing and processing refined petroleum products;

     - transporting, storing and selling natural gas;

     - transporting carbon dioxide for use in enhanced oil recovery operations;
       and

     - 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 low-cost capital available in 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:

     - Products Pipelines;

     - Natural Gas Pipelines;

     - CO(2) Pipelines; and

     - Terminals.

     On July 18, 2001, we announced a change in the organization of our business
segments, effective in the third quarter of 2001. Prior to the third quarter of
2001, we reported Bulk Terminals and Liquids Terminals as separate business
segments. As a result of combining our Bulk Terminals and Liquids Terminals
businesses under one management team beginning with the third quarter of 2001,
we are reporting the combined Bulk Terminals and Liquids Terminals segments as
our Terminals segment. Prior period segment results have been restated to
conform to our current organization. For more information on our reportable
business segments, see Note 15.

  MERGER OF KMI

     On October 7, 1999, K N Energy, Inc., a Kansas corporation that provided
integrated energy services including the gathering, processing, transportation
and storage of natural gas, the marketing of natural gas and natural gas liquids
and the generation of electric power, acquired Kinder Morgan (Delaware), Inc., a
Delaware corporation. Kinder Morgan (Delaware), Inc. is the sole stockholder of
our general partner, Kinder Morgan G.P., Inc. At the time of the closing of the
acquisition, K N Energy, Inc. changed its name to Kinder Morgan, Inc. It 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 midstream energy companies in
the United States, operating, either for themselves or on behalf of us, more
than 30,000 miles of natural gas and products pipelines in 26 states. KMI also
has significant retail natural gas distribution and electric generation
operations. KMI, through its subsidiary Kinder Morgan (Delaware), Inc., is the
sole stockholder of our general partner. At December 31, 2001, KMI and its
consolidated subsidiaries owned approximately 18.7% of our outstanding limited
partner units.

  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.

                                        81
<PAGE>

     In May 2001, KMR issued 2,975,000 of its shares representing limited
liability company interests to KMI and 26,775,000 of its shares to the public in
an initial public offering. KMR's shares were initially issued at a price of
$35.21 per share, less commissions and underwriting expenses, and the shares
trade on the New York Stock Exchange under the symbol "KMR". Substantially all
of the net proceeds from the offering were used to buy i-units from us. The
i-units are a new and separate class of limited partner interests in us and are
issued only to KMR.

     When it purchased i-units from us, KMR became a limited partner in us and,
pursuant to a delegation of control agreement, manages and controls our business
and affairs. Under the delegation of control agreement, our general partner
delegated to KMR, to the fullest extent permitted under Delaware law and our
partnership agreement, all of its power and authority to manage and control our
business and affairs, except that it cannot take certain specified actions
without the approval of our general partner. In accordance with its limited
liability company agreement, KMR's activities will be restricted to being a
limited partner in, and managing and controlling the business and affairs of the
Partnership, including our operating partnerships and our subsidiaries. See Note
11 for more information.

  TWO-FOR-ONE COMMON UNIT SPLIT

     On July 18, 2001, KMR, the delegate of our general partner, approved a
two-for-one unit 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 on 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 the split for all periods presented.

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.

  CRITICAL ACCOUNTING POLICIES AND ESTIMATES

     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, 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.

     The preparation of our financial statements in conformity with generally
accepted accounting principles requires our management to make estimates and
assumptions that affect:

     - the amounts we report for assets and liabilities;

     - our disclosure of contingent assets and liabilities at the date of the
       financial statements; and

     - the amounts we report for revenues and expenses during the reporting
       period.

     Therefore, the reported amounts of our assets and liabilities, revenues and
expenses 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
                                        82
<PAGE>

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, 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. With respect to our environmental exposure, we
utilize both internal staff and external experts to assist us in identifying
environmental issues and in estimating the costs and timing of remediation
efforts. Often, as the remediation evaluation and effort progresses, additional
information is obtained, requiring revisions to estimated costs. These revisions
are reflected in our income in the period in which they are reasonably
determinable. Finally, we are subject to litigation 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 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.

 CASH EQUIVALENTS

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

  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 compute
depreciation using the straight-line method based on estimated economic lives.
Generally, we apply composite depreciation rates to functional groups of
property having similar economic characteristics. The rates range from 2.0% to
12.5%, excluding certain short-lived assets such as vehicles. Depreciation,
depletion and amortization of the capitalized costs of producing carbon dioxide
properties, both tangible and intangible, are provided for on a
units-of-production basis. 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 basis for
units-of-production rate determination is by field. 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 evaluate impairment of our long-lived assets in accordance with
Statement of Financial Accounting Standards No. 121 "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of." 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.

     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. The Financial
Accounting Standards Board has issued a proposed Statement of Position entitled
"Accounting for Certain Costs and Activities Related to Property, Plant and
Equipment". For purposes of the SOP, a project stage or timeline frame works is
used and property, plant and equipment

                                        83
<PAGE>

assets are to be accounted for at a component level. Costs incurred for
property, plant and equipment are to be classified into four stages:

     - preliminary;

     - preacquisition;

     - acquisition-or-construction; and

     - in-service.

     Furthermore, a component is a tangible part or portion of property, plant
and equipment that:

     - can be separately identified as an asset and depreciate or amortized over
       its own expected use life; and

     - is expected to provide economic benefit for more than one year.

     If a component has an expected useful life that differs from the expected
useful life of the property, plant and equipment asset to which it relates, the
cost should be accounted for separately and depreciated or amortized over its
expected useful life. We are currently evaluating the effects of this proposed
SOP.

     On January 1, 2002, we adopted SFAS No. 144, "Accounting for the Impairment
or Disposal of Long-Lived Assets." This statement retains the requirements of
SFAS 121, mentioned above, 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 it. 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.

  NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

     In July 2001, the Financial Accounting Standards Board issued SFAS No. 143,
"Accounting for Asset Retirement Obligations". This statement requires companies
to record a liability relating to the retirement and removal of assets used in
their business. The liability is discounted to its present value, and the
relative asset value is increased by the same amount. Over the life of the
asset, the liability will be accreted to its future value and eventually
extinguished when the asset is taken out of service. The provisions of this
statement are effective for fiscal years beginning after June 15, 2002. We do
not expect that SFAS No. 143 will have a material impact on our business,
financial position or results of operations.

  EQUITY METHOD OF ACCOUNTING

     We account for investments in greater than 20% owned 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.

  EXCESS OF COST OVER FAIR VALUE

     As of December 31, 2001, we amortized the excess cost over our underlying
net asset book value in 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. 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 investments in 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,
we reported amortization of excess cost on investments as amortization of excess
cost of equity investments in our accompanying consolidated statements of
income. Our total unamortized excess cost over fair value of net assets on
investments in consolidated affiliates was approximately $546.7 million as of
December 31, 2001 and $158.1 million as of December 31, 2000. These amounts are
included within intangibles on our accompanying consolidated
                                        84
<PAGE>

balance sheet. Our total unamortized excess cost over underlying book value of
net assets on investments accounted for under the equity method was
approximately $341.2 million as of December 31, 2001 and $350.2 million as of
December 31, 2000. These amounts are included within equity investments on our
accompanying balance sheet.

     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. At December 31, 2001, we believed no such impairment had
occurred and no reduction in estimated useful lives was warranted. On January 1,
2002, we adopted SFAS No. 141 "Business Combinations".

     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 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. 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. After July 1, 2001, we completed four acquisitions and
have initiated or announced four additional acquisitions. Refer to Note 3 for
more detail about our acquisitions.

     SFAS No. 142 "Goodwill and Other Intangible Assets" supercedes Accounting
Principles Board Opinion No. 17 and requires that goodwill no longer be
amortized but 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 will be
tested for impairment annually. SFAS No. 142 applies to any goodwill acquired in
a business combination completed after June 30, 2001. Other intangible assets
are to be amortized over their useful life and reviewed for impairment in
accordance with the provisions of SFAS No. 121,"Accounting for the Impairment of
Long-Lived Assets and Long-Lived Assets to be Disposed Of". An intangible asset
with an indefinite useful life can no longer be amortized until its useful life
becomes determinable. 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. After June 30, 2001, we completed two acquisitions, our Boswell and
Stolt-Nielsen acquisitions, which resulted in the recognition of goodwill. We
adopted SFAS No. 142 on January 1, 2002, and we expect that SFAS No. 142 will
not have a material impact on our business, financial position or results of
operations. With the adoption of SFAS No. 142, goodwill of approximately $546.7
million is no longer subject to amortization over its estimated useful life. For
more information on our acquisitions, see Note 3.

  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 liquid terminal tank rental revenue ratably over the contract period.
We recognize liquid terminal through-put revenue based on volumes received or
volumes delivered depending on the customer contract. Liquid 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.

                                        85
<PAGE>

  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, and which do not contribute to current or
future revenue generation. We do not discount liabilities to net present value
and we record environmental liabilities when environmental assessments and/or
remedial efforts are probable and we can reasonably estimate the costs.
Generally, our making of these accruals coincides with our completion of a
feasibility study or our commitment to a formal plan of action.

  MINORITY INTEREST

     Minority interest consists of the following:

     - the 1.0101% general partner interest in our operating partnerships;

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

     - the 33 1/3% interest in Trailblazer Pipeline Company;

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

     - the approximate 32% interest in MidTex Gas Storage Company, L.L.P., a
       Texas limited liability partnership owned approximately 68% and
       controlled by Kinder Morgan Texas Pipeline 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 of our 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 the year ended December 31, 2001, the only difference
between net income and comprehensive income for us was the unrealized gain or
loss on derivatives utilized for hedging purposes. There was no difference
between net income and comprehensive income for each of the years ended December
31, 2000 and 1999. For more information on our hedging activities, see Note 14.

  NET INCOME PER UNIT

     We compute Basic Limited Partners' Net Income per Unit by dividing limited
partner's 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.

                                        86
<PAGE>

  RISK MANAGEMENT ACTIVITIES

     We utilize energy derivatives for the purpose of mitigating our risk
resulting from fluctuations in the market price of natural gas, natural gas
liquids, crude oil and carbon dioxide. In addition, we enter into interest rate
swap agreements for the purpose of hedging the interest rate risk associated
with our fixed rate debt obligations. Prior to December 31, 2000, our accounting
policy for these activities was based on a number of authoritative
pronouncements including SFAS No. 80 "Accounting for Futures Contracts". Our new
policy, which is based on SFAS No. 133 "Accounting for Derivative Instruments
and Hedging Activities", became effective on January 1, 2001. See Note 14 for
more information on our risk management activities.

3.  ACQUISITIONS AND JOINT VENTURES

     During 1999, 2000 and 2001, we completed 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 amounts
assigned to assets and liabilities may be adjusted during a short period
following the acquisition. The results of operations from these acquisitions are
included in the consolidated financial statements from the date of acquisition.

  Plantation Pipe Line Company

     On June 16, 1999, we acquired an additional approximate 27% interest in
Plantation Pipe Line Company for approximately $124.2 million. Collectively, we
now own approximately 51% of Plantation Pipe Line Company, and ExxonMobil
Pipeline Company, an affiliate of ExxonMobil Corporation, owns approximately
49%. Plantation Pipe Line Company owns and operates a 3,100-mile pipeline system
throughout the southeastern United States. The pipeline is a common carrier of
refined petroleum products to various metropolitan areas, including Atlanta,
Georgia; Charlotte, North Carolina; and the Washington, D.C. area. We do not
control Plantation Pipe Line Company, and therefore, we account for our
investment in Plantation under the equity method of accounting.

     Our purchase price and the allocation to assets acquired and liabilities
assumed was as follows (in thousands):

<Table>
<S>                                                            <C>
Purchase price:
  Cash paid, including transaction costs....................   $124,163
                                                               --------
  Total purchase price......................................   $124,163
                                                               ========
Allocation of purchase price:
  Equity investments........................................   $124,163
                                                               --------
                                                               $124,163
                                                               ========
</Table>

  Transmix Operations

     On September 10, 1999, we acquired transmix processing plants in Richmond,
Virginia and Dorsey Junction, Maryland and other related assets from Primary
Corporation. As consideration for the purchase, we paid Primary approximately
$16 million in cash and 1,020,294 common units valued at approximately $14.3
million. In addition, we assumed approximately $5.8 million of liabilities.

                                        87
<PAGE>

     Our purchase price and the allocation to assets acquired and liabilities
assumed was as follows (in thousands):

<Table>
<S>                                                            <C>
Purchase price:
  Common units issued.......................................   $14,348
  Cash paid, including transaction costs....................    15,957
  Liabilities assumed.......................................     5,792
                                                               -------
  Total purchase price......................................   $36,097
                                                               =======
Allocation of purchase price:
  Current assets............................................   $ 4,854
  Property, plant and equipment.............................    31,240
  Deferred charges and other assets.........................         3
                                                               -------
                                                               $36,097
                                                               =======
</Table>

  Trailblazer Pipeline Company

     Effective November 30, 1999, we acquired a 33 1/3% interest in Trailblazer
Pipeline Company for $37.6 million from Columbia Gulf Transmission Company, an
affiliate of Columbia Energy Group. Trailblazer Pipeline Company is an Illinois
partnership that owns and operates a 436-mile natural gas pipeline system that
traverses from Colorado through southeastern Wyoming to Beatrice, Nebraska.
Trailblazer Pipeline Company has a certificated capacity of 492 million cubic
feet per day of natural gas. For the month of December 1999, we accounted for
our 33 1/3% interest in Trailblazer Pipeline Company under the equity method of
accounting. Effective December 31, 1999, following our acquisition of an
additional 33 1/3% interest in Trailblazer Pipeline Company, which is discussed
below, we included Trailblazer Pipeline Company's activities as part of our
consolidated financial statements.

     On December 12, 2001, we announced that we had signed a definitive
agreement to acquire the remaining 33 1/3% ownership interest in Trailblazer
Pipeline Company from Enron Trailblazer Pipeline Company for $68 million in
cash. Following the acquisition, we will own 100% of Trailblazer Pipeline
Company. The transaction, which is expected to close in the first quarter of
2002, is subject to standard closing conditions, as well as approvals by the
court overseeing the Enron Corp. bankruptcy and by the Enron board of directors.
Through capital contributions it will make to the current expansion project on
the Trailblazer pipeline, CIG Trailblazer Gas Company, an affiliate of El Paso
Corporation, is expected to become a 7% to 8% equity owner in Trailblazer
Pipeline Company in mid-2002.

  1999 Kinder Morgan, Inc. Asset Contributions

     Effective December 31, 1999, we acquired over $935.8 million of assets from
KMI. As consideration for the assets, we paid to KMI $330 million in cash and
19,620,000 common units, valued at approximately $406.3 million. In addition, we
assumed $40.3 million in debt and approximately $121.6 million in liabilities.
We acquired Kinder Morgan Interstate Gas Transmission LLC (formerly K N
Interstate Gas Transmission Co.), a 33 1/3% interest in Trailblazer Pipeline
Company and a 49% equity interest in Red Cedar Gathering Company. The acquired
interest in Trailblazer Pipeline Company, when combined with the interest
purchased on November 30, 1999, gave us a 66 2/3% ownership interest.

                                        88
<PAGE>

     Our purchase price and the allocation to assets acquired and liabilities
assumed was as follows (in thousands):

<Table>
<S>                                                            <C>
Purchase price:
  Common units issued.......................................   $406,262
  Cash paid, including transaction costs....................    367,600
  Debt assumed..............................................     40,300
  Liabilities assumed.......................................    121,675
                                                               --------
  Total purchase price......................................   $935,837
                                                               ========
Allocation of purchase price:
  Current assets............................................   $ 78,335
  Property, plant and equipment.............................    741,125
  Equity investments........................................     88,249
  Deferred charges and other assets.........................     28,128
                                                               --------
                                                               $935,837
                                                               ========
</Table>

  Milwaukee Bulk Terminals, Inc. and Dakota Bulk Terminal, Inc.

     Effective January 1, 2000, we acquired all of the shares of the capital
stock of Milwaukee Bulk Terminals, Inc. and Dakota Bulk Terminal, Inc. We paid
an aggregate consideration of approximately $31.0 million, including 1,148,344
common units, approximately $0.8 million in cash and the assumption of
approximately $7.0 million in liabilities. The Milwaukee terminal is located on
nine acres of property leased from the Port of Milwaukee. Its major cargoes are
coal and bulk de-icing salt. The Dakota terminal, located in St. Paul,
Minnesota, primarily handles bulk de-icing salt and grain products.

     Our purchase price and the allocation to assets acquired and liabilities
assumed was as follows (in thousands):

<Table>
<S>                                                           <C>
Purchase price:
  Common units issued.......................................  $23,319
  Cash paid, including transaction costs....................      757
  Liabilities assumed.......................................    6,960
                                                              -------
  Total purchase price......................................  $31,036
                                                              =======
Allocation of purchase price:
  Current assets............................................  $ 1,764
  Property, plant and equipment.............................   15,201
  Goodwill..................................................   14,071
                                                              -------
                                                              $31,036
                                                              =======
</Table>

  Kinder Morgan CO(2) Company, L.P.

     Effective April 1, 2000, we acquired the remaining 78% limited partner
interest and the 2% general partner interest in Shell CO(2) Company, Ltd. from
Shell for approximately $212.1 million and the assumption of approximately $37.1
million of liabilities. We renamed the limited partnership Kinder Morgan CO(2)
Company, L.P., and going forward from April 1, 2000, we have included its
results as part of our consolidated financial statements under our CO(2)
Pipelines business segment. As is the case with all of our operating
partnerships, we own a 98.9899% limited partner ownership interest in KMCO(2)
and our general partner owns a direct 1.0101% general partner ownership
interest.

                                        89
<PAGE>

     Our purchase price and the allocation to assets acquired and liabilities
assumed was as follows (in thousands):

<Table>
<S>                                                           <C>
Purchase price:
  Cash paid, including transaction costs....................  $212,081
  Liabilities assumed.......................................    37,080
                                                              --------
  Total purchase price......................................  $249,161
                                                              ========
Allocation of purchase price:
  Current assets............................................  $ 51,870
  Property, plant and equipment.............................   230,332
  Goodwill..................................................    45,751
  Equity investments........................................   (79,693)(a)
  Deferred charges and other assets.........................       901
                                                              --------
                                                              $249,161
                                                              ========
</Table>

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

(a)  Represents reclassification of our original 20% equity investment in Shell
     CO(2) Company, L.P. of ($86.7) million and our allocation of purchase price
     to the equity investment purchased in our acquisition of Shell CO(2)
     Company, L.P. of $7.0 million.

  Devon Energy

     Effective June 1, 2000, we acquired significant interests in carbon dioxide
pipeline assets and oil-producing properties from Devon Energy Production
Company L.P. for $53.4 million. Included in the acquisition was an approximate
81% equity interest in the Canyon Reef Carriers CO(2) Pipeline, an approximate
71% working interest in the SACROC oil field, and minority interests in the
Sharon Ridge unit and the Reinecke unit. All of the assets and properties are
located in the Permian Basin of west Texas.

     Our purchase price and the allocation to assets acquired and liabilities
assumed was as follows (in thousands):

<Table>
<S>                                                           <C>
Purchase price:
  Cash paid, including transaction costs....................  $53,435
                                                              -------
  Total purchase price......................................  $53,435
                                                              =======
Allocation of purchase price:
  Property, plant and equipment.............................  $53,435
                                                              -------
                                                              $53,435
                                                              =======
</Table>

  Buckeye Refining Company, LLC

     On October 25, 2000, we acquired Kinder Morgan Transmix, LLC, formerly
Buckeye Refining Company, LLC, which owns and operates transmix processing
plants in Indianola, Pennsylvania and Wood River, Illinois and other related
transmix assets. As consideration for the purchase, we paid Buckeye
approximately $37.3 million for property, plant and equipment plus approximately
$8.4 million for net working capital and other items. We also assumed
approximately $11.5 million of liabilities.

                                        90
<PAGE>

     Our purchase price and the allocation to assets acquired and liabilities
assumed was as follows (in thousands):

<Table>
<S>                                                           <C>
Purchase price:
  Cash paid, including transaction costs....................  $45,696
  Liabilities assumed.......................................   11,462
                                                              -------
  Total purchase price......................................  $57,158
                                                              =======
Allocation of purchase price:
  Current assets............................................  $19,862
  Property, plant and equipment.............................   37,289
  Deferred charges and other assets.........................        7
                                                              -------
                                                              $57,158
                                                              =======
</Table>

  Cochin Pipeline

     Effective November 3, 2000, we acquired from NOVA Chemicals Corporation an
undivided 32.5% interest in the Cochin Pipeline System for approximately $120.5
million. On June 20, 2001, we acquired an additional 2.3% ownership interest in
the Cochin Pipeline System from Shell Canada Limited for approximately $8.0
million. We now own approximately 34.8% of the Cochin Pipeline System and the
remaining interests are owned by subsidiaries of BP Amoco, Conoco and NOVA
Chemicals. We record our proportional share of joint venture revenues and
expenses and cost of joint venture assets as part of our Products Pipelines
business segment.

     Our purchase price and the allocation to assets acquired and liabilities
assumed was as follows (in thousands):

<Table>
<S>                                                           <C>
Purchase price:
  Cash paid, including transaction costs....................  $128,589
                                                              --------
  Total purchase price......................................  $128,589
                                                              ========
Allocation of purchase price:
  Property, plant and equipment.............................  $128,589
                                                              --------
                                                              $128,589
                                                              ========
</Table>

     Effective December 31, 2001, we purchased an additional 10% ownership
interest in the Cochin Pipeline System from NOVA Chemicals Corporation for
approximately $29 million in cash. We now own approximately 44.8% of the Cochin
Pipeline System. We allocated the purchase price to property, plant and
equipment in January 2002.

  Delta Terminal Services LLC

     Effective December 1, 2000, we acquired all of the shares of the capital
stock of Delta Terminal Services LLC, formerly Delta Terminal Services, Inc.,
for approximately $114.1 million and the assumption of approximately $22.5
million of liabilities. The acquisition includes two liquid bulk storage
terminals in New Orleans, Louisiana and Cincinnati, Ohio.

                                        91
<PAGE>

     Our purchase price and the allocation to assets acquired and liabilities
assumed was as follows (in thousands):

<Table>
<S>                                                            <C>
Purchase price:
  Cash paid, including transaction costs....................   $114,112
  Liabilities assumed.......................................     22,496
                                                               --------
  Total purchase price......................................   $136,608
                                                               ========
Allocation of purchase price:
  Current assets............................................   $  1,137
  Property, plant and equipment.............................     70,189
  Goodwill..................................................     65,245
  Deferred charges and other assets.........................         37
                                                               --------
                                                               $136,608
                                                               ========
</Table>

  MKM Partners, L.P.

     On December 28, 2000, we announced that KMCO()2 had entered into a
definitive agreement to form a joint venture with Marathon Oil Company in the
southern Permian Basin of west Texas. The joint venture holds a nearly 13%
interest in the SACROC unit and a 49.9% interest in the Yates Field unit. The
joint venture was formed on January 1, 2001 and named MKM Partners, L.P. As of
December 31, 2000, we paid $34.2 million plus committed 30 billion cubic feet of
carbon dioxide for our 7.5% interest in the Yates field unit. In January 2001,
we contributed our interest in the Yates field unit together with an approximate
2% interest in the SACROC unit in return for a 15% interest in the joint
venture. In January 2001, Marathon Oil Company purchased an approximate 11%
interest in the SACROC unit from KMCO(2) for $6.2 million. Marathon Oil Company
then contributed this interest in the SACROC unit and its 42.4% interest in the
Yates field unit for an 85% interest in the joint venture. Going forward from
January 1, 2001, we accounted for this investment under the equity method of
accounting.

     Our purchase price and the allocation to assets acquired and liabilities
assumed was as follows (in thousands):

<Table>
<S>                                                           <C>
Purchase price:
  Cash paid, including transaction costs....................  $34,163
                                                              -------
  Total purchase price......................................  $34,163
                                                              =======
Allocation of purchase price:
  Equity investments........................................  $34,163
                                                              -------
                                                              $34,163
                                                              =======
</Table>

  2000 Kinder Morgan, Inc. Asset Contributions

     Effective December 31, 2000, we acquired $621.7 million of assets from KMI.
As consideration for these assets, we paid to KMI $192.7 million in cash and
approximately $156.3 million in units, consisting of 1,280,000 common units and
5,313,400 class B units. We also assumed liabilities of approximately $272.7
million. We acquired Kinder Morgan Texas Pipeline, L.P. and MidCon NGL Corp.
(both of which were converted to single-member limited liability companies), the
Casper and Douglas natural gas gathering and processing systems, a 50% interest
in Coyote Gas Treating, LLC and a 25% interest in Thunder Creek Gas Services,
LLC.

                                        92
<PAGE>

     Our purchase price and the allocation to assets acquired and liabilities
assumed was as follows (in thousands):

<Table>
<S>                                                           <C>
Purchase price:
  Common and Class B units issued...........................  $156,305
  Cash paid, including transaction costs....................   192,677
  Liabilities assumed.......................................   272,718
                                                              --------
  Total purchase price......................................  $621,700
                                                              ========
Allocation of purchase price:
  Current assets............................................  $255,320
  Property, plant and equipment.............................   137,145
  Intangible-leasehold Value................................   179,390
  Equity investments........................................    45,225
  Deferred charges and other assets.........................     4,620
                                                              --------
                                                              $621,700
                                                              ========
</Table>

  Colton Transmix Processing Facility

     Effective December 31, 2000, we acquired the remaining 50% interest in the
Colton Transmix Processing Facility from Duke Energy Merchants for approximately
$11.2 million and the assumption of approximately $1.8 million of liabilities.
We now own 100% of the Colton facility. Prior to our acquisition of the
controlling interest in the Colton facility, we accounted for our ownership
interest in the Colton facility under the equity method of accounting.

     Our purchase price and the allocation to assets acquired and liabilities
assumed was as follows (in thousands):

<Table>
<S>                                                           <C>
Purchase price:
  Cash paid, including transaction costs....................  $11,233
  Liabilities assumed.......................................    1,788
                                                              -------
  Total purchase price......................................  $13,021
                                                              =======
Allocation of purchase price:
  Current assets............................................  $ 4,465
  Property, plant and equipment.............................    8,556
                                                              -------
                                                              $13,021
                                                              =======
</Table>

  GATX Domestic Pipelines and Terminals Businesses

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

     - KMLT (formerly GATX Terminals Corporation), effective January 1, 2001;

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

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

     KMLT's assets includes 12 terminals, located across the United States,
which store 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
                                        93
<PAGE>

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 $1,231.6 million, consisting of
$975.4 million in cash, $134.8 million in assumed debt and $121.4 million in
assumed liabilities.

     Our purchase price and the allocation to assets acquired and liabilities
assumed was as follows (in thousands):

<Table>
<S>                                                           <C>
Purchase price:
  Cash paid, including transaction costs....................  $  975,428
  Debt assumed..............................................     134,746
  Liabilities assumed.......................................     121,436
                                                              ----------
  Total purchase price......................................  $1,231,610
                                                              ==========
Allocation of purchase price:
  Current assets............................................  $   32,364
  Property, plant and equipment.............................     927,344
  Deferred charges and other assets.........................       4,784
  Goodwill..................................................     267,118
                                                              ----------
                                                              $1,231,610
                                                              ==========
</Table>

  Pinney Dock & Transport LLC

     Effective March 1, 2001, we acquired all of the shares of the capital stock
of Pinney Dock & Transport LLC, formerly Pinney Dock & Transport Company, for
approximately $52.5 million. The acquisition includes 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 $10.8 million in assumed
liabilities.

     Our purchase price and the allocation to assets acquired and liabilities
assumed was as follows (in thousands):

<Table>
<S>                                                            <C>
Purchase price:
  Cash paid, including transaction costs....................   $41,674
  Liabilities assumed.......................................    10,875
                                                               -------
  Total purchase price......................................   $52,549
                                                               =======
Allocation of purchase price:
  Current assets............................................   $ 1,970
  Property, plant and equipment.............................    32,467
  Deferred charges and other assets.........................       487
  Goodwill..................................................    17,625
                                                               -------
                                                               $52,549
                                                               =======
</Table>

  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

                                        94
<PAGE>

price was approximately $44.3 million, consisting of approximately $43.6 million
in cash and approximately $0.7 million in assumed liabilities.

     Our purchase price and the allocation to assets acquired and liabilities
assumed was as follows (in thousands):

<Table>
<S>                                                            <C>
Purchase price:
  Cash paid, including transaction costs....................   $ 43,622
  Liabilities assumed.......................................        700
                                                               --------
  Total purchase price......................................   $ 44,322
                                                               ========
Allocation of purchase price:
  Property, plant and equipment.............................   $ 44,322
                                                               ========
</Table>

  Kinder Morgan Texas Pipeline

     Effective July 18, 2001, we acquired, from an affiliate of Occidental
Petroleum Corporation, Kinder Morgan Texas Pipeline, L.P., a partnership that
owns a natural gas pipeline system in the State of Texas. Prior to our
acquisition of this natural gas pipeline system, these assets were leased 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 will
be 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.

     Our purchase price and the allocation to assets acquired and liabilities
assumed was as follows (in thousands):

<Table>
<S>                                                            <C>
Purchase price:
  Cash paid, including transaction costs....................   $359,059
  Release SFAS No. 13 deferred credit previously held.......    (32,918)
                                                               --------
  Total purchase price......................................   $326,141
                                                               ========
Allocation of purchase price:
  Property, plant and equipment.............................   $326,141
                                                               --------
                                                               $326,141
                                                               ========
</Table>

     Note: These assets were previously leased from a third party under an
operating lease. The released Statement of Financial Accounting Standards No.
13, "Accounting for Leases" deferred credit relates to a deferred credit
accumulated to spread non-straight line operating lease rentals over the period
expected to benefit from those rentals.

  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 $22.2 million, consisting of approximately
$18.1 million in cash, a $3.0 million one-year note payable and approximately
$1.1 million in assumed liabilities.

                                        95
<PAGE>

     Our purchase price and the allocation to assets acquired and liabilities
assumed was as follows (in thousands):

<Table>
<S>                                                            <C>
Purchase price:
  Cash paid, including transaction costs....................   $18,035
  Note payable..............................................     3,000
  Liabilities assumed.......................................     1,115
                                                               -------
  Total purchase price......................................   $22,150
                                                               =======
Allocation of purchase price:
  Current assets............................................   $ 1,690
  Property, plant and equipment.............................     9,867
  Intangibles-Contract Rights...............................     4,000
  Goodwill..................................................     6,593
                                                               -------
                                                               $22,150
                                                               =======
</Table>

     The $6.6 million of goodwill was assigned to our Terminals business segment
and the entire amount is expected to be deductible for tax purposes.

  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 $69.8
million, consisting of approximately $44.8 million in cash and $25.0 million in
assumed debt.

     Our purchase price and the allocation to assets acquired and liabilities
assumed was as follows (in thousands):

<Table>
<S>                                                            <C>
Purchase price:
  Cash paid, including transaction costs....................   $44,838
  Debt assumed..............................................    25,000
                                                               -------
  Total purchase price......................................   $69,838
                                                               =======
Allocation of purchase price:
  Property, plant and equipment.............................   $69,763
  Goodwill..................................................        75
                                                               -------
                                                               $69,838
                                                               =======
</Table>

     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.

  Snyder and Diamond M Plants

     On November 14, 2001, we announced that KMCO(2) had purchased Mission
Resources Corporation's interest in the Snyder Gasoline Plant and Diamond M Gas
Plant. In December 2001, KMCO(2) purchased Torch E&P Company's interest in the
Snyder Gasoline Plant and entered into a definitive agreement to

                                        96
<PAGE>

purchase Torch's interest in the Diamond M Gas Plant. As of December 31, 2001,
we have paid approximately $14.7 million for these interests. Final purchase
price adjustments should be made in the first quarter of 2002. All of these
assets are located in the Permian Basin of west Texas. As a result of the
acquisition, we have increased our ownership interests in both plants, each of
which process gas produced by the SACROC unit.

     Our purchase price and the allocation to assets acquired and liabilities
assumed was as follows (in thousands):

<Table>
<S>                                                            <C>
Purchase price:
  Cash paid, including transaction costs....................   $14,700
                                                               -------
  Total purchase price......................................   $14,700
                                                               =======
Allocation of purchase price:
  Property, plant and equipment.............................   $14,700
                                                               -------
                                                               $14,700
                                                               =======
</Table>

  PRO FORMA INFORMATION

     The following summarized unaudited Pro Forma Consolidated Income Statement
information for the twelve months ended December 31, 2001 and 2000, assumes the
2001 and 2000 acquisitions and joint ventures had occurred as of January 1,
2000. 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
2001 and 2000 acquisitions and joint ventures as of January 1, 2000 or the
results which 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,
                                                              -----------------------
                                                                 2001         2000
                                                              ----------   ----------
                                                                    (UNAUDITED)
<S>                                                           <C>          <C>
Revenues....................................................  $3,028,543   $3,295,040
Operating Income............................................     592,668      537,561
Income before extraordinary charge..........................     501,153      469,609
Net Income..................................................     484,521      448,201
Basic and diluted Limited Partners' Income per unit before
  extraordinary charge......................................  $     1.56   $     1.38
Basic and diluted Limited Partners' Net Income per unit.....  $     1.56   $     1.38
</Table>

  ACQUISITIONS SUBSEQUENT TO DECEMBER 31, 2001

     On December 12, 2001, we announced that we had signed a definitive
agreement to acquire the remaining 33 1/3% ownership interest in Trailblazer
Pipeline Company from Enron Trailblazer Pipeline Company for $68 million in
cash. Following the acquisition, we will own 100% of Trailblazer Pipeline
Company. The transaction, which is expected to close in the first quarter of
2002, is subject to standard closing conditions, as well as approvals by the
court overseeing the Enron Corp. bankruptcy and by the Enron board of directors.
Through capital contributions it will make to the current expansion project on
the Trailblazer pipeline, CIG Trailblazer Gas Company, an affiliate of El Paso
Corporation, is expected to become a 7% to 8% equity owner in Trailblazer
Pipeline Company in mid-2002.

     On December 17, 2001, we announced that we had entered into a definitive
agreement to purchase Tejas Gas, LLC, a wholly owned subsidiary of InterGen
(North America), Inc., for approximately $750 million in cash. Tejas Gas, LLC is
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

                                        97
<PAGE>

north from near Houston to east Texas. InterGen is a joint venture owned by
affiliates of the Royal Dutch/Shell Group of Companies and Bechtel Enterprises
Holding, Inc. The transaction is subject to standard closing conditions
including receipt of certain regulatory and third party approvals. It is
expected to close in the first quarter of 2002.

     On February 4, 2002, we announced two acquisitions and a major expansion
program, both within our Terminals business segment. Together, the investments
represent approximately $43 million. The purchases included Pittsburgh,
Pennsylvania based Laser Materials Services LLC, operator of 59 transload
facilities in 18 states, and a 66 2/3% interest in International Marine
Terminals Partnership (IMT), which operates a bulk terminal site in Port
Sulphur, Louisiana. The expansion project, which is being carried out at our
Carteret, New Jersey, liquids terminal, will add 400,000 barrels of storage (6%
of current storage capacity) within 2002.

4.  GAIN ON SALE OF EQUITY INTEREST, NET OF SPECIAL CHARGES

     During the third quarter of 1999, we completed the sale of our partnership
interest in the Mont Belvieu fractionation facility for approximately $41.8
million. We recognized a gain of $14.1 million on the sale and included that
gain as part of our Natural Gas Pipelines business segment. Offsetting the gain
were charges of approximately $3.6 million relating to our write-off of
abandoned project costs, primarily within our Products Pipelines business
segment, and a charge of $0.4 million relating to prior years' over-billed
storage tank lease fees, also within our Products Pipelines business segment.

5.  INCOME TAXES

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

<Table>
<Caption>
                                                            YEAR ENDED DECEMBER 31,
                                                           --------------------------
                                                            2001      2000      1999
                                                           -------   -------   ------
<S>                                                        <C>       <C>       <C>
Taxes currently payable:
  Federal................................................  $ 9,058   $10,612   $8,169
  State..................................................    1,192     1,416    1,002
                                                           -------   -------   ------
  Total..................................................   10,250    12,028    9,171
Taxes deferred:
  Federal................................................    5,366     1,627      583
  State..................................................      757       279       72
                                                           -------   -------   ------
  Total..................................................    6,123     1,906      655
                                                           -------   -------   ------
Total tax provision......................................  $16,373   $13,934   $9,826
                                                           =======   =======   ======
Effective tax rate.......................................      3.5%      4.8%     5.0%
</Table>

                                        98
<PAGE>

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

<Table>
<Caption>
                                                              YEAR ENDED DECEMBER 31,
                                                              ------------------------
                                                               2001     2000     1999
                                                              ------   ------   ------
<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)%  (35.3)%
  Corporate subsidiary earnings subject to tax..............    1.3%     0.6%     1.0%
  Income tax expense attributable to corporate equity
     earnings...............................................    1.8%     4.1%     4.4%
  State taxes...............................................    0.4%     0.1%     0.1%
  Other.....................................................     --       --     (0.2)%
                                                              -----    -----    -----
Effective tax rate..........................................    3.5%     4.8%     5.0%
                                                              =====    =====    =====
</Table>

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

<Table>
<Caption>
                                                                DECEMBER 31,
                                                              ----------------
                                                               2001      2000
                                                              -------   ------
<S>                                                           <C>       <C>
Deferred tax assets:
  State taxes...............................................  $    --   $  184
  Book accruals.............................................      404      176
  Net Operating Loss/Alternative minimum tax credits........    1,846    1,376
                                                              -------   ------
Total deferred tax assets...................................    2,250    1,736
Deferred tax liabilities:
  Property, plant and equipment.............................   40,794    4,223
                                                              -------   ------
Total deferred tax liabilities..............................   40,794    4,223
                                                              -------   ------
Net deferred tax liabilities................................  $38,544   $2,487
                                                              =======   ======
</Table>

     We had available, at December 31, 2001, approximately $1.1 million of
alternative minimum tax credit carryforwards, which are available indefinitely,
and $1.9 million of net operating loss carryforwards, which will expire between
the years 2002 and 2018. 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.

                                        99
<PAGE>

6.  PROPERTY, PLANT AND EQUIPMENT

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

<Table>
<Caption>
                                                                   DECEMBER 31,
                                                              -----------------------
                                                                 2001         2000
                                                              ----------   ----------
<S>                                                           <C>          <C>
Natural gas, liquids and carbon dioxide pipelines...........  $2,246,930   $1,732,607
  Natural gas, liquids and carbon dioxide pipeline station
     equip..................................................   2,168,924    1,072,185
  Coal and bulk tonnage transfer, storage and services......     214,040      191,313
  Natural gas and transmix processing.......................      97,155       95,624
  Land and land right-of-way................................     283,878      196,109
  Construction work in process..............................     156,452       90,067
  Other.....................................................     217,245      117,981
                                                              ----------   ----------
  Total cost................................................   5,384,624    3,495,886
  Accumulated depreciation and depletion....................    (302,012)    (189,581)
                                                              ----------   ----------
                                                              $5,082,612   $3,306,305
                                                              ==========   ==========
</Table>

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

<Table>
<Caption>
                                                           2001      2000      1999
                                                         --------   -------   -------
<S>                                                      <C>        <C>       <C>
Depreciation and depletion expense.....................  $126,641   $79,740   $44,553
</Table>

7.  INVESTMENTS

     Our significant equity investments at December 31, 2001 consisted of:

     - Plantation Pipe Line Company (51%);

     - Red Cedar Gathering Company (49%);

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

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

     - Cortez Pipeline Company (50%)

     - MKM Partners, L.P. (15%); and

     - Heartland Pipeline Company (50%).

     On June 16, 1999, we acquired an additional approximate 27% interest in
Plantation Pipe Line Company. As a result, we now 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 April 1, 2000, we acquired the remaining 80% ownership interest in Shell
CO(2) Company, Ltd. and renamed the entity Kinder Morgan CO(2) Company, L.P.
(KMCO(2)). On December 31, 2000, we acquired the remaining 50% ownership
interest in the Colton Transmix Processing Facility. Due to these acquisitions,
we no longer report these two investments under the equity method of accounting.
In addition, we had an equity investment in Trailblazer Pipeline Company
(33 1/3%) for one month of 1999 and had an equity interest in Mont Belvieu
Associates through two quarters of 1999. We sold our equity interest in Mont
Belvieu Associates in the third quarter of 1999 and acquired an additional
33 1/3% interest in Trailblazer Pipeline Company effective December 31, 1999.

                                       100
<PAGE>

     On December 28, 2000, we announced that KMCO(2) had entered into a
definitive agreement to form a joint venture with Marathon Oil Company in the
southern Permian Basin of west Texas. The joint venture consists of a nearly 13%
interest in the SACROC unit and a 49.9% interest in the Yates oil field. The
joint venture was formed on January 1, 2001 and named MKM Partners, L.P. As of
December 31, 2000, we paid $34.2 million plus committed 30 billion cubic feet of
carbon dioxide for our 7.5% interest in the Yates oil field. In January 2001, we
contributed our interest in the Yates oil field together with an approximate 2%
interest in the SACROC unit in return for a 15% interest in the joint venture.
In January 2001, Marathon Oil Company purchased an approximate 11% interest in
the SACROC unit from KMCO(2) for $6.2 million. Marathon Oil Company then
contributed this interest in the SACROC unit and its 42.4% interest in the Yates
oil field for an 85% interest in the joint venture. Going forward from January
1, 2001, we have accounted for this investment under the equity method.

     We acquired our investment in Cortez Pipeline Company as part of our
KMCO(2) acquisition and we acquired our investments in Coyote Gas Treating, LLC
and Thunder Creek Gas Services, LLC from KMI on December 31, 2000.

     Please refer to Notes 3 and 4 for more information.

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

<Table>
<Caption>
                                                                 DECEMBER 31,
                                                              -------------------
                                                                2001       2000
                                                              --------   --------
<S>                                                           <C>        <C>
Plantation Pipe Line Company................................  $217,473   $223,627
Red Cedar Gathering Company.................................    99,484     96,388
MKM Partners, L.P...........................................    58,633         --
Thunder Creek Gas Services, LLC.............................    30,159     27,625
Coyote Gas Treating, LLC....................................    16,323     17,000
Cortez Pipeline Company.....................................     9,599      9,559
Heartland Pipeline Company..................................     5,608      6,025
All Others..................................................     3,239      2,658
                                                              --------   --------
Total Equity Investments....................................  $440,518   $382,882
Investment in oil and gas assets to be contributed to joint
  venture...................................................        --     34,163
                                                              --------   --------
Total Investments...........................................  $440,518   $417,045
                                                              ========   ========
</Table>

                                       101
<PAGE>

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

<Table>
<Caption>
                                                            YEAR ENDED DECEMBER 31,
                                                          ---------------------------
                                                           2001      2000      1999
                                                          -------   -------   -------
<S>                                                       <C>       <C>       <C>
Plantation Pipe Line Company............................  $25,314   $31,509   $22,510
Cortez Pipeline Company.................................   25,694    17,219        --
Red Cedar Gathering Company.............................   18,814    16,110        --
MKM Partners, L.P.......................................    8,304        --        --
Shell CO(2) Company, Ltd................................       --     3,625    14,500
Colton Transmix Processing Facility.....................       --     1,815     1,531
Heartland Pipeline Company..............................      882     1,581     1,571
Coyote Gas Treating, LLC................................    2,115        --        --
Thunder Creek Gas Services, LLC.........................    1,629        --        --
Mont Belvieu Associates.................................       --        --     2,500
Trailblazer Pipeline Company............................       --       (24)      284
All Others..............................................    2,082      (232)       22
                                                          -------   -------   -------
Total...................................................  $84,834   $71,603   $42,918
                                                          =======   =======   =======
Amortization of excess costs............................  $(9,011)  $(8,195)  $(4,254)
                                                          =======   =======   =======
</Table>

     Summarized combined unaudited financial information for our significant
equity investments is reported below (in thousands; amounts represent 100% of
investee financial information, not our pro rata portion):

<Table>
<Caption>
                                                          YEAR ENDED DECEMBER 31,
                                                       ------------------------------
INCOME STATEMENT                                         2001       2000       1999
----------------                                       --------   --------   --------
<S>                                                    <C>        <C>        <C>
Revenues.............................................  $449,502   $399,335   $344,017
Costs and expenses...................................   280,364    276,000    244,515
Earnings before extraordinary items..................   169,138    123,335     99,502
Net income...........................................   169,138    123,335     99,502
</Table>

<Table>
<Caption>
                                                                  DECEMBER 31,
                                                              ---------------------
BALANCE SHEET                                                    2001        2000
-------------                                                 ----------   --------
<S>                                                           <C>          <C>
Current assets..............................................  $  101,015   $117,050
Non-current assets..........................................   1,079,054    665,435
Current liabilities.........................................      75,722     92,027
Non-current liabilities.....................................     559,454    576,278
Partners'/owners' equity....................................     544,893    114,180
</Table>

8.  INTANGIBLES

     Our intangible assets include acquired goodwill, lease value, contracts and
agreements. We acquired our 2000 intangible lease value as part of our
acquisition of Kinder Morgan Texas Pipeline, L.P. on December 31, 2000 from KMI.
In our July 2001 acquisition of K M Texas Pipeline, L.P., we acquired the leased
pipeline asset from Occidental Petroleum and our operating lease was terminated.
We allocated the balance of the KMTP intangible lease value between goodwill and
property.

     All of our intangible assets having definite lives are being amortized on a
straight-line basis over their estimated useful lives. As of December 31, 2001,
goodwill was being amortized over a period of 40 years.

                                       102
<PAGE>

     Intangible assets consisted of the following (in thousands):

<Table>
<Caption>
                                                                 DECEMBER 31,
                                                              -------------------
                                                                2001       2000
                                                              --------   --------
<S>                                                           <C>        <C>
Goodwill....................................................  $566,633   $162,271
Accumulated amortization....................................   (19,899)    (4,201)
                                                              --------   --------
                                                               546,734    158,070
Lease value.................................................     6,124    185,982
Contracts and other.........................................    10,739      1,861
                                                              --------   --------
Accumulated amortization....................................      (200)      (608)
                                                              --------   --------
Other intangibles, net......................................    16,663    187,235
                                                              --------   --------
Total intangibles, net......................................  $563,397   $345,305
                                                              ========   ========
</Table>

     Amortization expense consists of the following (in thousands):

<Table>
<Caption>
                                                             2001      2000     1999
                                                            -------   ------   ------
<S>                                                         <C>       <C>      <C>
Amortization expense......................................  $15,436   $2,890   $1,916
</Table>

9.  DEBT

     Our debt and credit facilities as of December 31, 2001, consist primarily
of:

     - $200 million of Floating Rate Senior Notes due March 22, 2002;

     - an $85.2 million unsecured two-year credit facility due June 29, 2003
       (our subsidiary Trailblazer Pipeline Company is the obligor on the
       facility);

     - a $750 million unsecured 364-day credit facility due October 23, 2002;

     - a $300 million unsecured five-year credit facility due September 29,
       2004;

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

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

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

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

     - $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);

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

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

     - $79.6 million of Series F First Mortgage Notes due December 2004 (our
       subsidiary, SFPP, L.P. is the obligor on the notes);

     - $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);

     - $35 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); and

     - a $900 million short-term commercial paper program.

                                       103
<PAGE>

     None of our debt or credit facilities are subject to payment acceleration
as a result of any change to our credit ratings. Our short-term debt at December
31, 2001, consisted of:

     - $590.5 million of commercial paper borrowings;

     - $200.0 million under our Floating Rate Senior Notes due March 22, 2002;

     - $42.5 million under the SFPP 10.7% First Mortgage Notes; and

     - $3.5 million in other borrowings.

     Based on prior successful short-term debt refinancings and current market
conditions, we intend and have the ability to refinance $276.3 million of our
short-term debt on a long-term basis under our unsecured five-year credit
facility, and we do not anticipate any liquidity problems.

  Credit Facilities

     On September 29, 1999, our $325 million credit facility was replaced with a
$300 million unsecured five-year credit facility expiring in September 2004 and
a $300 million unsecured 364-day credit facility. We recorded an extraordinary
charge of $2.6 million related to the retirement of our $325 million credit
facility. Our 364-day credit facility expired on September 29, 2000 and was
extended until October 25, 2000. On October 25, 2000, the facility was replaced
with a new $600 million unsecured 364-day credit facility expiring on October
25, 2001. The outstanding balance under our 364-day credit facility was $582
million at December 31, 2000.

     During the first quarter of 2001, we obtained a third unsecured credit
facility, in the amount of $1.1 billion, expiring on December 31, 2001. The
terms of this credit facility were substantially similar to the terms of the
other two facilities. Upon issuance of additional senior notes on March 12,
2001, this short-term credit facility was reduced to $500 million. During the
second quarter of 2001, we terminated our $500 million credit facility, which
was scheduled to expire on December 31, 2001. On October 25, 2001, our 364-day
credit facility expired and we obtained a new $750 million unsecured 364-day
credit facility. The terms of this credit facility are substantially similar to
the terms of the expired facility. No borrowings were outstanding under our
364-day credit facility at December 31, 2001.

     On August 11, 2000, we refinanced the outstanding balance under SFPP,
L.P.'s secured credit facility with a $175.0 million borrowing under our
five-year credit facility. The outstanding balance under our five-year credit
facility was $207.6 million at December 31, 2000. No borrowings were outstanding
under our five-year credit facility at December 31, 2001.

     Our two credit facilities are with a syndicate of financial institutions.
First Union National Bank is the administrative agent under the agreements.
Interest on our credit facilities accrues at our option at a floating rate equal
to either:

     - First Union National Bank's base rate (but not less than the Federal
       Funds Rate, plus 0.5%); or

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

Our five-year credit facility also permits us to obtain bids for fixed rate
loans from members of the lending syndicate. The weighted average interest rate
on our borrowings under our credit facilities was 6.1531% during 2001 and
6.8987% during 2000.

     The amount available for borrowing under our credit facilities are reduced
by a $23.7 million letter of credit that supports Kinder Morgan Operating L.P.
"B"'s tax-exempt bonds and our outstanding commercial paper borrowings.

     We intend to secure promptly after the date of this document an additional
$750 million credit facility to back-up an increase in our commercial paper
program to $1.8 billion to fund the Tejas acquisition. We expect to terminate
this facility once we have issued debt and/or equity to permanently finance the

                                       104
<PAGE>

acquisition. At that time, our commercial paper capacity will be reduced to
$1.05 billion. We expect to increase the debt to EBITDA ratio allowed by our
credit facilities to 4.25 to 1 through June 30, 2002.

  Senior Notes

     Under an indenture dated March 22, 2000, we completed a private placement
of $200 million of floating rate notes due March 22, 2002 and $200 million of
8.0% notes due March 15, 2005. On May 31, 2000, we exchanged these notes with
substantially identical notes that were registered under the Securities Act of
1933. The proceeds from this offering, net of underwriting discounts, were
$397.9 million. The proceeds from the issuance of these notes were used to
reduce our outstanding commercial paper. At December 31, 2001, the interest rate
on our floating rate notes was 3.1025%.

     On November 8, 2000, we closed a private placement of $250 million of 7.5%
notes due November 1, 2010. On March 28, 2001, we exchanged these notes with
substantially identical notes that were registered under the Securities Act of
1933. The proceeds from this offering, net of underwriting discounts, were
$246.8 million. These proceeds were used to reduce our outstanding commercial
paper.

     On March 12, 2001, we closed a public offering of $1.0 billion in principal
amount of senior notes, consisting of $700 million in principal amount of 6.75%
senior notes due March 15, 2011 at a price to the public of 99.705% per note,
and $300 million in principal amount of 7.40% senior notes due March 15, 2031 at
a price to the public of 99.748% per note. In the offering, we received
proceeds, net of underwriting discounts and commissions, of approximately $693.4
million for the 6.75% notes and $296.6 million for the 7.40% notes. We used the
proceeds to pay for our acquisition of Pinney Dock & Transport LLC (see Note 3)
and to reduce our outstanding balance on our credit facilities and commercial
paper borrowings.

     At December 31, 2001, our unamortized liability balance due on the various
series of our senior notes were as follows (in millions):

<Table>
<S>                                                            <C>
6.30% senior notes due February 1, 2009.....................   $  249.4
8.0% senior notes due March 15, 2005........................      199.7
Floating rate notes due March 22, 2002......................      200.0
7.5% senior notes due November 1, 2010......................      248.6
6.75% senior notes due March 15, 2011.......................      698.1
7.40% senior notes due March 15, 2031.......................      299.3
                                                               --------
  Total.....................................................   $1,895.1
                                                               ========
</Table>

     In addition, in order to maintain a cost effective capital structure, it is
our policy to borrow funds utilizing a mix of fixed rate debt and variable rate
debt. In the third quarter of 2001, we elected to adjust our mix to be closer to
our target ratio of 50% fixed rate debt and 50% variable rate debt. Accordingly,
in August 2001, we entered into interest rate swap agreements with a notional
principal amount of $750 million for the purpose of hedging the interest rate
risk associated with our fixed rate debt obligations. These agreements
effectively convert 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:

     - 8.0% senior notes due March 15, 2005;

     - 6.30% senior notes due February 1, 2009; and

     - 7.40% senior notes due March 15, 2031.

     The swap agreements for our 8.0% senior notes and 6.30% senior notes have
terms that correspond to the maturity dates of such series. The swap agreement
for our 7.40% senior notes contains mutual cash-out agreements at the
then-current economic value every seven years.

                                       105
<PAGE>

  Commercial Paper Program

     In December 1999, we established a commercial paper program providing for
the issuance of up to $200 million of commercial paper, subsequently increased
to $300 million in January 2000. On October 25, 2000, in conjunction with our
new 364-day credit facility, we also increased our commercial paper program to
provide for the issuance of up to $600 million of commercial paper. During the
first quarter of 2001, we increased our commercial paper program to provide for
the issuance of an additional $1.1 billion of commercial paper, and during the
second quarter of 2001, we decreased our commercial paper program back to $600
million. On October 17, 2001, we increased our commercial paper program to $900
million. Borrowings under our commercial paper program reduce the borrowings
allowed under our credit facilities. As of December 31, 2001, we had $590.5
million of commercial paper outstanding with an interest rate of 2.6585%. The
borrowings under our commercial paper program were used to finance acquisitions
made during 2001.

     We intend to secure promptly after the date of this document an additional
$750 million credit facility to back-up an increase in our commercial paper
program to $1.8 billion to fund the Tejas acquisition. We expect to terminate
this facility once we have issued debt and/or equity to permanently finance the
acquisition. At that time, our commercial paper capacity will be reduced to
$1.05 billion. We expect to increase the debt to EBITDA ratio allowed by our
credit facilities to 4.25 to 1 through June 30, 2002.

  SFPP, L.P. Debt

     At December 31, 2001, the outstanding balance under SFPP, L.P.'s Series F
notes was $79.6 million. The annual interest rate on the Series F notes is
10.70%, the maturity is December 2004, and interest is payable semiannually in
June and December. We expect to repay the Series F notes prior to maturity as a
result of SFPP , L.P. taking advantage of certain optional prepayment provisions
without penalty in 1999 and 2000. Remaining annual installments are $42.6
million in 2002 and $37.0 million in 2003. Additionally, the Series F notes may
be prepaid in full or in part at a price equal to par plus, in certain
circumstances, a premium. We 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 are secured by mortgages on substantially all of the properties
of SFPP, L.P. The Series F notes contain 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. We do not believe that these restrictions will materially affect
distributions to our partners.

  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:

     - $4.1 million of 7.30% New Jersey Industrial Revenue Bonds due September
       1, 2019;

     - $59.5 million of 6.95% Texas Industrial Revenue Bonds due February 1,
       2022;

     - $7.4 million of 6.65% New Jersey Industrial Revenue Bonds due September
       1, 2022;

     - $13.3 million of 7.00% Louisiana Industrial Revenue Bonds due March 1,
       2023; and

     - $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. 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.
The 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
                                       106
<PAGE>

consisting of twelve 30-day months during a Term Rate Period. As of December 31,
2001, the interest rate was 1.391%. 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%
and will be repaid 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. At December 31, 2001, Central Florida's
outstanding balance under the Senior Notes was $35.0 million.

  CALNEV Pipe Line LLC Debt

     Effective March 30, 2001, we acquired CALNEV Pipe Line LLC (see Note 3). As
part of our purchase price, we assumed an aggregate principal amount of $6.8
million of Senior Notes originally issued to a syndicate of five insurance
companies. The Senior Notes had a fixed annual interest rate of 10.07%. In June
2001, we prepaid the balance outstanding under the Senior Notes, plus $0.9
million for interest and a make-whole premium, from cash on hand.

  Trailblazer Pipeline Company Debt

     At December 31, 2000, Trailblazer Pipeline Company had a $10 million
borrowing under an intercompany account payable in favor of KMI. In January
2001, Trailblazer Pipeline Company entered into a 364-day revolving credit
agreement with Credit Lyonnais New York Branch, providing for loans up to $10
million. The borrowings were used to pay the account payable to KMI. The
agreement was to expire on December 27, 2001. The agreement provided for an
interest rate of LIBOR plus 0.875%. Pursuant to the terms of the revolving
credit agreement with Credit Lyonnais New York Branch, Trailblazer Pipeline
Company partnership distributions were restricted by certain financial
covenants.

     On June 26, 2001, Trailblazer Pipeline Company prepaid the balance
outstanding under its Senior Secured Notes using a new two-year unsecured
revolving credit facility with a bank syndication. The new facility, as amended
August 24, 2001, provides for loans of up to $85.2 million and expires June 29,
2003. The agreement provides for an interest rate of LIBOR plus a margin as
determined by certain financial ratios. On June 29, 2001, Trailblazer Pipeline
Company paid the $10 million outstanding balance under its 364-day revolving
credit agreement and terminated that agreement. At December 31, 2001, the
outstanding balance under Trailblazer Pipeline Company's two-year revolving
credit facility was $55.0 million, with a weighted average interest rate of
2.875%, which reflects three-month LIBOR plus a margin of 0.875%. Pursuant to
the terms of the revolving credit facility, Trailblazer Pipeline Company
partnership distributions are restricted by certain financial covenants. We do
not believe that these restrictions will materially affect distributions to our
partners.

     On September 23, 1992, pursuant to the terms of a Note Purchase Agreement,
Trailblazer Pipeline Company issued and sold an aggregate principal amount of
$101 million of Senior Secured Notes to a syndicate of fifteen insurance
companies. The Senior Secured Notes had a fixed annual interest rate of 8.03%
and the $20.2 million balance as of December 31, 2000 was to be repaid in
semiannual installments of $5.05 million from March 1, 2001 through September 1,
2002, the final maturity date. Interest was payable semiannually in March and
September. Trailblazer Pipeline Company provided collateral for the notes
principally by an assignment of certain Trailblazer Pipeline Company
transportation contracts, and pursuant to the terms of this Note Purchase
Agreement, Trailblazer Pipeline Company's partnership distributions were
restricted by certain financial covenants. Effective April 29, 1997, Trailblazer
Pipeline Company amended the Note Purchase Agreement. This amendment allowed
Trailblazer Pipeline Company to include several additional transportation
contracts as collateral for the notes, added a

                                       107
<PAGE>

limitation on the amount of additional money that Trailblazer Pipeline Company
could borrow and relieved Trailblazer Pipeline Company from its security deposit
obligation. On June 26, 2001, Trailblazer Pipeline Company prepaid the $15.2
million balance outstanding under the Senior Secured Notes, plus $0.8 million
for interest and a make-whole premium, using its new two-year unsecured
revolving credit 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 2001, the weighted-average interest
rate on these bonds was 2.71% per annum, and at December 31, 2001 the interest
rate was 1.70%. We have an outstanding letter of credit issued under our credit
facilities that backs-up our tax-exempt bonds. The letter of credit reduces the
amount available for borrowing under our credit facilities.

  Cortez Pipeline

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

     Due to our indirect ownership of Cortez through KMCO(2), 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's debt programs in place as of April 1, 2000.

     At December 31, 2001, the debt facilities of Cortez Capital Corporation
consisted of:

     - a $127 million uncommitted 364-day revolving credit facility;

     - a $48 million committed 364-day revolving credit facility;

     - $136.4 million of Series D notes; and

     - a $175 million short-term commercial paper program.

     At December 31, 2001, Cortez had $146 million of commercial paper
outstanding with an interest rate of 1.87%, the average interest rate on the
series D notes was 6.8378% and there were no borrowings under the credit
facilities.

  MATURITIES OF DEBT

     The scheduled maturities of our outstanding debt at December 31, 2001, are
summarized as follows (in thousands):

<Table>
<S>                                                            <C>
2002........................................................   $  836,519
2003........................................................       92,073
2004........................................................           17
2005........................................................      199,753
2006........................................................           19
Thereafter..................................................    1,663,412
                                                               ----------
Total.......................................................   $2,791,793
                                                               ==========
</Table>

                                       108
<PAGE>

     Of the $836.5 million scheduled to mature in 2002, we intend and have the
ability to refinance $276.3 million on a long-term basis under our existing
credit facilities. We expect to pay the remaining portion of our short-term debt
within the next year.

  FAIR VALUE OF FINANCIAL INSTRUMENTS

     The estimated fair value of our long-term debt based upon prevailing
interest rates available to us at December 31, 2001 and December 31, 2000 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.

<Table>
<Caption>
                                                  DECEMBER 31, 2001         DECEMBER 31, 2000
                                               -----------------------   -----------------------
                                                CARRYING    ESTIMATED     CARRYING    ESTIMATED
                                                 VALUE      FAIR VALUE     VALUE      FAIR VALUE
                                               ----------   ----------   ----------   ----------
                                                                (IN THOUSANDS)
<S>                                            <C>          <C>          <C>          <C>
Total Debt...................................  $2,791,793   $3,089,089   $1,904,402   $2,011,818
</Table>

10.  PENSIONS AND OTHER POST-RETIREMENT BENEFITS

     In connection with our acquisition of SFPP and Kinder Morgan Bulk Terminals
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.

     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. 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.

     SFPP's post-retirement benefit plan is frozen and no additional
participants may join the plan. As a result of these events, we recognized a
curtailment gain related to the SFPP's plan of $3.9 million in 1999.

                                       109
<PAGE>

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

<Table>
<Caption>
                                        2001                         2000                   1999
                             --------------------------   --------------------------   ---------------
                                  OTHER                        OTHER                        OTHER
                             POST-RETIREMENT   PENSION    POST-RETIREMENT   PENSION    POST-RETIREMENT
                                BENEFITS       BENEFITS      BENEFITS       BENEFITS      BENEFITS
                             ---------------   --------   ---------------   --------   ---------------
<S>                          <C>               <C>        <C>               <C>        <C>
Net periodic benefit cost
Service cost...............       $ 120         $  --          $  46         $  --         $    80
Interest cost..............         804           145            755           141             696
Expected return on plan
  assets...................          --          (170)            --          (150)             --
Amortization of prior
  service cost.............        (545)           --           (493)           --            (493)
Actuarial gain.............         (27)           --           (290)           --            (340)
                                  -----         -----          -----         -----         -------
Net periodic benefit
  cost.....................       $ 352         $ (25)         $  18         $  (9)        $   (57)
                                  =====         =====          =====         =====         =======
Additional amounts
  recognized Curtailment
  (gain) loss..............       $  --         $  --          $  --         $  --         $(3,859)
Weighted-average
  assumptions as of
  December 31:
Discount rate..............        7.00%          7.5%          7.75%          7.0%            7.0%
Expected return on plan
  assets...................          --           8.5%            --           8.5%             --
Rate of compensation
  increase.................          --            --             --            --              --
</Table>

                                       110
<PAGE>

     Information concerning benefit obligations, plan assets, funded status and
recorded values for these plans follows (in thousands):

<Table>
<Caption>
                                                              2001                   2000
                                                   --------------------------   ---------------
                                                        OTHER                        OTHER
                                                   POST-RETIREMENT   PENSION    POST-RETIREMENT
                                                      BENEFITS       BENEFITS      BENEFITS
                                                   ---------------   --------   ---------------
<S>                                                <C>               <C>        <C>
Change in benefit obligation
Benefit obligation at Jan. 1.....................     $ 10,897        $1,737       $  9,564
Service cost.....................................          120            --             46
Interest cost....................................          804           145            755
Amendments.......................................           --            --           (371)
Administrative expenses..........................           --            (9)            --
Actuarial loss...................................        2,350           299          1,339
Benefits paid from plan assets...................         (803)         (189)          (435)
                                                      --------        ------       --------
Benefit obligation at Dec. 31....................     $ 13,368        $1,983       $ 10,898
                                                      ========        ======       ========
Change in plan assets
Fair value of plan assets at Jan. 1..............     $     --        $2,060       $     --
Actual return on plan assets.....................           --          (138)            --
Employer contributions...........................          803            92            435
Administrative expenses..........................           --            (9)            --
Benefits paid from plan assets...................         (803)         (189)          (435)
                                                      --------        ------       --------
Fair value of plan assets at Dec. 31.............     $     --        $1,816       $     --
                                                      ========        ======       ========
Funded status....................................     $(13,368)       $ (167)      $(10,898)
Unrecognized net actuarial (gain) loss...........          993           360         (1,383)
Unrecognized prior service (benefit).............       (1,111)           --         (1,656)
                                                      --------        ------       --------
Prepaid (accrued) benefit cost...................     $(13,486)       $  193       $(13,937)
                                                      ========        ======       ========
</Table>

     In 2001, SFPP modified benefits associated with its post-retirement benefit
plan. This plan amendment resulted in a $2.5 million increase in its benefit
obligation for 2001. The unrecognized prior service credit is amortized on a
straight-line basis over the remaining expected service to retirement (3.5
years). For measurement purposes, a 12% annual rate of increase in the per
capita cost of covered health care benefits was assumed for 2001. The rate was
assumed to decrease gradually to 5% by 2008 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:

<Table>
<Caption>
                                                             1-PERCENTAGE     1-PERCENTAGE
                                                            POINT INCREASE   POINT DECREASE
                                                            --------------   --------------
<S>                                                         <C>              <C>
Effect on total of service and interest cost components...      $   85           $ (72)
Effect on postretirement benefit obligation...............      $1,081           $(926)
</Table>

     Multiemployer Plans and Other Benefits.  With our acquisition of Kinder
Morgan Bulk Terminals, effective July 1, 1998, we participate in multi-employer
pension plans for the benefit of its 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 $0.6 million for the year ended 2001 and $0.2 million for
the year ended 2000. The amount charged from the period of acquisition through
December 31, 1998 was $0.5 million.

                                       111
<PAGE>

     We assumed River Consulting, Inc.'s (a consolidated affiliate of Kinder
Morgan Bulk Terminals) savings plan under Section 401(k) of the Internal Revenue
Code. This savings plan allowed eligible employees to contribute up to 10% of
their compensation on a pre-tax basis, with us matching 2.5% of the first 5% of
the employees' wage. Matching contributions are vested at the time of
eligibility, which is one year after employment. Effective January 1, 1999, we
merged this savings plan into the retirement savings plan of our general partner
(see next paragraph).

     Effective July 1, 1997, our general partner established the Kinder Morgan
Retirement Savings Plan, a defined contribution 401(k) plan. This plan was
subsequently amended and merged to form the Kinder Morgan Savings Plan. The plan
now permits all full-time employees of our general partner to contribute 1% to
50% of base compensation, on a pre-tax basis, into participant accounts. In
addition to a mandatory contribution equal to 4% of base compensation per year
for most plan participants, our general partner may make discretionary
contributions in years when specific performance objectives are met. Certain
employees' contributions are based on collective bargaining agreements. 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 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 2002, no discretionary contributions were made to individual accounts
for 2001. The total amount charged to expense for our Retirement Savings Plan
was $4.6 million during 2001. 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 our general partner became eligible
to participate in a new 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 new Cash Balance Retirement Plan. Employees with prior
service and not grandfathered convert to the Cash Balance Retirement Plan and
will be credited with the current fair value of any benefits they have
previously accrued through the defined benefit plan. We will then begin
contributions on behalf of these employees equal to 3% of eligible compensation
every pay period. In addition, we may make discretionary contributions to the
plan based on our performance. In the first quarter of 2002, an additional 1%
discretionary contribution was made to individual accounts based on achieving
2001 financial targets to unitholders. Interest will be credited to the personal
retirement accounts at the 30-year U.S. Treasury bond rate in effect each year.
Employees will be fully vested in the plan after five years, and they may take a
lump sum distribution upon termination of employment or retirement.

11.  PARTNERS' CAPITAL

     At December 31, 2001, our Partners' capital consisted of 129,855,018 common
units, 5,313,400 Class B units and 30,636,363 i-units. Together, these
165,804,781 units represent the limited partners' interest and an effective 98%
economic interest in the Partnership, exclusive of our general partner's
incentive distribution. Our common unit total consisted of 110,071,392 units
held by third parties, 18,059,626 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. At December 31, 2000 and 1999, there were 129,716,218
and 118,274,274 common units outstanding, respectively. The Class B units were
issued in December 2000 and the i-units were issued in 2001. Our general partner
has an effective 2% interest in the Partnership, excluding the general partner's
incentive distribution.

                                       112
<PAGE>

     In May 2001, we received net proceeds of approximately $996.9 million from
KMR for the issuance of i-units. In accordance with KMR's public offering of
limited liability shares, i-units were issued as follows:

     - 2,975,000 units to KMI; and

     - 26,775,000 units to the public.

     We used the proceeds from the i-unit issuance to reduce the debt we
incurred in our acquisition of GATX Corporation's domestic pipeline and liquids
terminal businesses during the first quarter of 2001. The i-units are a separate
class of limited partner interest in the Partnership. All of the i-units will be
owned by KMR and will not be publicly traded. KMR's limited liability company
agreement provides that the number of all of its outstanding shares, including
voting shares owned by our general partner, shall at all times equal the number
of i-units that it owns. 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.

     KMR, as the owner of the i-units, generally will vote together with the
holders of the common units and Class B units as a single class. However, the
i-units will vote separately as a class on the following matters:

     - amendments to our partnership agreement that would have a material
       adverse effect on the holders of the i-units in relation to the other
       classes of units (this kind of an amendment requires the approval of
       two-thirds of the outstanding i-units, excluding the number of i-units
       equal to the number of KMR shares owned by KMI and its affiliates); and

     - the approval of the withdrawal of our general partner or the transfer to
       a non-affiliate of all of its interest as our general partner (these
       matters require the approval of a majority of the outstanding i-units
       excluding the number of i-units equal to the number of KMR shares owned
       by KMI and its affiliates).

     In all cases, KMR will vote its i-units in proportion to the affirmative
and negative votes, abstentions and non-votes of owners of KMR shares.
Furthermore, under the terms of our partnership agreement, we agree 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. Typically, our general partner and owners
of common units and Class B units will receive distributions from us in cash,
while KMR as the owner of i-units will receive distributions in additional
i-units or fractions of i-units. For each outstanding i-unit, a fraction of an
i-unit will be issued. The fraction will be determined by dividing the amount of
cash being distributed per common unit by the average market price of a KMR
share over the ten consecutive trading days preceding the date on which the
shares begin to trade ex-dividend under the rules of the principal exchange on
which the shares are listed. 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
related cash but will retain the cash and use the cash 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.

     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 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, 2001, 2000 and 1999, we
distributed $2.15, $1.7125 and $1.425, respectively, per unit. Our distributions
to unitholders for 2001, 2000 and 1999 required incentive distributions to our
general partner in the amount of $199.7 million, $107.8 million and $55.0
million, respectively. The increased incentive distributions paid

                                       113
<PAGE>

for 2001 over 2000 and 2000 over 1999 reflect the increase in amounts
distributed per unit as well as the issuance of additional units.

     On January 16, 2002, we declared a cash distribution for the quarterly
period ended December 31, 2001, of $0.55 per unit. This distribution was paid on
February 14, 2002, to unitholders of record as of January 31, 2002. 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 $0.55
distribution per common unit. The number of i-units distributed was 453,970. For
each outstanding i-unit that KMR held, a fraction of an i-unit was issued. The
fraction was determined by dividing:

     - $0.55, the cash amount distributed per common unit

by

     - $37.116, the average of KMR's limited liability shares' closing market
       prices from January 14-28, 2002, 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 distribution required an incentive distribution to our general partner
in the amount of $54.4 million. Since this distribution was declared after the
end of the quarter, no amount is shown in the December 31, 2001 balance sheet as
a Distribution Payable.

12.  RELATED PARTY TRANSACTIONS

  GENERAL AND ADMINISTRATIVE EXPENSES

     Kinder Morgan Management, LLC, through its wholly owned subsidiary, Kinder
Morgan Services LLC provides employees and related 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
Kinder Morgan Services are assigned to work for one or more members of the
Group. The direct costs of all compensation, benefits expenses, employer taxes
and other employer expenses for these employees are allocated and charged by
Kinder Morgan Services LLC to the appropriate members of the Group; and the
members of the Group reimburse Kinder Morgan Services for their allocated shares
of these direct costs. There is no profit or margin charged by Kinder Morgan
Services LLC to the members of the Group. The administrative support necessary
to implement these payroll and benefits services is provided by the human
resource department of Kinder Morgan, Inc., and the related administrative costs
are allocated to members of the Group in accordance with existing expense
allocation procedures. The effect of these arrangements is that each member of
the Group bears the direct compensation and employee benefits costs of its
assigned or partially assigned employees, as the case may be, while also bearing
its allocable share of administrative costs. Pursuant to our limited partnership
agreement, we reimburse Kinder Morgan Services LLC for our share of these
administrative costs and such reimbursements will be accounted for as described
above.

     The named executive officers of our general partner and KMR and some other
employees that provide management or services to both Kinder Morgan, Inc. and
the Group are employed by Kinder Morgan, Inc. Additionally, other Kinder Morgan,
Inc. employees assist in the operation of Kinder Morgan Energy Partners' Natural
Gas Pipeline assets formerly owned by Kinder Morgan, Inc. These Kinder Morgan,
Inc. employees' expenses are allocated without a profit component between Kinder
Morgan, Inc. 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 the Partnership, and a direct 1.0101% ownership interest
in each of our five operating partnerships. Collectively, our general partner
owns an effective 2% interest in the operating partnerships, excluding incentive
distributions:

                                       114
<PAGE>

     - its 1.0101% direct general partner ownership interest (accounted for as
       minority interest in the consolidated financial statements of the
       Partnership); and

     - its 0.9899% ownership interest indirectly owned via its 1% ownership
       interest in the Partnership.

     At December 31, 2001, our general partner owned 1,724,000 common units,
representing approximately 1.04% of our outstanding limited partner units. Our
partnership agreement requires that we distribute 100% of "Available Cash" (as
defined in the 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 and net
reductions in reserves 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% special limited partner interest in SFPP,
L.P.

     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.

     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 or fractions of i-units. For each
outstanding i-unit, a fraction of an i-unit will be issued. The fraction is
calculated by dividing the amount of cash being distributed per common unit by
the average market price of KMR's limited liability shares over the ten
consecutive trading days preceding the date on which the shares begin to trade
ex-dividend under the rules of the New York Stock Exchange. The cash equivalent
of distributions of i-units will be treated as if it had actually been
distributed, including for purposes of determining the distributions to our
general partner and calculating Available Cash for future periods. We will not
distribute the related cash but will retain the cash and use the cash 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 as follows;

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

     - second, 85% of any Available Cash then remaining to the owners of all
       classes of units pro rata and 15% to our general partner until the owners
       of all classes of units have received a total of $0.17875 per unit in
       cash or equivalent i-units for such quarter;

     - third, 75% of any Available Cash then remaining to the owners of all
       classes of units pro rata and 25% to our general partner until the owners
       of all classes of units have received a total of $0.23375 per unit in
       cash or equivalent i-units for such quarter; and

     - 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 KMR in the equivalent number of i-units, and 50% to our
       general partner in cash.

     Incentive distributions are generally defined as all cash distributions
paid to our general partner that are in excess of 2% of the aggregate amount of
cash being distributed. Our general partner's declared incentive distributions
for the years ended December 31, 2001, 2000 and 1999 were $199.7 million, $107.8
million and $55.0 million, respectively.

                                       115
<PAGE>

  Kinder Morgan, Inc.

     KMI, through its subsidiary Kinder Morgan (Delaware), Inc., remains the
sole stockholder of our general partner. At December 31, 2001, KMI directly
owned 13,047,300 common units and 5,313,400 class B units, indirectly owned
6,736,326 common units owned by its consolidated affiliates, including our
general partner, and owned 5,956,946 KMR shares, representing an indirect
ownership interest of 5,956,946 i-units. These units represent approximately
18.7% of our outstanding limited partner units.

  Kinder Morgan Management, LLC

     KMR, our general partner's delegate, remains the sole owner of our
30,636,363 i-units.

  ASSET ACQUISITIONS

     Effective December 31, 1999, we acquired over $935.8 million of assets from
KMI. As consideration for the assets, we paid to KMI $330 million and 19,620,000
common units, valued at approximately $406.3 million. In addition, we assumed
$40.3 million in debt and approximately $121.6 million in liabilities. We
acquired Kinder Morgan Interstate Gas Transmission LLC (formerly K N Interstate
Gas Transmission Co.), a 33 1/3% interest in Trailblazer Pipeline Company and a
49% equity interest in Red Cedar Gathering Company. The acquired interest in
Trailblazer Pipeline Company, when combined with the interest purchased on
November 30, 1999, gave us a 66 2/3% ownership interest.

     Effective December 31, 2000, we acquired over $621.7 million of assets from
KMI. As consideration for these assets, we paid to KMI $192.7 million in cash
and approximately $156.3 million in units, consisting of 1,280,000 common units
and 5,313,400 class B units. We also assumed liabilities of approximately $272.7
million. We acquired Kinder Morgan Texas Pipeline, L.P. and MidCon NGL Corp.
(both of which were converted to single-member limited liability companies), the
Casper and Douglas natural gas gathering and processing systems, a 50% interest
in Coyote Gas Treating, LLC and a 25% interest in Thunder Creek Gas Services,
LLC. The purchase price for the transaction was determined by the boards of
directors of KMI and our general partner based on pricing principles used in the
acquisition of similar assets as well as a fairness opinion from the investment
banking firm A.G. Edwards & Sons, Inc.

  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 two separate agreements, one entered into December 31, 1999,
between KMI and Kinder Morgan Interstate Gas Transmission LLC, and one entered
into December 31, 2000, between KMI and Kinder Morgan Operating L.P. "A". Both
agreements have five-year terms and contain automatic five-year extensions.
Under these agreements, Kinder Morgan Interstate Gas Transmission LLC and Kinder
Morgan Operating L.P. "A" pay KMI a fixed amount as reimbursement for the
corporate general and administrative costs incurred in connection with the
operation of these assets. The amounts paid to KMI under these agreements for
corporate general and administrative costs were $9.5 million for 2001 and $6.1
million for 2000. For 2002, the amount will decrease to $8.6 million. Although
we believe the amounts paid to KMI for the services they provided each year
fairly reflect the value of the services performed, the determination of these
amounts were not the result of arms length negotiations. However, due to the
nature of the allocations, these reimbursements may not have exactly matched the
actual time and overhead spent. We believe the agreed-upon amounts were, at the
time the contracts were entered into, a reasonable estimate of the corporate
general and administrative expenses to be incurred by KMI and its

                                       116
<PAGE>

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.

  OTHER

     Generally, KMR makes all decisions relating to the management and control
of our business. Our general partner owns all of KMR's voting securities and is
its sole managing member. KMI, through its wholly owned and controlled
subsidiary Kinder Morgan (Delaware), Inc., owns all the common stock of our
general partner. Certain conflicts of interest could arise as a result of the
relationships among KMR, our general partner, KMI and us. The directors and
officers of KMI have fiduciary duties to manage KMI, including selection and
management of its investments in its subsidiaries and affiliates, in a manner
beneficial to the shareholders of KMI. In general, KMR has a fiduciary duty to
manage us in a manner beneficial to our unitholders. The partnership agreements
for us and our operating partnerships contain provisions that allow KMR to take
into account the interests of parties in addition to us in resolving conflicts
of interest, thereby limiting its fiduciary duty to our unitholders, as well as
provisions that may restrict the remedies available to unitholders for actions
taken that might, without such limitations, constitute breaches of fiduciary
duty. 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.

13.  LEASES AND COMMITMENTS

     We have entered into certain operating leases. Including probable elections
to exercise renewal options, the remaining terms on our leases range from one to
42 years. Future commitments related to these leases at December 31, 2001 are as
follows (in thousands):

<Table>
<S>                                                           <C>
2002........................................................  $ 16,735
2003........................................................    14,702
2004........................................................    12,133
2005........................................................    11,019
2006........................................................    10,798
Thereafter..................................................    68,793
                                                              --------
Total minimum payments......................................  $134,180
                                                              ========
</Table>

     We have not reduced our total minimum payments for future minimum sublease
rentals aggregating approximately $2.2 million. Total lease and rental expenses,
including related variable charges were $41.1 million for 2001, $7.5 million for
2000 and $8.8 million for 1999.

     During 1998, we established a common unit option plan, which provides that
key personnel are eligible to receive grants of options to acquire common units.
The number of common units available under the option plan is 500,000. The
option plan terminates in March 2008. As of December 31, 2001, outstanding
options for 379,400 common units were granted to certain personnel with a term
of seven years at exercise prices equal to the market price of the common units
at the grant date. In addition, as of December 31, 2001, outstanding options for
30,000 common units were granted to our three non-employee directors. The
options granted generally vest 40% in the first year and 20% each year
thereafter.

     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. 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. No compensation expense
has been recorded since the options were granted at exercise prices equal to the
market prices at the date of grant.

                                       117
<PAGE>

     Effective January 17, 2002, our general partner entered into a retention
agreement with C. Park Shaper, an officer of our general partner and its
delegate. Pursuant to the terms of the agreement, Mr. Shaper received a $5
million personal loan guaranteed by us. Mr. Shaper was required to purchase KMI
common shares and our common units in the open market with the loan proceeds. If
he voluntarily leaves us prior to the end of five years, then he must repay the
entire loan. After five years, provided Mr. Shaper has continued to be employed
by our general partner, we and KMI will assume Mr. Shaper's obligations under
the loan. The agreement contains provisions that address termination for cause,
death, disability and change of control.

     We have an Executive Compensation Plan for certain executive officers of
our general partner. We may, at our option and with the approval of our
unitholders, pay the participants in units instead of cash. Eligible awards are
equal to a percentage of an incentive compensation value, which is equal to a
formula based upon the cash distributions paid to our general partner during the
four calendar quarters preceding the date of redemption multiplied by eight. The
amount of these awards are accrued as compensation expense and adjusted
quarterly. Under the plan, no eligible employee may receive a grant in excess of
2% of the incentive compensation value and total awards under the plan may not
exceed 10% of the incentive compensation value. The plan terminates January 1,
2007, and any unredeemed awards will be automatically redeemed. At December 31,
2001, there were no outstanding awards granted under our Executive Compensation
Plan.

14.  RISK MANAGEMENT

  HEDGING ACTIVITIES

     Our normal business activities expose us to risks associated with changes
in the market price of natural gas and associated transportation, natural gas
liquids, crude oil and carbon dioxide. Through KMI, we use energy financial
instruments to reduce our risk of price changes in the spot and fixed price of
natural gas, natural gas liquids and crude oil markets as discussed below. We
are exposed to credit-related losses in the event of nonperformance by
counterparties to these financial instruments but, given their existing credit
ratings, we do not expect any counterparties to fail to meet their obligations.
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.

     The energy risk management products that we use include:

     - commodity futures and options contracts;

     - fixed-price swaps; and

     - basis swaps.

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

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

     - gas purchases; and

     - 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 KMI's Risk Management Committee, which is charged with the
review and enforcement of our management's risk management policy.

                                       118
<PAGE>

     Effective January 1, 2001, we adopted Statement of Financial Accounting
Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities" as amended by Statement of Financial Accounting Standards 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. As a
result of our adoption of SFAS No. 133, 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.

     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 $20.0 million at
December 31, 2001 and $7.0 million on December 31, 2000. Our margin deposits
associated with over-the-counter swap partners were ($42.1) million on December
31, 2001 and $0.0 on December 31, 2000.

     We recognized approximately $1.3 million net in earnings as a loss during
2001 as a result of ineffective hedges, which amount is reported within the
caption "Operations and maintenance" in the accompanying Consolidated Statements
of Income. We did not exclude any component of the derivative instruments' gain
or loss from the assessment of hedge effectiveness.

     We reclassify the gains and losses included in accumulated other
comprehensive income into earnings as the hedged sales and purchases take place.
We expect to reclassify approximately $45.4 million of the accumulated other
comprehensive income balance of $63.8 million representing unrecognized net
gains on derivative activities at December 31, 2001 into earnings during the
next twelve months. During 2001, we did not reclassify any gains or losses 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.

     The differences between the current market value and the original physical
contracts value associated with hedging activities are primarily reflected as
other current assets and accrued other current liabilities in the accompanying
consolidated balance sheet at December 31, 2001. At December 31, 2001, our
balance of $194.9 million of other current assets includes approximately $163.7
million related to risk management activities, and our balance of $209.9 million
of accrued other current liabilities includes approximately $117.8 million
related to risk management activities. The remaining differences between the
current market value and the original physical contracts value associated with
hedging activities are reflected as deferred charges or deferred credits in the
accompanying consolidated balance sheet at December 31, 2001. Prior to 2001, we
accounted for gain/loss on our over the counter swaps and marked our open
futures position to market value. Such items were deferred on the balance sheet
and reflected in current receivables, other current assets, accrued other
current liabilities, deferred charges or deferred credits in the accompanying
consolidated balance sheet at December 31, 2000. These deferrals are offset by
the corresponding value of the underlying physical transactions. In the event
energy financial instruments are terminated prior to the period of physical
delivery of the items being hedged, the gains and losses on the energy financial
instruments at the time of termination remain deferred until the period of
physical delivery.

                                       119
<PAGE>

     Given our portfolio of businesses as of December 31, 2001, our principal
uses of derivative financial instruments will be to mitigate the risk associated
with market movements in the price of energy commodities. Our short natural gas
derivatives position primarily represents our hedging of anticipated future
natural gas sales. Our short crude oil derivatives position represents our crude
oil derivative sales made to hedge anticipated oil sales. In addition, crude oil
contracts have been sold to hedge anticipated carbon dioxide sales that have
pricing tied to crude oil prices. Finally, our short natural gas liquids
derivatives position reflects the hedging of our forecasted natural gas liquids
sales.

     As of December 31, 2001, 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............................  $ 20,957    $   35,901   $   56,858
Contract Amounts -- Gross...........................  $339,456    $1,436,291   $1,775,747
Contract Amounts -- Net.............................  $(90,036)   $ (227,979)  $ (318,015)

                                                           (NUMBER OF CONTRACTS(1))
Natural Gas
  Notional Volumetric Positions: Long...............     3,687         1,688        5,375
  Notional Volumetric Positions: Short..............    (4,851)       (1,980)      (6,831)
  Net Notional Totals to Occur in 2002..............      (964)          (20)        (984)
  Net Notional Totals to Occur in 2003 and Beyond...      (200)         (271)        (471)
Crude Oil
  Notional Volumetric Positions: Long...............       140           116          256
  Notional Volumetric Positions: Short..............    (1,947)         (583)      (2,530)
  Net Notional Totals to Occur in 2002..............    (1,360)         (186)      (1,546)
  Net Notional Totals to Occur in 2003 and Beyond...      (447)         (281)        (728)
Natural Gas Liquids
  Notional Volumetric Positions: Long...............        --            55           55
  Notional Volumetric Positions: Short..............        --        (1,258)      (1,258)
  Net Notional Totals to Occur in 2002..............        --          (626)        (626)
  Net Notional Totals to Occur in 2003 and Beyond...        --          (577)        (577)
</Table>

---------------
(1) A term of reference describing a unit of commodity trading. One natural gas
    contract equals 10,000 MMBtus. One crude oil or natural gas liquids contract
    equals 1,000 barrels.

     Our over-the-counter swaps and options are with a number of parties, each
of which is an investment grade credit. We both owe money and are owed money
under these financial instruments. At December 31, 2001, if all parties owing us
failed to pay us amounts due under these arrangements, our credit loss would be
$23.2 million. At December 31, 2001, our largest credit exposure to a single
counterparty was $4.5 million.

     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:

     - ceased to account for those derivatives as hedges;

     - entered into new derivative transactions with other counterparties to
       replace our position with Enron;

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

                                       120
<PAGE>

     - recognized a $6.0 million loss (included with "General and
       administrative" expenses in the 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.

     While we enter into derivative transactions only with investment grade
counterparties and actively monitor their credit ratings, it is nevertheless
possible that additional losses will result from counterparty credit risk in the
future.

  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. Since
August 1998, we have entered into interest rate swap agreements for the purpose
of hedging the interest rate risk associated with our variable rate debt
obligations. In the third quarter of 2001, we elected to adjust our mix to be
closer to our target ratio of 50% fixed rate debt and 50% variable rate debt.
Accordingly, in August 2001, we entered into interest rate swap agreements with
a notional principal amount of $750 million for the purpose of hedging the
interest rate risk associated with our fixed rate debt obligations. These
agreements effectively convert 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:

     - 8.0% senior notes due March 15, 2005;

     - 6.30% senior notes due February 1, 2009; and

     - 7.40% senior notes due March 15, 2031.

     The swap agreements for our 8.0% senior notes and 6.30% senior notes have
terms that correspond to the maturity dates of such series. The swap agreement
for our 7.40% senior notes contains mutual cash-out agreements at the
then-current economic value every seven years. As of December 31, 2001, we were
party to interest rate swap agreements with a total notional principal amount of
$900 million.

     These swaps have been designated as fair value hedges as defined by SFAS
No. 133. These swaps also 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 will 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 will record interest expense
equal to the variable rate payments, which will be accrued monthly and paid
semi-annually. At December 31, 2001, we recognized a liability of $5.4 million
for the net fair value of our swap agreements and we included this amount with
Other Long-Term Liabilities and Deferred Credits on the accompanying balance
sheet.

15.  REPORTABLE SEGMENTS

     We compete in four reportable business segments (see Note 1):

     - Products Pipelines;

     - Natural Gas Pipelines;

     - CO(2) Pipelines; and

     - Terminals.

     Each segment uses the same accounting policies as those described in the
summary of significant accounting policies (see Note 2). We evaluate performance
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.

                                       121
<PAGE>

     Our Products Pipelines segment derives its revenues primarily from the
transportation 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 gathering and transmission of natural gas. Our CO(2)
Pipelines segment derives its revenues primarily from the marketing and
transportation of carbon dioxide used as a flooding medium for recovering crude
oil from mature oil fields. Our Terminals segment derives its revenues primarily
from the transloading and storing of refined petroleum products and dry and
liquid bulk products, including coal, petroleum coke, cement, alumina, salt, and
chemicals.

     Financial information by segment follows (in thousands):

<Table>
<Caption>
                                                      2001         2000         1999
                                                   ----------   ----------   ----------
<S>                                                <C>          <C>          <C>
Revenues
  Product Pipelines..............................  $  605,392   $  420,272   $  313,017
  Natural Gas Pipelines..........................   1,869,315      174,187        1,096
  CO(2) Pipelines................................     122,094       89,214           23
  Terminals......................................     349,875      132,769      114,613
                                                   ----------   ----------   ----------
  Total consolidated revenues....................  $2,946,676   $  816,442   $  428,749
                                                   ==========   ==========   ==========
Operating income
  Product Pipelines..............................  $  295,288   $  193,424   $  185,998
  Natural Gas Pipelines..........................     171,811       97,305           88
  CO(2) Pipelines................................      59,295       47,901           18
  Terminals......................................     136,443       36,996       36,917
                                                   ----------   ----------   ----------
  Total segment operating income.................     662,837      375,626      223,021
  Corporate administrative expenses..............     (99,009)     (60,065)     (35,614)
                                                   ----------   ----------   ----------
  Total consolidated operating Income............  $  563,828   $  315,561   $  187,407
                                                   ==========   ==========   ==========
Earnings from equity investments, net of amortization of excess costs
  Product Pipelines..............................  $   22,686   $   29,105   $   21,395
  Natural Gas Pipelines..........................      21,156       14,975        2,759
  CO(2) Pipelines................................      31,981       19,328       14,487
  Terminals......................................          --           --           23
                                                   ----------   ----------   ----------
  Consolidated equity earnings, net of
     amortization................................  $   75,823   $   63,408   $   38,664
                                                   ==========   ==========   ==========
</Table>

<Table>
<Caption>
                                                      2001         2000         1999
                                                   ----------   ----------   ----------
<S>                                                <C>          <C>          <C>
Interest revenue
  Product Pipelines..............................  $       --   $       --   $       --
  Natural Gas Pipelines..........................          --           --           --
  CO(2) Pipelines................................          --           --           --
  Terminals......................................          --           --           --
                                                   ----------   ----------   ----------
  Total segment interest revenue.................          --           --           --
  Unallocated interest revenue...................       4,473        3,818        1,731
                                                   ----------   ----------   ----------
  Total consolidated interest revenue............  $    4,473   $    3,818   $    1,731
                                                   ==========   ==========   ==========
</Table>

                                       122
<PAGE>

<Table>
<Caption>
                                                      2001         2000         1999
                                                   ----------   ----------   ----------
<S>                                                <C>          <C>          <C>
Interest (expense)
  Product Pipelines..............................  $       --   $       --   $       --
  Natural Gas Pipelines..........................          --           --           --
  CO(2) Pipelines................................          --           --           --
  Terminals......................................          --           --           --
                                                   ----------   ----------   ----------
  Total segment interest (expense)...............          --           --           --
  Unallocated interest (expense).................    (175,930)     (97,102)     (54,336)
                                                   ----------   ----------   ----------
  Total consolidated interest (expense)..........  $ (175,930)  $  (97,102)  $  (54,336)
                                                   ==========   ==========   ==========
Other, net
  Product Pipelines..............................  $      440   $   10,492   $    9,948
  Natural Gas Pipelines..........................         749          744       14,159
  CO(2) Pipelines................................         547          741          710
  Terminals......................................         226        2,607         (669)
                                                   ----------   ----------   ----------
  Total consolidated other, net..................  $    1,962   $   14,584   $   24,148
                                                   ==========   ==========   ==========
Income tax benefit (expense)
  Product Pipelines..............................  $   (9,653)  $  (11,960)  $   (8,493)
  Natural Gas Pipelines..........................          --           --          (45)
  CO(2) Pipelines................................          --           --           --
  Terminals......................................      (6,720)      (1,974)      (1,288)
                                                   ----------   ----------   ----------
  Total consolidated income tax benefit
     (expense)...................................  $  (16,373)  $  (13,934)  $   (9,826)
                                                   ==========   ==========   ==========
Segment earnings
  Product Pipelines..............................  $  308,761   $  221,061   $  208,848
  Natural Gas Pipelines..........................     193,716      113,024       16,961
  CO(2) Pipelines................................      91,823       67,970       15,215
  Terminals......................................     129,949       37,629       34,983
                                                   ----------   ----------   ----------
  Total segment earnings.........................     724,249      439,684      276,007
  Interest and corporate administrative
     expenses(a).................................    (281,906)    (161,336)     (93,705)
                                                   ----------   ----------   ----------
  Total consolidated net income..................  $  442,343   $  278,348   $  182,302
                                                   ==========   ==========   ==========
</Table>

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

(a)  Includes interest and debt expense, general and administrative expenses,
     minority interest expense, extraordinary charges and other insignificant
     items.

<Table>
<Caption>
                                                      2001         2000         1999
                                                   ----------   ----------   ----------
<S>                                                <C>          <C>          <C>
Assets at December 31
  Product Pipelines..............................  $3,095,899   $2,220,984   $2,007,050
  Natural Gas Pipelines..........................   2,058,836    1,552,506      888,021
  CO(2) Pipelines................................     503,565      417,278       86,684
  Terminals......................................     990,760      357,689      203,601
                                                   ----------   ----------   ----------
  Total segment assets...........................   6,649,060    4,548,457    3,185,356
  Corporate assets(a)............................      83,606       76,753       43,382
                                                   ----------   ----------   ----------
  Total consolidated assets......................  $6,732,666   $4,625,210   $3,228,738
                                                   ==========   ==========   ==========
</Table>

                                       123
<PAGE>

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

(a)  Includes cash, cash equivalents and certain unallocable deferred charges.

<Table>
<S>                                                <C>          <C>          <C>
Depreciation and amortization
  Product Pipelines..............................  $   65,864   $   40,730   $   37,999
  Natural Gas Pipelines..........................      31,564       21,709          929
  CO(2) Pipelines................................      17,562       10,559           --
  Terminals......................................      27,087        9,632        7,541
                                                   ----------   ----------   ----------
  Total consolidated depreciation and
     amortization................................  $  142,077   $   82,630   $   46,469
                                                   ==========   ==========   ==========
Equity Investments at December 31
  Product Pipelines..............................  $  225,561   $  231,651   $  243,668
  Natural Gas Pipelines..........................     146,566      141,613       88,249
  CO(2) Pipelines................................      68,232        9,559       86,675
  Terminals......................................         159           59           59
                                                   ----------   ----------   ----------
  Total consolidated equity investments..........     440,518      382,882      418,651
Investment in oil and gas assets to be
  contributed to joint venture...................          --       34,163           --
                                                   ----------   ----------   ----------
                                                   $  440,518   $  417,045   $  418,651
                                                   ==========   ==========   ==========
Capital expenditures
  Product Pipelines..............................  $   84,709   $   69,243   $   68,674
  Natural Gas Pipelines..........................      86,124       14,496           --
  CO(2) Pipelines................................      65,778       16,115           --
  Terminals......................................      58,477       25,669       14,051
                                                   ----------   ----------   ----------
  Total consolidated capital expenditures........  $  295,088   $  125,523   $   82,725
                                                   ==========   ==========   ==========
</Table>

     Our total operating revenues are derived from a wide customer base. For the
year ended December 31, 2001, one customer accounted for more than 10% of our
total consolidated revenues. Total transactions with Reliant Energy, within our
Natural Gas Pipelines and Terminals segments, accounted for 20.2% of our total
consolidated revenues during 2001. For each of the two years ending December 31,
2000 and 1999, no revenues from transactions with a single external customer
amounted to 10% or more of our total consolidated revenues.

16.  LITIGATION AND OTHER CONTINGENCIES

     The tariffs charged for interstate common carrier pipeline transportation
for our pipelines are subject to rate regulation by the Federal Energy
Regulatory Commission ("FERC") under the Interstate Commerce Act. The Interstate
Commerce Act requires, among other things, that petroleum products pipeline
rates be just and reasonable and non-discriminatory. Pursuant to FERC Order No.
561, effective January 1, 1995, 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 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, 2001, 2000 and 1999,
the application of the indexing methodology did not significantly affect our
tariff rates.

                                       124
<PAGE>

  FEDERAL ENERGY REGULATORY COMMISSION PROCEEDINGS

  SFPP, L.P.

     SFPP, L.P. is the subsidiary limited partnership that owns our Pacific
operations, excluding the CALNEV pipeline and related terminals acquired from
GATX Corporation. Tariffs charged by SFPP are subject to certain proceedings
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. In September 1992, El Paso Refinery,
L.P. filed a protest/complaint with the FERC:

     - challenging SFPP's East Line rates from El Paso, Texas to Tucson and
       Phoenix, Arizona;

     - challenging SFPP's proration policy; and

     - seeking to block the reversal of the direction of flow of SFPP's six-inch
       pipeline between Phoenix and Tucson.

     At various dates following El Paso Refinery's September 1992 filing, other
shippers on SFPP's South System filed separate complaints, and/or motions to
intervene in the FERC proceeding, challenging SFPP's rates on its East and West
Lines. These shippers include:

     - Chevron U.S.A. Products Company;

     - Navajo Refining Company;

     - ARCO Products Company;

     - Texaco Refining and Marketing Inc.;

     - Refinery Holding Company, L.P. (a partnership formed by El Paso
       Refinery's long-term secured creditors that purchased its refinery in May
       1993);

     - Mobil Oil Corporation; and

     - Tosco Corporation.

     Certain of these parties also claimed that a gathering enhancement charge
at SFPP's Watson origin pump station in Carson, California was charged in
violation of the Interstate Commerce Act. In subsequent procedural rulings, the
FERC consolidated these challenges (Docket Nos. OR92-8-000, et al.) and ruled
that they must proceed as a complaint proceeding, with the burden of proof being
placed on the complaining parties. These parties must show that SFPP's rates and
practices at issue violate the requirements of the Interstate Commerce Act.

     Hearings in the FERC proceeding were held in 1996 and an initial decision
by the FERC administrative law judge was issued on September 25, 1997. The
initial decision upheld SFPP's position that "changed circumstances" were not
shown to exist on the West Line, thereby retaining the just and reasonable
status of all West Line rates that were "grandfathered" under the Energy Policy
Act of 1992. Accordingly, the administrative law judge ruled that these rates
are not subject to challenge, either for the past or prospectively, in that
proceeding. The administrative law judge's decision specifically excepted from
that ruling SFPP's Tariff No. 18 for movement of jet fuel from Los Angeles to
Tucson, which was initiated subsequent to the enactment of the Energy Policy
Act.

     The initial decision also included rulings that were generally adverse to
SFPP on such cost of service issues as:

     - the capital structure to be used in computing SFPP's 1985 starting rate
       base under FERC Opinion 154-B;

     - the level of income tax allowance; and

     - the recoverability of civil and regulatory litigation expense and certain
       pipeline reconditioning costs.

                                       125
<PAGE>

     The administrative law judge also ruled that the gathering enhancement
service at SFPP's Watson origin pump station was subject to FERC jurisdiction
and ordered that a tariff for that service and supporting cost of service
documentation be filed no later than 60 days after a final FERC order on this
matter.

     On January 13, 1999, the FERC issued its Opinion No. 435, which affirmed in
part and modified in part the initial decision. In Opinion No. 435, the FERC
ruled that all but one of the West Line rates are "grandfathered" as just and
reasonable and that "changed circumstances" had not been shown to satisfy the
complainants' threshold burden necessary to challenge those rates. The FERC
further held that the one "non-grandfathered" West Line tariff did not require
rate reduction. Accordingly, the FERC dismissed all complaints against the West
Line rates without any requirement that SFPP reduce, or pay any reparations for,
any West Line rate.

     With respect to the East Line rates, Opinion No. 435 reversed in part and
affirmed in part the initial decision's ruling regarding the methodology for
calculating the rate base for the East Line. Opinion No. 435 modified the
initial decision concerning the date on which the starting rate base should be
calculated and the accumulated deferred income tax and allowable cost of equity
used to calculate the rate base. In addition, Opinion No. 435 ruled that SFPP
would not owe reparations to any complainant for any period prior to the date on
which that complainant's complaint was filed, thus reducing by two years the
potential reparations period claimed by most complainants. On January 19, 1999,
ARCO filed a petition with the United States Court of Appeals for the District
of Columbia Circuit for review of Opinion No. 435. Additional petitions for
review were thereafter filed in that court by RHC, Navajo, Chevron and SFPP.

     SFPP and certain complainants each sought rehearing of Opinion No. 435 by
the FERC, asking that a number of rulings be modified. In compliance with
Opinion No. 435, on March 15, 1999, SFPP submitted a compliance filing
implementing the rulings made by FERC, establishing the level of rates to be
charged by SFPP in the future, and setting forth the amount of reparations owed
by SFPP to the complainants under the order. The complainants contested SFPP's
compliance filing.

     On July 6, 1999, in response to a motion by the FERC, the Court of Appeals
held the ARCO and RHC petitions in abeyance pending FERC action on petitions for
rehearing of Opinion No. 435 and dismissed the Navajo, Chevron and SFPP
petitions as premature because those parties had sought FERC rehearing.

     On May 17, 2000, the FERC issued its Opinion No. 435-A, which ruled on the
requests for rehearing and modified Opinion No. 435 in certain respects. It
denied requests to reverse its prior rulings that SFPP's West Line rates and
Watson Station gathering enhancement facilities charge are entitled to be
treated as just and reasonable "grandfathered" rates under the Energy Policy
Act. It suggested, however, that if SFPP had fully recovered the capital costs
of the Watson Station facilities, that might form the basis of an amended
"changed circumstances" complaint.

     Opinion No. 435-A granted a request by Chevron and Navajo to require that
SFPP's December 1988 partnership capital structure be used to compute the
starting rate base from December 1983 forward, as well as a request by SFPP to
vacate a ruling that would have required the elimination of approximately $125
million from the rate base used to determine capital structure. It also granted
two clarifications sought by Navajo, to the effect that SFPP's return on its
starting rate base should be based on SFPP's capital structure in each given
year (rather than a single capital structure from the outset) and that the
return on deferred equity should also vary with the capital structure for each
year. Opinion No. 435-A denied the request of Chevron and Navajo that no income
tax allowance be recognized for the limited partnership interests held by SFPP's
corporate parent, as well as SFPP's request that the tax allowance should
include interests owned by certain non-corporate entities. However, it granted
Navajo's request to make the computation of interest expense for tax allowance
purposes the same as the computation for debt return.

                                       126
<PAGE>

     Opinion No. 435-A reaffirmed that SFPP may recover certain litigation costs
incurred in defense of its rates (amortized over five years), but reversed a
ruling that those expenses may include the costs of certain civil litigation
between SFPP and Navajo and El Paso. It also reversed a prior decision that
litigation costs should be allocated between the East and West Lines based on
throughput, and instead adopted SFPP's position that such expenses should be
split equally between the two systems.

     As to reparations, Opinion No. 435-A held that no reparations would be
awarded to West Line shippers and that only Navajo was eligible to recover
reparations on the East Line. It reaffirmed that a 1989 settlement with SFPP
barred Navajo from obtaining reparations prior to November 23, 1993, but allowed
Navajo reparations for a one-month period prior to the filing of its December
23, 1993 complaint. Opinion No. 435-A also confirmed that FERC's indexing
methodology should be used in determining rates for reparations purposes and
made certain clarifications sought by Navajo.

     Opinion No. 435-A denied Chevron's request for modification of SFPP's
prorationing policy. This policy requires customers to demonstrate a need for
additional capacity if a shortage of available pipeline space exits.

     Finally, Opinion No. 435-A directed SFPP to revise its initial compliance
filings to reflect the modified rulings. It eliminated the refund obligation for
the compliance tariff containing the Watson Station gathering enhancement
charge, but required SFPP to pay refunds to the extent that the compliance
tariff East Line rates are higher than the rates produced under Opinion No.
435-A.

     In June 2000, several parties filed requests for rehearing of certain
rulings made in Opinion No. 435-A. Chevron and RHC both sought reconsideration
of the FERC's ruling that only Navajo is entitled to reparations for East Line
shipments. SFPP sought rehearing of the FERC's:

     - decision to require use of the December 1988 partnership capital
       structure for the period 1994-98 in computing the starting rate base;

     - elimination of civil litigation costs;

     - refusal to allow any recovery of civil litigation settlement payments;
       and

     - failure to provide any allowance for regulatory expenses in prospective
       rates.

     ARCO, Chevron, Navajo, RHC, Texaco and SFPP sought judicial review of
Opinion No. 435-A in the United States Court of Appeals for the District of
Columbia Circuit. The FERC moved to:

     - consolidate those petitions with prior ARCO and RHC petitions to review
       Opinion No. 435;

     - dismiss the Chevron, RHC and SFPP petitions; and

     - hold the other petitions in abeyance pending ruling on the requests for
       rehearing of Opinion No. 435-A.

     On July 17, 2000, SFPP submitted a compliance filing implementing the
rulings made in Opinion No. 435-A, together with a calculation of reparations
due to Navajo and refunds due to other East Line shippers. SFPP also filed a
tariff containing East Line rates based on those rulings. On August 16, 2000,
the FERC directed SFPP to supplement its compliance filing by providing certain
underlying workpapers and information; SFPP responded to that order on August
31, 2000.

     On September 19, 2000, the Court of Appeals dismissed Chevron's petition
for lack of prosecution, and the court in an order issued January 19, 2001
denied a November 2, 2000 motion by Chevron for reconsideration of that
dismissal. On October 20, 2000, the court dismissed the petitions for review
filed by SFPP and RHC as premature in light of their pending requests for FERC
rehearing, consolidated the ARCO, Navajo and Texaco petitions for review with
the petitions for review of Opinion No. 435, and ordered that proceedings be
held in abeyance until after FERC action on the rehearing requests.

     Pursuant to the Court's orders, the FERC has filed quarterly reports
regarding the status of the proceedings pending before the Commission. On May
14, 2001, ARCO filed an Answer and Protest to the

                                       127
<PAGE>

FERC's May 4, 2001 status report, requesting the Court of Appeals to reactivate
the petitions for review that are being held in abeyance and to initiate a
briefing schedule. On May 24, 2001, the FERC filed an opposition to that motion.

     On July 6, 2001, ARCO, Chevron, Mobil, Navajo, RHC and Texaco filed a joint
motion asking the FERC to expedite its action on their requests for rehearing,
correction and clarification of Opinion No. 435-A and on SFPP's compliance
filing and related protests. Ultramar filed a similar motion on July 10, 2001.
On July 30, 2001, the Court of Appeals issued an order denying ARCO's motion
without prejudice and directing the FERC to advise the Court in its next status
report as to when the FERC expects to take final action with respect to the
proceedings on rehearing. On August 2, 2001, the FERC filed a status report
advising the Court that it intended to present the pending requests for
rehearing of Opinion No. 435-A for consideration at the FERC's meeting scheduled
for September 12, 2001.

     On September 13, 2001, the FERC issued Opinion No. 435-B ("Opinion on
Rehearing and Directing Revised Compliance Filing"), which ruled on pending
requests for rehearing and comments on SFPP's compliance filing implementing
Opinion No. 435-A. Based on those rulings, the FERC directed SFPP to submit a
revised compliance filing, including revised tariffs and revised estimates of
reparations and refunds, by November 12, 2001.

     Opinion No. 435-B denied SFPP's requests for rehearing, which involved the
capital structure to be used in computing starting rate base, SFPP's ability to
recover litigation and settlement costs incurred in connection with the Navajo
and El Paso civil litigation and the need for provision for regulatory costs in
prospective rates. The decision also made modifications to the Commission's
prior rulings on several other issues. In particular, Opinion No. 435-B reversed
Opinion No. 435-A's ruling that Navajo was the sole party entitled to
reparations, holding instead that Chevron, RHC, Tosco and Mobil are also
eligible to recover reparations for East Line shipments. However, Opinion No.
435-B held that Ultramar is not eligible for reparations in the proceedings in
which Opinions No. 435, 435-A and 435-B were issued.

     The decision also changed prior FERC rulings permitting SFPP to apply
certain litigation, environmental and pipeline rehabilitation costs that were
not recovered through the prescribed rates to offset overearnings (and potential
reparations) and to recover any such costs that remained by means of a surcharge
to shippers. In Opinion No. 435-B, the FERC required SFPP to pay reparations to
each complainant without any offset for unrecovered costs. It went on to require
that SFPP subtract from the total 1995-1998 supplemental costs allowed under
Opinion No. 435-A any overearnings that are not paid out as reparations, and
allowed SFPP to recover any remaining costs from shippers by means of a
five-year surcharge beginning on August 1, 2000. Opinion No. 435-B also ruled
that SFPP would only be permitted to recover certain regulatory litigation costs
through the surcharge and that the surcharge could not recover environmental or
pipeline rehabilitation costs.

     Opinion No. 435-B granted requests for late intervention as to the
compliance filing review by Texaco, ARCO, Ultramar and Tosco; in addition,
Navajo had made a timely intervention. On review, the FERC directed SFPP to make
several changes in its revised compliance filing, including requiring SFPP to:

     - use a remaining useful life of 16.8 years in amortizing its starting rate
       base, instead of the 20.6 year period previously used;

     - remove the starting rate base component from its base rates as of August
       1, 2001;

     - amortize its accumulated deferred income tax balance beginning in 1992,
       rather than 1988;

     - list the corporate unitholders that were the basis for the income tax
       allowance claimed in its compliance filing and certify that those
       companies are not Subchapter S corporations; and

     - "clearly exclude" civil litigation costs from its compliance filing and
       explain how it has limited litigation costs to FERC-related expenses and
       assigned them to appropriate periods in making reparations calculations.

                                       128
<PAGE>

     On October 15, 2001, Chevron and RHC filed petitions for rehearing of
Opinion No. 435-B. Chevron's petition asks the FERC to clarify:

     - the period for which Chevron is entitled to reparations; and

     - whether East Line shippers that have received the benefit of
       Commission-prescribed rates for 1994 and subsequent years must show that
       there has been a substantial divergence between the cost of service and
       the change in the Commission's rate index in order to have standing to
       challenge SFPP rates for those years in pending or subsequent
       proceedings.

     RHC's petition contends that Opinion No. 435-B erred, and should be
modified on rehearing, to the extent it:

     - suggests that a "substantial divergence" standard applies to complaint
       proceedings, subsequent to those that led to Opinion No. 435-B,
       challenging the total level of SFPP's East Line rates;

     - requires a substantial divergence to be shown between SFPP's cost of
       service and the change in the FERC oil pipeline index in such subsequent
       complaint proceedings, rather than a substantial divergence between the
       cost of service and SFPP's revenues; and

     - permits SFPP to recover 1993 rate case litigation expenses through a
       surcharge mechanism.

     ARCO, Ultramar and SFPP filed petitions seeking judicial review of Opinion
No. 435-B (and in SFPP's case, Opinion Nos. 435 and 435-A) in the U.S. Court of
Appeals for the District of Columbia Circuit. The Court has consolidated the
Ultramar and SFPP petitions with the consolidated cases that had been held in
abeyance and has ordered that the consolidated cases be returned to its active
docket. On October 24, 2001, the FERC filed a motion asking the court to
consolidate ARCO's petition for review of Opinion No. 435-B as well and to hold
the consolidated cases in abeyance pending FERC action on the Chevron and RHC
petitions for rehearing.

     On November 7, 2001, the FERC issued an order ruling on the Chevron and RHC
petitions for rehearing of Opinion No. 435-B. The Commission held that Chevron's
eligibility for reparations should be measured from August 3, 1993, rather than
September 23, 1992, as Chevron had sought. The Commission also clarified its
prior ruling with respect to the "substantial divergence" test, holding that in
order to be considered on the merits, complaints challenging the SFPP rates set
by applying the Commission's indexing regulations to the 1994 cost of service
derived under the Opinion No. 435 series of orders must demonstrate a
substantial divergence between the indexed rates and the pipeline's actual cost
of service. Finally, the FERC granted rehearing to hold that SFPP's 1993
regulatory costs should not be included in the surcharge permitted for the
recovery of supplemental costs.

     On December 7, 2001, Chevron filed a petition for rehearing of the FERC's
November 7, 2001 order. The petition requested the Commission to specify whether
Chevron would be entitled to reparations for the two year period prior to the
August 3, 1993 filing of its complaint.

     On January 7, 2002, SFPP and RHC filed petitions in the U.S. Court of
Appeals for the District of Columbia Circuit for review of the FERC's November
7, 2001 order. On January 8, 2002, the Court consolidated those petitions with
the petitions for review of Opinion Nos. 435, 435-A and 435-B. On January 24,
2002, the Court of Appeals ordered the consolidated proceedings to be held in
abeyance until the FERC acts on the pending request for rehearing of the
November 7, 2001 order.

     SFPP submitted its compliance filing and tariffs implementing Opinion No.
435-B and the Commission's November 7, 2001 order on November 20, 2001. Motions
to intervene and protest were subsequently filed by ARCO, Mobil (which now
submits filings under the name ExxonMobil), RHC, Navajo and Chevron, alleging
that SFPP:

     - should have calculated the supplemental cost surcharge differently;

     - did not provide adequate information on the taxpaying status of its
       unitholders; and

     - failed to estimate potential reparations for ARCO.
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     On December 10, 2001, SFPP filed a response to those claims, explaining
that it had computed the surcharge consistent with the Commission's rulings,
provided all unitholder tax status information requested by Opinion No. 435-B
and calculated estimated reparations for all complainants for which the FERC had
directed it to do so. On December 14, 2001, SFPP filed a revised compliance
filing and new tariff correcting an error that had resulted in understating the
proper surcharge and tariff rates.

     On December 20, 2001, the FERC's Director of the Division of Tariffs and
Rates Central issued two letter orders rejecting SFPP's November 20, 2001 and
December 14, 2001 tariff filings because they were not made effective
retroactive to August 1, 2000. On January 11, 2002, SFPP filed a request for
rehearing of those orders by the Commission, on the ground that the FERC has no
authority to require retroactive reductions to rates filed pursuant to its
orders in complaint proceedings. On February 15, 2002, the FERC denied the
motion for rehearing. SFPP is currently preparing a motion for reclarification
of the order denying rehearing.

     Motions to intervene and protest the December 14, 2001 corrected submission
were filed by Navajo, ARCO and Mobil. Ultramar requested leave to file an
out-of-time intervention and protest of both the November 20, 2001 and December
14, 2001 submissions. On January 14, 2002, SFPP responded to those filings to
the extent they were not mooted by the orders rejecting the tariffs in question.

     In December 1995, Texaco filed an additional FERC complaint, which involves
the question of whether a tariff filing was required for movements on SFPP's
Sepulveda Lines, which are upstream of its Watson, California station origin
point, and, if so, whether those rates may be set in that proceeding and what
those rates should be. Several other West Line shippers have filed similar
complaints and/or motions to intervene in this proceeding, all of which have
been consolidated into Docket Nos. OR96-2-000, et al. Hearings before an
administrative law judge were held in December 1996 and the parties completed
the filing of final post-hearing briefs in January 1997.

     On March 28, 1997, the administrative law judge issued an initial decision
holding that the movements on the Sepulveda Lines are not subject to FERC
jurisdiction. On August 5, 1997, the FERC reversed that decision and found the
Sepulveda Lines to be subject to the jurisdiction of the FERC. The FERC ordered
SFPP to make a tariff filing within 60 days to establish an initial rate for
these facilities. The FERC reserved decision on reparations until it ruled on
the newly-filed rates. On October 6, 1997, SFPP filed a tariff establishing the
initial interstate rate for movements on the Sepulveda Lines from Sepulveda
Junction to Watson Station at the preexisting rate of five cents per barrel,
along with supporting cost of service documentation. Subsequently, several
shippers filed protests and motions to intervene at the FERC challenging that
rate. On December 24, 1997, FERC denied SFPP's request for rehearing of the
August 5, 1997 decision. On December 31, 1997, SFPP filed an application for
market power determination, which, if granted, will enable it to charge
market-based rates for this service. Several parties protested SFPP's
application. On September 30, 1998, the FERC issued an order finding that, based
on SFPP's application, SFPP lacks market power in the Watson Station destination
market served by the Sepulveda Lines. The FERC found that SFPP appeared to lack
market power in the origin market served by the Sepulveda Lines as well, but
established a hearing to permit the protesting parties to substantiate
allegations that SFPP possesses market power in the origin market. Hearings
before a FERC administrative law judge on this limited issue were held in
February 2000.

     On December 21, 2000, the FERC administrative law judge issued his initial
decision finding that SFPP possesses market power over the Sepulveda Lines
origin market. SFPP and other parties have filed briefs opposing and supporting
the initial decision with the FERC. The ultimate disposition of SFPP's market
rate application is pending before the FERC.

     Following the issuance of the initial decision in the Sepulveda case, the
FERC judge indicated an intention to proceed to consideration of the justness
and reasonableness of the existing rate for service on the Sepulveda Lines. SFPP
sought clarification from FERC on the proper disposition of that issue in light
of the pendency of its market rate application and prior deferral of
consideration of SFPP's tariff filing. On February 22, 2001, the FERC granted
SFPP's motion and deferred consideration of the pending complaints against the
Sepulveda Lines rate until after its final disposition of SFPP's market rate
application.

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<PAGE>

     On October 22, 1997, ARCO, Mobil and Texaco filed another complaint at the
FERC (Docket No. OR98-1-000) challenging the justness and reasonableness of all
of SFPP's interstate rates. The complaint again challenges SFPP's East and West
Line rates and raises many of the same issues, including a renewed challenge to
the grandfathered status of West Line rates, that have been at issue in Docket
Nos. OR92-8-000, et al. The complaint includes an assertion that the acquisition
of SFPP and the cost savings anticipated to result from the acquisition
constitute "substantially changed circumstances" that provide a basis for
terminating the "grandfathered" status of SFPP's otherwise protected rates. The
complaint also seeks to establish that SFPP's grandfathered interstate rates
from the San Francisco Bay area to Reno, Nevada and from Portland to Eugene,
Oregon are also subject to "substantially changed circumstances" and, therefore,
are subject to challenge. In November 1997, Ultramar Diamond Shamrock
Corporation filed a similar complaint at the FERC (Docket No. OR98-2-000, et
al.). The shippers are seeking both reparations and prospective rate reductions
for movements on all of the lines.

     SFPP filed answers to both complaints, and on January 20, 1998, the FERC
issued an order accepting the complaints and consolidating both complaints into
one proceeding, but holding them in abeyance pending a FERC decision on review
of the initial decision in Docket Nos. OR92-8-000, et al. In July 1998, some
complainants amended their complaints to incorporate updated financial and
operational data on SFPP. SFPP answered the amended complaints. In a companion
order to Opinion No. 435, the FERC directed the complainants to amend their
complaints, as may be appropriate, consistent with the terms and conditions of
its orders, including Opinion No. 435. On January 10 and 11, 2000, the
complainants again amended their complaints to incorporate further updated
financial and operational data on SFPP. SFPP filed an answer to these amended
complaints on February 15, 2000. On May 17, 2000, the FERC issued an order
finding that the various complaining parties had alleged sufficient grounds for
their complaints against SFPP's interstate rates to go forward to a hearing. At
such hearing, the administrative law judge will assess whether any of the
challenged rates that are grandfathered under the Energy Policy Act will
continue to have such status and, if the grandfathered status of any rate is not
upheld, whether the existing rate is just and reasonable.

     A hearing in this new proceeding commenced in October 2001 and continues.
An initial decision by the administrative law judge is expected in the latter
half of 2002.

     In August 2000, Navajo and RHC filed new complaints against SFPP's East
Line rates and Ultramar filed an additional complaint updating its pre-existing
challenges to SFPP's interstate pipeline rates. SFPP answered the complaints,
and on September 22, 2000, the FERC issued an order accepting these new
complaints and consolidating them with the ongoing proceeding in Docket No.
OR96-2-000, et al.

     The complainants have alleged a variety of grounds for finding
"substantially changed circumstances," including the acquisition of SFPP and
cost savings achieved subsequent to the acquisition. 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," which is the showing necessary to make
"grandfathered" rates subject to challenge. Given the newness of the
grandfathering standard under the Energy Policy Act and limited precedent, we
cannot predict how these allegations will be viewed by the FERC.

     If "substantially changed circumstances" are found, SFPP rates previously
"grandfathered" under the Energy Policy Act may lose their "grandfathered"
status. If these rates are found to be unjust and unreasonable, shippers may be
entitled to a prospective rate reduction and a complainant may be entitled to
reparations for periods from the date of its complaint to the date of the
implementation of the new rates.

     In June 2001, ARCO and others protested SFPP's adjustment to its interstate
rates in compliance with the Commission's indexing regulations. Following
submissions by the protestants and SFPP, the Commission issued an order in
September 2001 dismissing the protests and finding that SFPP had complied with
the Commission's indexing regulations.

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<PAGE>

     We are not able to predict with certainty the final outcome of the FERC
proceedings, should they be carried through to their conclusion, or whether we
can reach a settlement with some or all of the complainants. Although it is
possible that current or future proceedings could be resolved in a manner
adverse to us, we believe that the resolution of such matters will not have a
material adverse effect on our business, financial position or results of
operations.

  CALNEV PIPE LINE LLC

     We acquired CALNEV Pipe Line LLC in March 2001. CALNEV provides interstate
and intrastate transportation from an interconnection with SFPP at Colton,
California to destinations in and around Las Vegas, Nevada. On June 1, 2001,
CALNEV filed to adjust its interstate rates upward pursuant to the FERC's
indexing regulations. ARCO, ExxonMobil, Ultramar Diamond Shamrock and Ultramar,
Inc. protested this adjustment. On June 29, 2001, the FERC accepted and
suspended the rate adjustment and permitted it to go into effect subject to
refund. The FERC withheld ruling on the protests pending submission by CALNEV of
its FERC Form No. 6 annual report and responses from the protestants to data
contained therein. In September 2001, following submission by CALNEV of its Form
No. 6 annual report and further submissions by ARCO and CALNEV, the Commission
dismissed the protests, finding that CALNEV's rate adjustment comported with the
Commission's indexing regulations.

     In August 2001, ARCO filed a complaint against CALNEV's interstate rates
alleging that they were unjust and unreasonable. Tosco and Ultramar filed
interventions. In an October 15, 2001 order, the Commission set this claim for
investigation and hearing. The matter has, however, first been referred to a
settlement judge and such settlement process is currently ongoing. On November
14, 2001, CALNEV filed a motion for rehearing or, in the alternative,
clarification of the Commission's October 15, 2001 order. CALNEV asserted that
the Commission should have dismissed ARCO's complaint because it did not meet
the standards of the Commission's regulations or, in the alternative, that the
Commission should clarify the standards of pleading and proof applicable to
ARCO's complaint.

     On January 14, 2002 Tosco Corporation filed a complaint claiming that
CALNEV's rates are unjust and unreasonable and asking that its complaint be
consolidated with the ARCO complaints for hearing. Ultramar filed a similar
complaint on January 18, 2002. CALNEV answered both of these complaints on
February 4, 2002. At a settlement conference on January 17, 2002 the parties
made substantial progress toward reaching a settlement. They have agreed to a
"standstill" in the litigation while they attempt to reach a comprehensive
written settlement. The settlement judge has indicated that he anticipates that
the parties will be able to submit a settlement agreement to the Commission on
or before April 30, 2002.

     We are not able to predict with certainty the final outcome of this FERC
proceeding, should it be carried through to its conclusion, or whether we can
reach a settlement with the complainant. Although it is possible that current or
future proceedings could be resolved in a manner adverse to us, we believe that
the resolution of such matters will not have a material adverse effect on our
business, financial position or results of operations.

  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 seek prospective rate reductions
aggregating approximately $10 million per year.
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<PAGE>

     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 a
decision addressing the submitted matters is expected at any time.

     We believe that the resolution of such matters will not have a material
adverse effect on our business, financial position or results of operations.

  SOUTHERN PACIFIC TRANSPORTATION COMPANY EASEMENTS

     SFPP 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 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).
Although SFPP received a favorable ruling from the trial court in May 1997, in
September 1999, the California Court of Appeals remanded the case back to the
trial court for further proceeding. SFPP is accruing amounts for payment of the
rental for the subject rights-of-way consistent with our expectations of the
ultimate outcome of the proceeding. We expect this matter to go to trial during
the second quarter of 2002.

  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 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 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 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 FERC, addressing its
July 13, 2001 Order 637 compliance plan. In this 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 Commission.
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. The November 19, 2001 Compliance
filing has been protested by several parties. KMIGT filed responses to those
protests on December 14, 2001. At this time, it is unknown when this proceeding
will be finally resolved. KMIGT currently expects that it may not have a fully
compliant Order 637 tariff approved and in effect until sometime in the first or
second quarter of 2002. The full impact of implementation of Order 637 on the
KMIGT system is under evaluation. We believe that these matters will not have a
material adverse effect on our business, financial position or results of
operations.
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<PAGE>

     Separately, numerous petitioners, including KMIGT, have filed appeals 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 courts in December 2001 and final action is
pending.

  Trailblazer Pipeline Company

     On August 15, 2000, Trailblazer Pipeline Company made a filing to comply
with FERC's Order Nos. 637 and 637-A. Trailblazer Pipeline Company's compliance
filing reflected changes in:

     - segmentation;

     - scheduling for capacity release transactions;

     - receipt and delivery point rights;

     - treatment of system imbalances;

     - operational flow orders;

     - penalty revenue crediting; and

     - right of first refusal language.

     On October 15, 2001, FERC issued its order on Trailblazer Pipeline
Company's Order No. 637 compliance filing. FERC approved Trailblazer Pipeline
Company's proposed language regarding operational flow orders and the right of
first refusal, but is requiring Trailblazer Pipeline Company to make changes to
its tariff related to the other issues listed above. Most of the tariff
provisions will have an effective date of January 1, 2002, with the exception of
language related to scheduling and segmentation, which will become effective at
a future date dependent on when KMIGT's Order No. 637 provisions go into effect.
Trailblazer Pipeline Company anticipates no adverse impact on its business as a
result of the implementation of Order No. 637.

     On November 14, 2001, Trailblazer Pipeline Company made its compliance
filing pursuant to the FERC order of October 15, 2001. That compliance filing
has been protested. Separately, also on November 14, 2001, Trailblazer Pipeline
Company filed for rehearing of that FERC order. These pleadings are pending FERC
action.

  STANDARDS OF CONDUCT RULEMAKING

     On September 27, 2001, 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 KMIGT, Trailblazer Pipeline Company and their respective
affiliates. In addition, the Notice could be read to require separate staffing
of KMIGT and its affiliates, and Trailblazer and its affiliates. Comments on the
Notice of Proposed Rulemaking were due December 20, 2001. We believe that these
matters, as finally adopted, will not have a material adverse effect on our
business, financial position or results of operations.

  CARBON DIOXIDE LITIGATION

     Kinder Morgan CO(2) Company, L.P. directly or indirectly through its
ownership interest in the Cortez Pipeline Company, along with other entities, is
a defendant in several actions in which the plaintiffs allege that the
defendants undervalued carbon dioxide produced from the McElmo Dome field and
overcharged for transportation costs, thereby allegedly underpaying royalties
and severance tax payments. The plaintiffs, who are seeking monetary damages and
injunctive relief, are comprised of royalty, overriding royalty and small share
working interest owners who claim that they were underpaid by the defendants.
These cases are: CO(2) 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);
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<PAGE>

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. file
9/22/00); United States ex rel. Crowley v. Shell Oil Company, et al., No.
00-Z-1220 (U.S.D.C. Colo. filed 6/13/00); Ptasynski et al. v. Shell Western E&P
Inc., et al., No. 99-11049 (U.S. Ct. App. 5th Cir. filed 5/21/97 ); 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).

  RSM Production Company et al. v. Kinder Morgan Energy Partners, L.P. et al.

     Cause No. 4519, in the District Court, Zapata County Texas, 49th Judicial
District. On October 15, 2001, Kinder Morgan Energy Partners, L.P. was served
with the First Supplemental Petition filed by RSM Production Corporation on
behalf of the County of Zapata, State of Texas and Zapata County Independent
School District as plaintiffs. Kinder Morgan Energy Partners, L.P. was sued in
addition to 15 other defendants, including two other Kinder Morgan affiliates.
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.
Defendants have sought an extension of time to answer, and have not yet
responded to the Petition. There are no further pretrial proceedings at this
time.

  Quinque Operating Company, et al. v. Gas Pipelines, et al.

     Cause No. 99-1390-CM, United States District Court for the District of
Kansas. This action was originally filed 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. The plaintiffs
in the case seek to have the Court certify the case as a class action. The
plaintiffs are natural gas producers and fee royalty owners who allege that they
have been subject to systematic mismeasurement of natural gas by the defendants
for more than 25 years. Among other things, the plaintiffs allege a conspiracy
among the pipeline industry to under-measure natural gas and have asserted joint
and several liability against the defendants. Subsequently, one of the
defendants removed the action to Kansas Federal District Court. 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,
styled as United States of America, ex rel., Jack J. Grynberg v. K N Energy,
Civil Action No. 97-D-1233, filed in the United States District Court, District
of Colorado, because of common factual questions. On April 10, 2000, the
Multidistrict Litigation Panel ordered that this case be consolidated with the
Grynberg federal False Claims Act cases. 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. A case management conference recently
occurred in State Court in Stevens County, and a briefing schedule was
established for preliminary matters. Personal jurisdiction discovery has
commenced. Merits discovery has not commenced.

     Although no assurances can be given, we believe that we have meritorious
defenses to all of these actions, that 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 or results of operations.

  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
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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 and terminal
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:

     - 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;

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

     - 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.

     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.

     Review of assets related to Kinder Morgan Interstate Gas Transmission LLC
includes the environmental impacts from petroleum and used oil releases to the
soil and groundwater at nine sites. Additionally, review of assets related to
Kinder Morgan Texas Pipeline includes the environmental impacts from petroleum
releases to the soil and groundwater at six sites. Further delineation and
remediation of these impacts will be conducted. Reserves have been established
to address the closure of these issues.

     On October 2, 2001, the jury rendered a verdict in the case of Walter
Chandler v. Plantation Pipe Line Company.  The jury awarded the plaintiffs a
total of $43.8 million. The verdict was divided with the following award of
damages:

     - $0.3 million compensatory damages for property damage to the Evelyn
       Chandler Trust;

     - $5 million compensatory damages to Walter (Buster) Chandler;

     - $1.5 million compensatory damages to Clay Chandler; and

     - $37 million punitive damages.

     Plantation has filed post judgment motions and appeal of the verdict. The
appeal of this case will be directly heard by the Alabama Supreme Court. It is
anticipated that a decision by the Alabama Supreme Court will be received within
the next twelve to eighteen months.

     This case was filed in April 1997 by the landowner (Evelyn Chandler Trust)
and two residents of the property (Buster Chandler and his son, Clay Chandler).
The suit was filed against Chevron, Plantation and two individuals. The two
individuals were later dismissed from the suit. Chevron settled with the
plaintiffs in December 2000. The property and residences are directly across the
street from the location of a former Chevron products terminal. The Plantation
pipeline system traverses the Chevron terminal property. The suit alleges that
gasoline released from the terminal and pipeline contaminated the groundwater
under the plaintiffs' property. A current remediation effort is taking place
between Chevron, Plantation and Alabama Department of Environmental Management.

     Although no assurance can be given, we believe that the ultimate resolution
of all these environmental matters set forth in this note will not have a
material adverse effect on our business, financial position or

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<PAGE>

results of operations. We have recorded a total reserve for environmental claims
in the amount of $75.8 million at December 31, 2001.

  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 or
results of operations.

17.  QUARTERLY FINANCIAL DATA (UNAUDITED)

<Table>
<Caption>
                                                                               BASIC       DILUTED
                                       OPERATING    OPERATING                NET INCOME   NET INCOME
                                        REVENUES     INCOME     NET INCOME    PER UNIT     PER UNIT
                                       ----------   ---------   ----------   ----------   ----------
                                                  (IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)
<S>                                    <C>          <C>         <C>          <C>          <C>
2001
     First Quarter...................  $1,028,645   $138,351     $101,667      $0.45        $0.45
     Second Quarter..................     735,755    138,596      104,226       0.36         0.36
     Third Quarter...................     638,544    144,892      115,792       0.37         0.37
     Fourth Quarter..................     563,880    143,185      120,658       0.40         0.40
2000
     First Quarter...................  $  157,358   $ 63,061     $ 59,559      $0.32        $0.32
     Second Quarter..................     193,758     79,976       71,810       0.35         0.35
     Third Quarter...................     202,575     79,826       69,860       0.33         0.33
     Fourth Quarter..................     262,751     92,698       77,119       0.34         0.34
</Table>

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