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


                                  F O R M 10-Q


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

                  For the quarterly period ended March 31, 2002

                                       or

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

                   For the transition period from _____to_____

                         Commission file number: 1-11234


                       KINDER MORGAN ENERGY PARTNERS, L.P.
             (Exact name of registrant as specified in its charter)


             DELAWARE                             76-0380342
    (State or other jurisdiction                (I.R.S. Employer
of incorporation or organization)               Identification No.)


         500 Dallas Street, Suite 1000, Houston, Texas 77002
         (Address of principal executive offices)(zip code)
  Registrant's telephone number, including area code: 713-369-9000


   Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No
    The Registrant had 129,908,018 common units outstanding at May 3, 2002.



                                       1




                       KINDER MORGAN ENERGY PARTNERS, L.P.
                                TABLE OF CONTENTS

                                                                           Page
                                                                          Number
                          PART I. FINANCIAL INFORMATION

Item 1:   Financial Statements (Unaudited)......................
            Consolidated Statements of Income-Three Months
            Ended March 31, 2002 and 2001.......................           3
            Consolidated Balance Sheets-March 31, 2002 and
            December 31, 2001...................................           4
            Consolidated Statements of Cash Flows-Three Months
            Ended March 31, 2002 and 2001.......................           5
            Notes to Consolidated Financial Statements..........        6-27

Item 2:   Management's Discussion and Analysis of Financial
          Condition and Results of Operations...................
            Results of Operations...............................          28
            Financial Condition.................................          30
            Information Regarding Forward-Looking Statements....          33

Item 3:   Quantitative and Qualitative Disclosures About
          Market Risk...........................................          34


                           PART II. OTHER INFORMATION

Item 1:   Legal Proceedings.....................................          35

Item 2:   Changes in Securities and Use of Proceeds.............          35

Item 3:   Defaults Upon Senior Securities.......................          35

Item 4:   Submission of Matters to a Vote of Security Holders...          35

Item 5:   Other Information.....................................          35

Item 6:   Exhibits and Reports on Form 8-K......................          35

          Signature.............................................          37


                                       2


PART I.  FINANCIAL INFORMATION

Item 1.  Financial Statements. (Unaudited)

              KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
                        CONSOLIDATED STATEMENTS OF INCOME
                     (In Thousands Except Per Unit Amounts)
                                   (Unaudited)

                                               Three Months Ended March 31,
                                                  2002                2001
                                              ----------          ----------
      Revenues
        Natural gas sales                      $463,274            $635,750
        Services                                261,209             238,743
        Product sales and other                  78,582             154,152
                                              ----------          -----------
                                                803,065           1,028,645
                                              ----------          -----------
      Costs and Expenses
        Gas purchases and other costs of sales  448,093             707,714
        Operations and maintenance               87,291              95,005
        Fuel and power                           18,384              15,242
        Depreciation and amortization            41,326              30,075
        General and administrative               26,347              28,585
        Taxes, other than income taxes           15,768              13,673
                                              ----------          ------------
                                                637,209             890,294
                                              ----------          ------------

      Operating Income                          165,856             138,351

      Other Income (Expense)
        Earnings from equity investments         23,271              21,203
        Amortization of excess cost of           (1,394)             (2,253)
                equity investments
        Interest, net                           (39,022)            (49,807)
        Other, net                                  (50)                274
      Minority Interest                          (2,827)             (3,002)
                                              -----------         ------------

      Income Before Income Taxes                145,834              104,766

      Income Taxes                                4,401                3,099
                                              -----------         ------------

      Net Income                              $ 141,433           $  101,667
                                              ===========         ============

      General Partner's interest in Net       $  61,794           $   41,622
      Income

      Limited Partners' interest in Net          79,639               60,045
      Income                                  -----------         ------------


      Net Income                              $ 141,433           $  101,667
                                              ===========         ============

      Basic and Diluted Limited Partners'     $    0.48           $     0.44
                                              ===========         ============
      Net Income per Unit

      Weighted Average Number of Units used in Computation
      of Limited Partners' Net Income per Unit

      Basic                                     166,049              135,036
                                              ===========         =============

      Diluted                                   166,246              135,222
                                              ===========         =============

      Additional per Unit information
      Declared Distribution                   $   0.590           $    0.525
                                              ===========         ============


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

                                       3


              KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
                           CONSOLIDATED BALANCE SHEETS
                                 (In Thousands)
                                   (Unaudited)

                                               March 31,          December 31,
                                                 2002                2001
                                              ---------          ------------
            ASSETS

            Current Assets
               Cash and cash equivalents         $  29,266          $   62,802
               Accounts and notes receivable
                 Trade                             279,409             215,860
                 Related parties                    18,427              52,607
               Inventories
                 Products                            1,048               2,197
                 Materials and supplies              6,549               6,212
               Gas imbalances                       77,546              15,265
               Gas in underground storage            7,436              18,214
               Other current assets                 91,268             194,886
                                                -----------         ----------
                                                   510,949             568,043
                                                -----------         ----------

            Property, Plant and Equipment, net   5,892,435           5,082,612
            Investments                            453,080             440,518
            Notes receivable                         3,030               3,095
            Intangibles, net                       563,742             563,397
            Deferred charges and other assets       71,971              75,001
                                                -----------         ----------
            TOTAL ASSETS                        $7,495,207          $6,732,666
                                                ===========         ==========

            LIABILITIES AND PARTNERS' CAPITAL
            Current Liabilities
               Accounts payable
                 Trade                           $ 129,115          $  111,853
                 Related parties                    68,528               9,235
               Current portion of long-term debt   538,582             560,219
               Accrued interest                     19,195              34,099
               Deferred revenues                     2,664               2,786
               Gas imbalances                       97,388              34,660
               Accrued other liabilities           190,426             209,852
                                                -----------         ----------
                                                 1,045,898             962,704
                                                -----------         ----------

            Long-Term Liabilities and Deferred
            Credits
               Long-term debt                    2,959,661           2,231,574
               Deferred revenues                    28,657              29,110
               Deferred income taxes                38,544              38,544
               Other                               277,761             246,464
                                                -----------         ----------
                                                 3,304,623           2,545,692
                                                -----------         ----------
            Commitments and Contingencies

            Minority Interest                       64,480              65,236
                                                -----------         ----------
            Partners' Capital
               Common Units                      1,886,229           1,894,677
               Class B Units                       125,376             125,750
               i-Units                           1,034,947           1,020,153
               General Partner                      61,123              54,628
               Accumulated other comprehensive
                income (loss)                      (27,469)             63,826
                                                -----------         ----------
                                                 3,080,206           3,159,034
                                                -----------         ----------
            TOTAL LIABILITIES AND PARTNERS'
            CAPITAL                             $7,495,207          $6,732,666
                                                ===========         ==========

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

                                       4




              KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                                 (In Thousands)
                                   (Unaudited)

                                                Three Months Ended March 31,
                                                  2002                2001
                                              ----------          ----------
  Cash Flows From Operating Activities
  Net income                                   $141,433            $101,667
  Adjustments to reconcile net income
  to net cash provided by operating
  activities:
      Depreciation and amortization              41,326              30,075
      Amortization of excess cost of
         equity investments                       1,394               2,253
      Earnings from equity investments          (23,271)            (21,203)
      Distributions from equity investments       6,177              10,521
      Changes in components of working capital   58,998              (9,424)
      Other, net                                 (3,486)             23,933
                                              ----------          ----------
  Net Cash Provided by Operating
  Activities                                    222,571             137,822
                                              ----------          ----------


  Cash Flows From Investing
  Activities
      Acquisitions of assets                   (758,340)         (1,015,594)
      Additions to property, plant
        and equipment for
        expansion and maintenance               (91,038)            (39,881)
        projects
      Sale of investments, property,
        plant and equipment,
        net of removal costs                       (363)               8,047
      Contributions to equity investments          (291)              (1,244)
      Other                                         758               (3,148)
                                              ----------         ------------
  Net Cash Used in Investing Activities        (849,274)          (1,051,820)
                                              ----------         ------------


  Cash Flows From Financing
  Activities
      Issuance of debt                        1,800,337            3,067,734
      Payment of debt                        (1,075,591)          (1,849,301)
      Debt issue costs                              (60)              (6,989)
      Distributions to partners:
          Common units                          (71,424)             (61,011)
          Class B units                          (2,922)                --
          General Partner                       (55,300)             (33,398)
          Minority interest                      (2,651)              (2,274)
      Other, net                                    778                 (325)
                                             -----------         ------------
  Net Cash Provided by Financing
  Activities                                    593,167            1,114,436
                                             -----------         ------------

  Increase in Cash and Cash Equivalents         (33,536)             200,438

  Cash and Cash Equivalents,
    beginning of period                         62,802                59,319
                                             -----------         ------------
  Cash and Cash Equivalents, end of
    period                                     $29,266           $   259,757
                                             ===========         ============
  Noncash Investing and Financing
  Activities:
    Assets acquired by the
    assumption of liabilities                  105,597              $259,634

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


                                       5


              KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                                   (Unaudited)

1. Organization

   General

   Unless the context requires otherwise, references to "we", "us", "our" or the
"Partnership" are intended to mean Kinder Morgan Energy Partners, L.P. We have
prepared the accompanying unaudited consolidated financial statements under the
rules and regulations of the Securities and Exchange Commission. Under such
rules and regulations, we have condensed or omitted certain information and
notes normally included in financial statements prepared in conformity with
accounting principles generally accepted in the United States of America. We
believe, however, that our disclosures are adequate to make the information
presented not misleading. The consolidated financial statements reflect all
adjustments that are, in the opinion of our management, necessary for a fair
presentation of our financial results for the interim periods. You should read
these consolidated financial statements in conjunction with our consolidated
financial statements and related notes included in our annual report on Form
10-K for the year ended December 31, 2001.

   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 that 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:

o     the amounts we report for assets and liabilities;
o     our disclosure of contingent assets and liabilities at the date of the
      financial statements; and
o     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
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. In addition, 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.
These revisions are reflected in our income in the period in which they are
reasonably determinable.

   Net Income Per Unit

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

                                        6





2. Acquisitions and Joint Ventures

   During the first quarter of 2002, we completed the following 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 effective date of acquisition.

   Cochin Pipeline

   In January 2002, 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.
The transaction was effective December 31, 2001, and we allocated the purchase
price to property, plant and equipment in January 2002. We record our
proportional share of joint venture revenues and expenses and cost of joint
venture assets with respect to the Cochin Pipeline System as part of our
Products Pipelines business segment.

   Laser Materials Services LLC

   Effective January 1, 2002, we acquired all of the equity interests of Laser
Materials Services LLC for approximately $9.1 million and the assumption of
approximately $3.3 million of liabilities, including long-term debt of $0.4
million. Laser Materials Services LLC operates 59 transload facilities in 18
states. The facilities handle dry-bulk products, including aggregates, plastics
and liquid chemicals. The acquisition of Laser Materials Services LLC expands
our growing bulk terminal operations and is part of our Terminals business
segment.

   At March 31, 2002, we allocated our purchase price to property, plant and
equipment. In the second quarter of 2002, we plan on making our final allocation
to assets acquired and liabilities assumed. Our purchase price and our estimated
allocation to assets acquired and liabilities assumed is as follows (in
thousands):

     Purchase price:
        Cash paid, including transaction costs               $ 9,101
        Debt assumed                                             357
        Liabilities assumed                                    2,967
                                                             -------
           Total purchase price                              $12,425
                                                             =======
     Allocation of purchase price:
         Current assets                                      $   879
         Property, plant and equipment                        11,546
                                                             -------
                                                             $12,425
                                                             =======

   International Marine Terminals

   Effective January 1, 2002, we acquired a 33 1/3% interest in International
Marine Terminals from Marine Terminals Incorporated. Effective February 1, 2002,
we acquired an additional 33 1/3% interest in IMT from Glenn Springs Holdings.
Inc. Our combined purchase price was approximately $40.5 million. IMT is a
partnership that operates a bulk terminal site in Port Sulphur, Louisiana. The
Port Sulphur terminal is a multi-purpose import and export facility, which
handles approximately 7 million tons annually of bulk products including coal,
petroleum coke and iron ore. The acquisition complements our existing bulk
terminal assets and we include IMT as part of our Terminals business segment.

   At March 31, 2002, we allocated our purchase price to property, plant and
equipment. In the second quarter of 2002, we plan on making our final allocation
to assets acquired and liabilities assumed. Our purchase price and our estimated
allocation to assets acquired and liabilities assumed is as follows (in
thousands):

                                       7



     Purchase price:
       Cash received, net of transaction costs               $(3,781)
       Debt assumed                                           40,000
       Liabilities assumed                                     4,249
                                                             --------
       Total purchase price                                  $40,468
                                                             =======

     Allocation of purchase price:
       Current assets                                        $ 6,600
       Property, plant and equipment                          31,781
       Deferred charges and other assets                         139
       Minority interest                                       1,948
                                                            ---------
                                                             $40,468
                                                            =========
   Kinder Morgan Tejas

   Effective January 31, 2002, we acquired all of the equity interests of Tejas
Gas, LLC, a wholly-owned subsidiary of InterGen (North America), Inc., for
approximately $687.2 million and the assumption of approximately $103.8 million
of liabilities. The acquisition cost will be modified by purchase price
adjustments in the second quarter of 2002. Tejas Gas, LLC is primarily comprised
of a 3,400-mile natural gas intrastate pipeline system that extends from south
Texas along the Mexico border and the Texas Gulf Coast to near the Louisiana
border and north from near Houston to east Texas. The acquisition expands our
natural gas operations within the State of Texas. The acquired assets are
referred to as Kinder Morgan Tejas in this report and are included in our
Natural Gas Pipelines business segment.

   The allocation of our purchase price to the assets and liabilities of Kinder
Morgan Tejas is preliminary pending, among other things, the final purchase
price adjustments. Our estimated allocation to assets acquired and liabilities
assumed is as follows (in thousands):

     Purchase price:
           Cash paid, including transaction costs          $ 687,208
           Liabilities assumed                               103,787
                                                           ----------
                Total purchase price                       $ 790,995
                                                           ==========
      Allocation of purchase price:
           Current assets                                  $  96,108
           Property, plant and equipment                     694,887
                                                           ----------
                                                           $ 790,995
                                                           ==========

   Pro Forma Information

   The following summarized unaudited Pro Forma Consolidated Income Statement
information for the three months ended March 31, 2002 and 2001, assumes all of
the acquisitions we have made since January 1, 2001, including the ones listed
above, had occurred as of January 1, 2001. We have prepared these unaudited Pro
Forma financial results for comparative purposes only. These unaudited Pro Forma
financial results may not be indicative of the results that would have occurred
if we had completed these acquisitions as of January 1, 2001 or the results that
will be attained in the future. Amounts presented below are in thousands, except
for the per unit amounts:

                                                         Pro Forma
                                                    Three Months Ended
                                                         March 31,
                                                     2002           2001
                                                     ----           ----
                                                        (Unaudited)
Revenues                                          $1,044,811    $1,951,897
Operating Income                                     171,499       162,755
Net Income                                           141,028       126,586
Basic and diluted Limited Partners' Net Income
  per unit                                        $     0.48    $     0.43

   Acquisitions Subsequent to March 31, 2002

   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. The
transaction closed on May 6, 2002. Following the acquisition, we now own 100% of
Trailblazer Pipeline Company. During the first quarter of 2002, we paid $12.0
million to CIG Trailblazer Gas Company, an affiliate of El Paso Corporation, in
exchange for CIG's relinquishment of its rights to become a 7% to 8% equity
owner in Trailblazer Pipeline Company in mid-2002. At March 31, 2002, we
allocated this payment to property,

                                       8



plant and equipment.

3. Litigation and Other Contingencies

   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.

   OR92-8, et al. proceedings.  In September 1992, El Paso Refinery, L.P.
   ---------------------------
filed a protest/complaint with the FERC:

        o     challenging SFPP's East Line rates from El Paso, Texas to Tucson
              and Phoenix, Arizona;
        o     challenging SFPP's proration policy; and
        o     seeking to block the reversal of the direction of flow of SFPP's
                six-inch pipeline between Phoenix and Tucson.

   At various subsequent dates, the following 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/or West Lines:

        o     Chevron U.S.A. Products Company;
        o     Navajo Refining Company;
        o     ARCO Products Company;
        o     Texaco Refining and Marketing Inc.;
        o     Refinery Holding Company, L.P. (a partnership formed by El Paso
              Refinery's long-term secured creditors that purchased its refinery
              in May 1993);
        o     Mobil Oil Corporation; and
        o     Tosco Corporation.

Certain of these parties also claimed that a gathering enhancement fee at SFPP's
Watson Station in Carson, California was charged in violation of the Interstate
Commerce Act.

   The FERC consolidated these challenges in Docket Nos. OR92-8-000, et al., and
ruled that they are complaint proceedings, with the burden of proof on the
complaining parties. These parties must show that SFPP's rates and practices at
issue violate the requirements of the Interstate Commerce Act.

   A FERC administrative law judge held hearings in 1996, and issued an initial
decision on September 25, 1997. The initial decision agreed with SFPP's position
that "changed circumstances" had not been shown to exist on the West Line, and
therefore held that all West Line rates that were "grandfathered" under the
Energy Policy Act of 1992 were deemed to be just and reasonable and were not
subject to challenge, either for the past or prospectively, in the Docket No.
OR92-8 et al. proceedings. 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, was specifically excepted from that ruling.

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

        o     the capital structure to be used in computing SFPP's 1985
              starting rate base ;
        o     the level of income tax allowance; and
        o     the recovery of civil and regulatory litigation expenses and
              certain pipeline reconditioning costs.

   The administrative law judge also ruled that SFPP's gathering enhancement
service at Watson Station was subject to FERC jurisdiction and ordered SFPP to
file a tariff for that service, with supporting cost of service documentation.

   SFPP and other parties asked the Commission to modify various rulings made in
the initial decision. On January 13, 1999, the FERC issued its Opinion No. 435,
which affirmed certain of those rulings and reversed or modified others.

                                       9


   With respect to SFPP's West Line, the FERC affirmed 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 rate stated
in Tariff No. 18 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 made several changes in
the initial decision's methodology for calculating the rate base. It held that
the June 1985 capital structure of SFPP's parent company at that time, rather
than SFPP's 1988 partnership capital structure, should be used to calculate the
starting rate base and modified the accumulated deferred income tax and
allowable cost of equity used to calculate the rate base. It also 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.

   SFPP and certain complainants sought rehearing of Opinion No. 435 by the
FERC. In addition, ARCO, RHC, Navajo, Chevron and SFPP filed petitions for
review of Opinion No. 435 with the U.S. Court of Appeals for the District of
Columbia Circuit, all of which were either dismissed as premature or held in
abeyance pending FERC action on the rehearing requests.

    On March 15, 1999, as required by the FERC's order, SFPP submitted a
compliance filing implementing the rulings made in Opinion No. 435, establishing
the level of rates to be charged by SFPP in the future, and setting forth the
amount of reparations that would be owed by SFPP to the complainants under the
order. The complainants contested SFPP's compliance filing.

   On May 17, 2000, the FERC issued its Opinion No. 435-A, which modified
Opinion No. 435 in certain respects. It denied requests to reverse its rulings
that SFPP's West Line rates and Watson Station gathering enhancement facilities
fee are entitled to be treated as "grandfathered" rates under the Energy Policy
Act. It suggested, however, that if SFPP had fully recovered the capital costs
of the gathering enhancement 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 for debt return.

   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
with 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. That policy required customers to demonstrate a need for
additional capacity if a shortage of available pipeline space existed. SFPP's
prorationing policy has since been changed to eliminate the "demonstrated need"
test.

   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 fee,
but required SFPP to pay refunds to the extent that the initial compliance
tariff East Line rates exceeded the

                                       10



rates produced under Opinion No. 435-A.

   In June 2000, several parties filed requests for rehearing of 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:

     o    decision  to require  use of the  December  1988  partnership  capital
          structure for the period  1984-88 in computing the starting rate base;
     o    elimination of civil litigation costs;
     o    refusal to allow any recovery of civil litigation settlement payments;
          and
     o    failure  to  provide  any   allowance  for   regulatory   expenses  in
          prospective rates.

   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
stating revised East Line rates based on those rulings.

    ARCO, Chevron, Navajo, RHC, Texaco and SFPP sought judicial review of
Opinion No. 435-A in the U.S. Court of Appeals for the District of Columbia
Circuit. All of those petitions except Chevron's were either dismissed as
premature or held in abeyance pending action on the rehearing requests. On
September 19, 2000, the court dismissed Chevron's petition for lack of
prosecution, and subsequently denied a motion by Chevron for reconsideration of
that dismissal.

   On September 13, 2001, the FERC issued Opinion No. 435-B, which ruled on
requests for rehearing and comments on SFPP's compliance filing. Based on those
rulings, the FERC directed SFPP to submit a further revised compliance filing,
including revised tariffs and revised estimates of reparations and refunds.

   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 provision for regulatory costs in
prospective rates. However, it modified the Commission's prior rulings on
several other issues. It reversed the ruling that only Navajo is eligible to
seek reparations, holding that Chevron, RHC, Tosco and Mobil are also eligible
to recover reparations for East Line shipments. It ruled, however, that Ultramar
is not eligible for reparations in the Docket No. OR92-8 et al. proceedings .

   The FERC also changed prior rulings that had permitted SFPP to use 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. Opinion No. 435-B required SFPP to pay reparations to each
complainant without any offset for unrecovered costs. It required SFPP to
subtract from the total 1995-1998 supplemental costs allowed under Opinion No.
435-A any overearnings not paid out as reparations, and allowed SFPP to recover
any remaining costs from shippers by means of a five-year surcharge beginning
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 include environmental or pipeline rehabilitation costs.

   Opinion No. 154-B directed SFPP to make additional changes in its revised
compliance filing, including:

     o    using a remaining useful life of 16.8 years in amortizing its starting
          rate base,  instead of 20.6 years;
     o    removing the starting rate base comPonent from base rates as of August
          1, 2001;
     o    amortizing the accumulated  deferred  income tax balance  beginning in
          1992, rather than 1988;
     o    listing the corporate  unitholders  that were the basis for the income
          tax  allowance  in its  compliance  filing and  certifying  that those
          companies are not Subchapter S corporations; and
     o    "clearly"  excluding  civil  litigation  costs and  explaining  how it
          limited litigation costs to FERC-related expenses and assigned them to
          appropriate periods in making reparations calculations.

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

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

                                       11

          pending or subsequent proceedings.

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

     o    suggested  that  a  "substantial   divergence"   standard  applies  to
          complaint proceedings  challenging the total level of SFPP's East Line
          rates  subsequent  to the  Docket  No.  OR92-8 et al.  proceedings;
     o    required 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
     o    permitted SFPP to recover 1993 rate case litigation expenses through a
          surcharge mechanism.

   ARCO, Ultramar and SFPP filed petitions for 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 consolidated the Ultramar and SFPP
petitions with the consolidated cases held in abeyance and ordered that the
consolidated cases be returned to its active docket.

   On November 7, 2001, the FERC issued an order ruling on the 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 the
September 23, 1992 date sought by Chevron. 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 orders must demonstrate a substantial
divergence between the indexed rates and the pipeline's actual cost of service.
Finally, the FERC held that SFPP's 1993 regulatory costs should not be included
in the surcharge 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 for review of the FERC's
November 7, 2001 order in the U.S. Court of Appeals for the District of Columbia
Circuit. 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 ordered the consolidated proceedings to be held in abeyance until the
FERC acts on Chevron's 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:

     o    should have calculated the supplemental cost surcharge differently;
     o    did not provide  adequate  information on the taxpaying  status of its
          unitholders; and
     o    failed to estimate potential reparations for ARCO.

   On December 10, 2001, SFPP filed a response to those claims. 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 of rates filed pursuant to its
orders in complaint proceedings.

   Motions to intervene and protest the December 14, 2001 corrected submissions
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.

   On February 15, 2002, the Commission denied rehearing of the Director of the
Division of Tariffs and Rates Central's letter orders. On February 21, 2002,
SFPP filed a motion requesting that the Commission clarify whether

                                       12



it intended SFPP to file a retroactive tariff or simply make a compliance filing
calculating the effects of Opinion No. 435-B back to August 1, 2000; in the
event the order was clarified to require a retroactive tariff filing, SFPP asked
the Commission to stay that requirement pending judicial review.

   On April 8, 2002, SFPP filed a petition for review of the Commission's
February 15, 2002 Order in the U.S. Court of Appeals for the District of
Columbia Circuit. On April 9, 2002, the Court of Appeals consolidated that
petition with the consolidated petitions for review of the Commission's prior
orders and directed the parties "to file motions to govern future proceedings"
by May 9, 2002.

   Sepulveda proceedings. In December 1995, Texaco filed a complaint at FERC
(Docket No. OR96-2) alleging that movements on SFPP's Sepulveda pipelines (Line
Sections 109 and 110) to Watson Station, in the Los Angeles basin, were subject
to FERC's jurisdiction under the Interstate Commerce Act, and, if so, claimed
that the rate for that service was unlawful. Texaco sought to have its claims
addressed in the OR92-8 proceeding discussed above. Several other West Line
shippers filed similar complaints and/or motions to intervene. The Commission
consolidated all of these filings into Docket Nos. OR96-2 and set the claims for
a separate hearing. A hearing before an administrative law judge was held in
December 1996.

   In March 1997, the judge issued an initial decision holding that the
movements on the Sepulveda pipelines were not subject to FERC jurisdiction. On
August 5, 1997, the FERC reversed that decision. On October 6, 1997, SFPP filed
a tariff establishing the initial interstate rate for movements on the Sepulveda
pipelines at the preexisting rate of five cents per barrel. Several shippers
protested that rate. In December 1997, SFPP filed an application for authority
to charge a market-based rate for the Sepulveda service, which application was
protested by several parties. On September 30, 1998, the FERC issued an order
finding that SFPP lacks market power in the Watson Station destination market
and that, while SFPP appeared to lack market power in the Sepulveda origin
market, a hearing was necessary to permit the protesting parties to substantiate
allegations that SFPP possesses market power in the origin market. A hearing
before a FERC administrative law judge on this limited issue was 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 origin
market. The ultimate disposition of SFPP's 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 pipelines.
On February 22, 2001, the FERC granted SFPP's motion to block such consideration
and to defer consideration of the pending complaints against the Sepulveda rate
until after FERC's final disposition of SFPP's market rate application.

   OR97-2; OR98-1. et al. In October 1996, Ultramar filed a complaint at FERC
(Docket No. OR97-2) challenging SFPP's West Line rates, claiming they were
unjust and unreasonable and no longer subject to grandfathering. In October
1997, ARCO, Mobil and Texaco filed a complaint at the FERC (Docket No. OR98-1)
challenging the justness and reasonableness of all of SFPP's interstate rates,
raising claims against SFPP's East and West Line rates similar to those that
have been at issue in Docket Nos. OR92-8, et al., but expanding them to include
challenges to SFPP's grandfathered interstate rates from the San Francisco Bay
area to Reno, Nevada and from Portland to Eugene, Oregon - the North Line and
Oregon Line. In November 1997, Ultramar Diamond Shamrock Corporation filed a
similar, expanded complaint (Docket No. OR98-2). Tosco Corporation filed a
similar complaint in April 1998. The shippers seek both reparations and
prospective rate reductions for movements on all of the lines. SFPP answered
each of these complaints. FERC issued orders accepting the complaints and
consolidating them into one proceeding (Docket No. OR96-2, et al.), but holding
them in abeyance pending a FERC decision on review of the initial decision in
Docket Nos. OR92-8, et al.

   In a companion order to Opinion No. 435, the FERC gave the complainants an
opportunity to amend their complaints in light of Opinion No. 435, which the
complainants did in January 2000. On May 17, 2000, the FERC issued an order
finding that the various complaining parties had alleged sufficient grounds for
their complaints to go forward to a hearing to 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.

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

                                       13


al.

   A hearing in this consolidated proceeding was held from October 2001 to March
2002. An initial decision by the administrative law judge is expected in the
latter half of 2002.

   The complainants have alleged a variety of grounds for finding "substantially
changed circumstances." Applicable rules and regulations in this field are
vague, relevant factual issues are complex, and there is little precedent
available regarding the factors to be considered or the method of analysis to be
employed in making a determination of "substantially changed circumstances,"
which is the showing necessary to render "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 will 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.

   Indexing protests. In June 2001, ARCO, Tosco, and Ultramar 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.

   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.

   Indexing protests. In June 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. FERC accepted and
suspended the rate adjustment and permitted it to go into effect subject to
refund. 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.

  OR01-08. In August 2001, ARCO filed a complaint against CALNEV's interstate
rates alleging that they were unjust and unreasonable. Tosco and Ultramar filed
interventions and subsequently filed complaints. In October 2001, the Commission
set this claim for investigation and hearing. The matter was first referred to a
settlement judge. On November 14, 2001, CALNEV filed a motion for rehearing or,
in the alternative, clarification of the Commission's October 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.

  Settlement negotiations commenced in January 2002. In April 2002, CALNEV and
the complainants were able to reach a mutually agreeable resolution of the
disputed claims, and a settlement agreement was executed. Under the terms of the
settlement agreement, the parties have filed a joint motion for dismissal of the
pending complaints and termination of the proceeding. The parties are awaiting
commission action on these motions.

   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.

                                       14




   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.

   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 within three to four
months.

   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 the Order addressing the July 13,
2001 compliance plan, KMIGT's plan was accepted, but KMIGT was directed to make
several changes to its tariff, and in doing so, was directed that it could not
place the revised tariff into effect until further order of the 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 second
or third 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.

                                       15


   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. On April 5, 2002, the D.C.
Circuit issued an order largely affirming Order Nos. 637, et seq. The D.C.
Circuit remanded the Commission's decision to impose a 5-year cap on bids that
an existing shipper would have to match in the right of first refusal process.
The D.C. Circuit also remanded the Commission's decision to allow forward-hauls
and backhauls to the same point. Finally, the D.C. Circuit held that several
aspects of the Commission's segmentation policy and its policy on discounting at
alternate points were not ripe for review.

   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's compliance filing reflected
changes in:

     o    segmentation;
     o    scheduling for capacity release transactions;
     o    receipt and delivery point rights;
     o    treatment of system imbalances;
     o    operational flow orders;
     o    penalty revenue crediting; and
     o    right of first refusal language.

   On October 15, 2001, FERC issued its order on Trailblazer's Order No. 637
 compliance filing. FERC approved Trailblazer's proposed language regarding
 operational flow orders and the right of first refusal, but is requiring
 Trailblazer 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 anticipates no adverse impact on
 its business as a result of the implementation of Order No. 637.

   On November 14, 2001, Trailblazer 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 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 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. Numerous parties, including KMIGT, have filed
comment on the Proposed Standards of Conduct Rulemaking. The Proposed Rulemaking
is awaiting further Commission action. 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 CO2 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:  CO2 Claims Coalition, LLC v. Shell Oil Co., et
                               -----------------------------------------------
al., No. 96-Z-2451 (U.S.D.C. Colo. filed 8/22/96); Rutter & Wilbanks et al.
- ---                                                -------------------------
v. Shell Oil Co., et al., No. 00-Z-1854 (U.S.D.C. Colo. filed 9/22/00);
- -----------------------
Watson v. Shell Oil Co., et al., No. 00-Z-1855 (U.S.D.C. Colo. filed
- ------------------------------
9/22/00); Ainsworth et al. v. Shell Oil Co., et al., No. 00-Z-1856 (U.S.D.C.
          ----------------------------------------
Colo. filed 9/22/00); United States ex rel. Crowley v. Shell Oil Company, et
                      -------------------------------------------------------
al., No. 00-Z-1220 (U.S.D.C. Colo. filed 6/13/00); Shell Western E&P Inc. v.
- --                                                 --------------------------
Bailey, et al., No 98-28630 (215th Dist. Ct. Harris County, Tex. filed
- --------------
6/17/98); Shores, et al. v. Mobil Oil Corporation, et al., No. GC-99-01184
          -----------------------------------------------
(Texas Probate Court, Denton County filed 12/22/99); First State Bank of
                                                     --------------------
Denton v. Mobil Oil Corporation, et al., No. PR-8552-01 (Texas Probate Court,
- ---------------------------------------
Denton County filed 3/29/01); and

                                       16



Celeste C. Grynberg v. Shell Oil Company, et al., No. 98-CV-43 (Colo. Dist.
- -----------------------------------------------
Ct. Montezuma County filed 3/21/98).

      At a hearing conducted in the United States District Court for the
District of Colorado on April 8, 2002, the Court orally announced that it had
approved the certification of proposed plaintiff classes and approved a proposed
settlement in the CO2 Claims Coalition, LLC, Rutter & Wilbanks, Watson,
Ainsworth and United States ex rel. Crowley cases. As of the date of this
disclosure no written judgment has been entered.

   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. Recently, the defendants filed a
motion to dismiss on grounds other than personal jurisdiction and a motion to
dismiss for lack of personal jurisdiction for non-resident defendants.

    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 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:

     o    one  cleanup  ordered by the United  States  Environmental  Protection
          Agency related to ground water

                                       17

          contamination in the vicinity of SFPP's storage facilities and
          truck loading terminal at Sparks, Nevada;
     o    several   ground   water   hydrocarbon   remediation   efforts   under
          administrative  orders issued by the California Regional Water Quality
          Control Board and two other state agencies; and
     o    groundwater and soil remediation efforts under  administrative  orders
          issued by various  regulatory  agencies on those assets purchased from
          GATX  Corporation,  comprising  Kinder Morgan  Liquids  Terminals LLC,
          CALNEV Pipe Line LLC and Central Florida Pipeline LLC.

   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:

     o    $0.3 million  compensatory  damages for property  damage to the Evelyn
          Chandler Trust;
     o    $5 million compensatory damages to Walter (Buster) Chandler;
     o    $1.5 million compensatory damages to Clay Chandler; and
     o    $37 million punitive damages.

   Plantation has filed post judgment motions and an 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 the environmental matters set forth in this note will not have a material
adverse effect on our business, financial position or results of operations. We
have recorded a total reserve for environmental claims in the amount of $72.6
million at March 31, 2002.

   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.

4.  Two-for-One Common Unit Split

   On July 18, 2001, Kinder Morgan Management, LLC, 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 two-for-one split occurred on August 31, 2001 to unitholders of
record on August 17, 2001. All references to the number of Kinder Morgan
Management, LLC 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.

                                       18




5.  Distributions

   On February 14, 2002, we paid a cash distribution for the quarterly period
ended December 31, 2001, of $0.55 per unit to our common unitholders and to our
class B unitholders. Kinder Morgan Management, LLC, our sole i-unitholder,
received additional i-units based on the $0.55 cash distribution per common
unit. The distributions were declared on January 16, 2002, payable to
unitholders of record as of January 31, 2002.

   On April 17, 2002, we declared a cash distribution for the quarterly period
ended March 31, 2002, of $0.59 per unit. The distribution will be paid on or
before May 15, 2002, to unitholders of record as of April 30, 2002. Our common
unitholders and class B unitholders will receive cash. Our sole i-unitholder
will receive a distribution in the form of additional i-units based on the $0.59
distribution per common unit. The number of i-units distributed will be 527,572.
For each outstanding i-unit that Kinder Morgan Management, LLC holds, a fraction
of an i-unit will be issued. The fraction is determined by dividing:

     o    the cash amount distributed per common unit

           by

     o    the  average of Kinder  Morgan  Management's  shares'  closing  market
          prices  from April  12-25,  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.

6.      Intangibles

   Effective January 1, 2002, we adopted Statement of Financial Accounting
Standards No. 141 "Business Combinations" and Statement of Financial Accounting
Standards No. 142 "Goodwill and Other Intangible Assets". These accounting
pronouncements require that we prospectively cease amortization of all
intangible assets having indefinite useful economic lives. Such assets,
including goodwill, are not to be amortized until their lives are determined to
be finite, however, a recognized intangible asset with an indefinite useful life
should be tested for impairment annually or on an interim basis if events or
circumstances indicate that the fair value of the asset has decreased below its
carrying value. As of March 31, 2002, we have not completed a transitional test
for goodwill impairment. We intend to complete this test during the second
quarter of 2002.

   Our intangible assets include goodwill, lease value, contracts and
agreements. All of our intangible assets having definite lives are being
amortized on a straight-line basis over their estimated useful lives. SFAS Nos.
141 and 142 also require that we disclose the following information related to
our intangible assets still subject to amortization and our goodwill (in
thousands):

                                               March 31,           December 31,
                                                 2002                 2001
                                              ----------          -------------

                    Goodwill                   $567,050              $566,633
                    Accumulated amortization    (19,899)              (19,899)
                                              ----------           -----------
                    Goodwill, net                547,151               546,734
                                              ----------           -----------
                    Lease value                    6,124                 6,124
                    Contracts and other           10,712                10,739
                    Accumulated amortization        (245)                 (200)
                                              -----------          ------------
                    Other intangibles, net        16,591                16,663
                                              -----------          ------------
                    Total intangibles, net      $563,742              $563,397
                                              ===========          ============

   Changes in the carrying amount of goodwill for the quarter ended March 31,
2002 are summarized as follows (in thousands):
                                         Natural
                             Products     Gas         CO2
                             Pipelines  Pipeline  Pipeline   Terminals   Total
                             ---------  --------  ---------  ---------  -------
  Balance at Dec. 31, 2001   $262,765   $87,452    $46,101   $150,416   546,734
  Goodwill acquired               417        --         --         --       417
  Goodwill  dispositions, net      --        --         --         --        --
  Impairment losses                --        --         --         --        --
                             ---------  --------  ---------  ---------  -------
  Balance at Mar. 31, 2002   $263,182   $87,452    $46,101   $150,416  $547,151
                             ========   =======    =======   ========  ========



                                       19





   Amortization expense consists of the following (in thousands):

                                                   Three Months
                                                     Ended
                                                     March 31,
                                                -----------------
                                                2002         2001
                                                -----------------
                    Goodwill                    $   --     $2,582
                    Lease value                     35      1,397
                    Contracts and other             10        138
                                                ------     ------
                                                $   45     $4,117
                                                ======     ======

   Our weighted average amortization period for our intangible assets is
approximately 42 years. The following table shows the estimated amortization
expense for these assets for each of the five succeeding fiscal years (in
thousands):
                            2003       $  180
                            2004       $  180
                            2005       $  180
                            2006       $  180
                            2007       $  180

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

                                                             Three Months
                                                                 Ended
                                                               March 31,
                                                            -----------------
                                                             2002      2001
                                                            -------   -------
        Reported limited partners' interest in net income  $ 79,639  $ 60,045
        Add: limited partners' interest in goodwill
             amortization                                        --     2,557
                                                            -------   -------
        Adjusted limited partners' interest in net income  $ 79,539  $ 62,602
                                                           ========  ========

        Basic limited partners' net income per unit:
         Reported net income                               $   0.48  $   0.44
         Goodwill amortization                                   --      0.02
                                                           --------  --------
         Adjusted net income                               $   0.48  $   0.46
                                                           ========  ========

        Diluted limited partners' net income per unit:
         Reported net income                               $   0.48  $   0.44
         Goodwill amortization                                   --      0.02
                                                           --------- --------
         Adjusted net income                               $   0.48  $   0.46
                                                           ========  ========


7.      Debt

   Our debt and credit facilities as of March 31, 2002, consist primarily of:

     o    an $85.2 million unsecured  two-year credit facility due June 29, 2003
          (Trailblazer Pipeline Company is the obligor on the facility);
     o    a $750 million unsecured 364-day credit facility due October 23, 2002;
     o    a $200  million  unsecured  364-day  credit  facility due February 20,
          2003;
     o    a $300 million  unsecured  five-year credit facility due September 29,
          2004;
     o    $200 million of 8.00% Senior Notes due March 15, 2005;
     o    $250 million of 6.30% Senior Notes due February 1, 2009;
     o    $250 million of 7.50% Senior Notes due November 1, 2010;
     o    $700 million of 6.75% Senior Notes due March 15, 2011;
     o    $450 million of 7.125% Senior Notes due March 15, 2012;
     o    $40 million of  Plaquemines,  Louisiana  Port,  Harbor,  and  Terminal
          District  Revenue Bonds due March 15, 2006 (assumed as part of our IMT
          acquisition, see Note 2.);
     o    $25 million of New Jersey Economic Development Revenue Refunding Bonds
          due January 15, 2018 (our subsidiary,  Kinder Morgan Liquids Terminals
          LLC, is the obligor on the bonds);
     o    $23.7 million of  tax-exempt  bonds due 2024 (our  subsidiary,  Kinder
          Morgan Operating L.P. "B", is the obligor on the bonds);
     o    $300 million of 7.40% Senior Notes due March 15, 2031;

                                       20




     o    $300 million of 7.75% Senior Notes due March 15, 2032;
     o    $79.6 million of Series F First  Mortgage Notes due December 2004 (our
          subsidiary, SFPP, L.P. is the obligor on the notes);
     o    $87.9  million of  Industrial  Revenue  Bonds  with  final  maturities
          ranging from September 2019 to December 2024 (our  subsidiary,  Kinder
          Morgan Liquids Terminals LLC, is the obligor on the bonds);
     o    $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
     o    a $1.25 billion short-term commercial paper program.

   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 March 31, 2002, consisted of:

     o    $763.9 million of commercial paper borrowings;
     o    $42.5 million under the SFPP, L.P. 10.7% First Mortgage Notes;
     o    $5.0 million under the Central Florida Pipeline LLC Notes; and
     o    $3.5 million in other borrowings.

   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. We do
not anticipate any liquidity problems. Our average interest rate for outstanding
borrowings during the first quarter of 2002 was approximately 5.172% per annum.

   For additional information regarding our debt facilities, see Note 9 to our
consolidated financial statements included in our Form 10-K for the year ended
December 31, 2001.

   Credit Facilities

   On December 31, 2001, we had two credit facilities with a syndicate of
financial institutions. They consisted of a $300 million unsecured five-year
credit facility expiring on September 29, 2004 and a $750 million unsecured
364-day credit facility expiring on October 23, 2002. There were no borrowings
under either credit facility at December 31, 2001 or during the first quarter of
2002.

   On February 21, 2002, we obtained a third unsecured 364-day credit facility,
in the amount of $750 million, expiring on February 20, 2003. The credit
facility was used to support the increase in our commercial paper program to
$1.8 billion for our acquisition of Tejas Gas, LLC. The terms of this credit
facility are substantially similar to the terms of our other two credit
facilities. Upon issuance of additional senior notes in March 2002, this
short-term credit facility was reduced to $200 million. As of March 31, 2002, no
borrowings were outstanding under this credit facility.

   Our three credit facilities are with a syndicate of financial institutions.
First Union National Bank is the administrative agent under our five-year credit
facility and our 364-day facility that expires on October 23, 2002. JPMorgan
Chase Bank is the administrative agent under our 364-day facility that expires
on February 20, 2003. Interest on these three credit facilities accrues at our
option at a floating rate equal to either:

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

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

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

   The amount available for borrowing under our five-year credit facility is
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.

   Senior Notes

   On March 14, 2002, we closed a public offering of $750 million in principal
amount of senior notes, consisting of $450 million in principal amount of 7.125%
senior notes due March 15, 2012 at a price to the public of 99.535% per note,
and $300 million in principal amount of 7.75% senior notes due March 15, 2032 at
a price to the public of

                                       21




99.492% per note. The terms of these notes are substantially similar to the
terms of our other senior notes. In the offering, we received proceeds, net of
underwriting discounts and commissions, of approximately $445.0 million for the
7.125% notes and $295.9 million for the 7.75% notes. We used the proceeds to
reduce our outstanding balance on our commercial paper borrowings.

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

   At March 31, 2002, our unamortized liability balance due on the various
series of our senior notes were as follows (in millions):

   8.0% senior notes due March 15, 2005                          $ 199.8
   6.30% senior notes due February 1, 2009                         249.4
   7.5% senior notes due November 1, 2010                          248.6
   6.75% senior notes due March 15, 2011                           698.2
   7.125% senior notes due March 15, 2012                          447.9
   7.40% senior notes due March 15, 2031                           299.3
   7.75% senior notes due March 15, 2032                           298.5
                                                                --------
          Total                                                 $2,441.7
                                                                ========

   Commercial Paper Program

   As of December 31, 2001, we had $590.5 million of commercial paper
outstanding with an interest rate of 2.6585%. On February 21, 2002, our
commercial paper program increased to provide for the issuance of up to $1.8
billion of commercial paper. We entered into a $750 million unsecured 364-day
credit facility to support this increase in our commercial paper program, and we
used the program's increase in available funds to close on the Tejas
acquisition. After the issuance of additional senior notes on March 14, 2002, we
reduced our commercial paper program to $1.25 billion. As of March 31, 2002, we
had $763.9 million of commercial paper outstanding with an interest rate of
2.455%.

   Trailblazer Pipeline Company Debt

   At March 31, 2002, the outstanding balance under Trailblazer's $85.2 million
two-year revolving credit facility was $60.0 million. The revolving credit
facility expires on June 29, 2003, and had a weighted average interest rate of
2.77% at March 31, 2002, which reflects LIBOR plus a margin of 0.875%. Pursuant
to the terms of the revolving credit facility, Trailblazer partnership
distributions are restricted by certain financial covenants.

   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 the first quarter of 2002, the
weighted-average interest rate on these bonds was 1.29% per annum, and at March
31, 2002, the interest rate was 1.51%. We have an outstanding letter of credit
issued under our credit facilities that supports our tax-exempt bonds. The
letter of credit reduces the amount available for borrowing under our credit
facilities.

   Cortez Pipeline Company Debt

   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 KMCO2, 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 March 31, 2002, the debt facilities of Cortez Capital Corporation
consisted of:

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

                                       22
<page>

     o    a $48 million committed 364-day revolving credit facility;
     o    $136.4 million of Series D notes; and
     o    a $175 million short-term commercial paper program.

   At March 31, 2002, Cortez had $138 million of commercial paper outstanding
with an interest rate of 1.83%, the average interest rate on the series D notes
was 6.8579% and there were no borrowings under the credit facilities.

8. Partners' Capital

   At March 31, 2002, our partners' capital consisted of 129,893,618 common
units, 5,313,400 class B units and 31,090,333 i-units. Together, these
166,297,351 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 110,178,342 units
held by third parties, 17,991,276 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 Kinder Morgan, Inc. and
our i-units were held entirely by Kinder Morgan Management, LLC. Our general
partner has an effective 2% interest in the Partnership, excluding the general
partner's incentive distribution.

   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. Our common unit total
consisted of 110,071,392 units held by third parties, 18,059,626 units held by
Kinder Morgan, Inc. 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 Kinder Morgan, Inc. and our i-units were held entirely by
Kinder Morgan Management, LLC.

   Our class B units were issued in December 2000 and our i-units were initially
issued in May 2001. The i-units are a separate class of limited partner interest
in the Partnership. All of the i-units are owned by Kinder Morgan Management,
LLC and are not publicly traded. Through the combined effect of the provisions
in our partnership agreement and the provisions of Kinder Morgan Management,
LLC's limited liability company agreement, the number of outstanding Kinder
Morgan Management, LLC shares and the number of i-units will at all times be
equal.
   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. The number of i-units we distribute to
Kinder Morgan Management, LLC is based upon the amount of cash we distribute to
the owners of our common units. Typically, if cash is paid to the holders of our
common units, we will issue additional i-units to Kinder Morgan Management, LLC.
The fraction of an i-unit paid per i-unit owned by Kinder Morgan Management, LLC
will have the same value as the cash payment on the common unit. Based on the
preceding, Kinder Morgan Management, LLC received 453,970 i-units on February
14, 2002. These additional i-units distributed were based on the $0.55 per unit
distributed to our common unitholders on that date.

   For the purposes of maintaining partner capital accounts, our partnership
agreement specifies that items of income and loss shall be allocated among the
partners 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 that quarterly distributions to unitholders exceed certain specified
target levels. Our distribution of $0.55 per unit paid on February 14, 2002 for
the fourth quarter of 2001 required an incentive distribution to our general
partner of $54.4 million. Our distribution of $0.475 per unit paid on February
14, 2001 for the fourth quarter of 2000 required an incentive distribution to
our general partner of $32.8 million. The increased incentive distribution to
our general partner paid for the fourth quarter of 2001 over the distribution
paid for the fourth quarter of 2000 reflects the increase in the amount
distributed per unit as well as the issuance of additional units.

   Our declared distribution for the first quarter of 2002 of $0.59 per unit
will result in an incentive distribution to our general partner of $61.0
million. This compares to our distribution of $0.525 per unit and incentive
distribution to our general partner of $41.0 million for the first quarter of
2001.

9. Comprehensive Income

   Statement of Financial Accounting Standards No. 130, "Accounting for
Comprehensive Income", requires that enterprises report a total for
comprehensive income.  For each of the quarters ended March 31, 2002 and
2001, the only difference between our net income and our comprehensive income
was the unrealized gain or loss on

                                       23



derivatives utilized for hedging purposes.  For more information on our
hedging activities, see Note 10.  Our total comprehensive income is as
follows (in thousands):
                                            Three Months      Three Months
                                               Ended             Ended
                                            March 31, 2002    March 31, 2001
                                            --------------    -------------
  Net income                                  $ 141,433         $ 101,667
  Cumulative effect transition adjustment            --           (22,797)
  Change in fair value of derivatives used
     for hedging purposes                       (66,936)          (20,209)
  Reclassification of change in fair value
     of derivatives to net income               (24,359)           40,258
                                              -----------        ----------
  Comprehensive income                        $  50,138          $ 98,919
                                              ===========        ==========

10.Risk Management

   Hedging Activities

   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.

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

   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. Our Form 10-K for the year ended December 31,
2001 contains additional information about the risks we face and the hedging
program we employ to mitigate those risks.

   Approximately $0.8 million was recognized in earnings as a gain during the
first quarter of 2002 as a result of ineffectiveness of these hedges, which
amount is reported within the caption Operations and maintenance in the
accompanying Consolidated Statements of Income. For the first quarter of 2001,
approximately $0.3 million was recognized in earnings as a loss as a result of
ineffectiveness of these hedges. For each of the quarters ended March 31, 2002
and 2001, there was no component of the derivative instruments' gain or loss
excluded from the assessment of hedge effectiveness.

   The gains and losses included in Accumulated other comprehensive income
will be reclassified into earnings as the hedged sales and purchases take place.
Approximately $21.7 million of the Accumulated other comprehensive income
balance of $27.5 million representing unrecognized net losses on derivative
activities at March 31, 2002 is expected to be reclassified into earnings during
the next twelve months. During the quarter ended March 31, 2002, no gains or
losses were reclassified into earnings as a result of the discontinuance of cash
flow hedges due to a determination that the forecasted transactions will no
longer occur by the end of the originally specified time period.

   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 sheets. At March 31, 2002, our balance of $91.3 million of
other current assets includes approximately $60.7 million related to risk
management activities, and our balance of $190.4 million of accrued other
current liabilities includes approximately $83.0 million related to risk
management activities. At

                                       24
<page>

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 sheets.

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

   Interest Rate Swaps

   In order to maintain a cost effective capital structure, it is our policy to
borrow funds using a mix of fixed rate debt and variable rate debt. As of
March 31, 2002, we have entered into interest rate swap agreements with a
notional principal amount of $1.3 billion 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:

      o  8.0% senior notes due March 15, 2005;
      o  6.30% senior notes due February 1, 2009;
      o  7.125% senior notes due March 15, 2012;
      o  7.40% senior notes due March 15, 2031; and
      o  7.75% senior notes due March 15, 2032.

   The swap agreements for our senior notes have termination dates that
correspond to the maturity dates of such series. The swap agreements for our
7.40% senior notes contain mutual cash-out provisions at the then-current
economic value every seven years. The swap agreements for our 7.75% senior
notes contain mutual cash-out provisions at the then-current economic value
every five 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
March 31, 2002, we recognized a liability of $23.9 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. At December
31, 2001, we recognized a liability of $5.4 million for the net fair value of
our swap agreements. We are exposed to credit related losses in the event of
nonperformance by counterparties to these interest rate swap agreements, but,
given their existing credit ratings, we do not expect any counterparties to fail
to met their obligations.

11.  Reportable Segments

   We divide our operations into four reportable business segments:

      o   Products Pipelines;
      o   Natural Gas Pipelines;
      o   CO2 Pipelines; and
      o   Terminals.

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

   Our Products Pipelines segment derives its revenues primarily from the
transportation 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 CO2
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

                                       25



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):

                                                    Three Months Ended March 31,
                                                        2002          2001
                                                      --------     ----------
             Revenues
                Products Pipelines                    $134,818    $   190,693
                Natural Gas Pipelines                  537,557        726,285
                CO2 Pipelines                           32,124         29,102
                Terminals                               98,566         82,565
                                                      --------    -----------
                Total consolidated revenues           $803,065    $ 1,028,645
                                                      ========    ===========

             Operating income
                Products Pipelines                    $ 77,542    $    67,035
                Natural Gas Pipelines                   61,474         53,386
                CO2 Pipelines                           12,524         14,452
                Terminals                               40,663         32,063
                                                      --------    -----------
                Total segment operating income         192,203        166,936
                Corporate administrative expenses      (26,347)       (28,585)
                                                      --------    -----------
                Total consolidated operating Income   $165,856    $   138,351
                                                      ========    ===========

             Earnings from equity investments, net of
             amortization of excess costs
                Products Pipelines                    $  7,180    $     4,915
                Natural Gas Pipelines                    6,056          5,276
                CO2 Pipelines                            8,641          8,759
                Terminals                                  --             --
                                                      --------    -----------
                Consolidated equity earnings, net     $ 21,877    $    18,950
                of amortization                       ========    ===========

             Income taxes and Other, net - income
             (expense)
                Products Pipelines                    $ (2,775)   $    (2,102)
                Natural Gas Pipelines                        5             10
                CO2 Pipelines                               94            251
                Terminals                               (1,775)          (984)
                                                      ---------   ------------
                Total consolidated income taxes       $ (4,451)   $    (2,825)
                and Other, net                        =========   ============

             Segment Earnings
                Products Pipelines                    $ 81,947    $    69,848
                Natural Gas Pipelines                   67,535         58,672
                CO2 Pipelines                           21,259         23,462
                Terminals                               38,888         31,079
                                                      --------    -----------
                Total segment earnings                 209,629        183,061
                Interest and corporate                 (68,196)       (81,394)
                administrative expenses (a)           ---------   -----------

                Total consolidated net income         $141,433   $    101,667
                (a) Includes interest expense,        ========   ============
                general and administrative expenses,
                minority interest and other
                insignificant items.

                                                      Mar. 31,     Dec. 31,
                                                        2002         2001
                                                     ----------  ----------
           Assets
              Products Pipelines                     $3,160,609  $3,095,899
              Natural Gas Pipelines                   2,752,323   2,058,836
              CO2 Pipelines                             510,009     503,565
              Terminals                               1,016,511     990,760
                                                     ----------  ----------
              Total segment assets                    7,439,452   6,649,060
              Corporate assets (a)                       55,755      83,606
                                                     ----------  ----------
              Total consolidated assets              $7,495,207  $6,732,666
                                                     ==========  ==========
              (a) Includes cash, cash equivalents
              and certain unallocable deferred charges

                                       26





12.  New Accounting Pronouncements

   Statement of Financial Accounting Standards No. 141 "Business Combinations"
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.
We adopted SFAS No. 141 on January 1, 2002. Refer to Note 2 for more detail
about our acquisitions.

   Statement of Financial Accounting Standards 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. We intend to
make our initial assessment during the second quarter of 2002. 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 $547.2 million at March 31, 2002 is no longer subject
to amortization over its estimated useful life.

   Statement of Financial Accounting Standards No. 143, "Accounting for Asset
Retirement Obligations", issued in July 2001 by the Financial Accounting
Standards Board, 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.

   Statement of Financial Accounting Standards No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets" 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. We adopted SFAS No. 144 on January 1, 2002
and the adoption has not had a material impact on our business, financial
position or results of operations.

                                       27


Item 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations.

Results of Operations

First Quarter 2002 Compared With First Quarter 2001

   Our first quarter results continued to reflect solid returns from both our
existing assets and our recently acquired assets, including the operating
results of Kinder Morgan Tejas, which was acquired effective January 31, 2002.
The acquisition of Kinder Morgan Tejas was one of our largest acquisitions since
our current management took control of our general partner in February 1997, and
the inclusion of Kinder Morgan Tejas' operating results in the first quarter of
2002 operating results helped us to reach record levels of quarterly operating
income and net income. Kinder Morgan Tejas' operations include a 3,400-mile
intrastate natural gas pipeline system that has good access to natural gas
supply basins and provides a strategic, complementary fit with our other natural
gas pipeline assets in Texas, particularly Kinder Morgan Texas Pipeline. By
combining these intrastate pipeline systems, we expect to recognize operational
synergies, increase transportation capacity, improve reliability and create
additional services for our customer base.

   Our net income was $141.4 million ($0.48 per diluted unit) on revenues of
$803.1 million in the first quarter of 2002, compared to net income of $101.7
million ($0.44 per diluted unit) on revenues of $1,028.6 million in the first
quarter of 2001. Total consolidated operating income was $165.9 million in the
first quarter of 2002 versus $138.4 million in the same period last year. Our
operating expenses, consisting of gas purchases and other cost of sales, fuel,
power and operating and maintenance expenses were $553.8 million in the first
quarter of 2002 compared with $818.0 million in the same period a year ago.

   First quarter earnings from equity investments, net of amortization of excess
costs, were $21.9 million in 2002 versus $19.0 million in 2001. In addition, we
declared a record cash distribution of $0.59 per unit for the first quarter of
2002 (an annualized rate of $2.36). Our first quarter 2002 distribution is up
12% from the $0.525 per unit distribution made for the first quarter of 2001.

   Products Pipelines

   Our Products Pipelines segment reported earnings of $81.9 million on revenues
of $134.8 million in the first quarter of 2002. In the first quarter of 2001,
the segment reported earnings of $69.8 million on revenues of $190.7 million.
The $55.9 million (29%) decrease in quarter-to-quarter segment revenues includes
a reduction of $68.1 million in transmix revenues resulting from the Duke
contract as described below and a reduction of $1.7 million in operating
reimbursements from Plantation Pipe Line Company. During the first quarter of
2001, we entered into a 10-year agreement with Duke Energy Merchants to process
transmix on a fee basis only. Under the agreement, Duke Energy Merchants is
responsible for procurement of the transmix and sale of the products after
processing. This agreement allows us to eliminate commodity price exposure in
our transmix operations. The overall decrease in segment revenues was partly
offset by $11.6 million in revenues earned by CALNEV Pipe Line LLC and an
increase of $1.6 million in revenues earned from our ownership interest in the
Cochin Pipeline System. The increases reflect our acquisitions of CALNEV on
March 30, 2001 from GATX Corporation and an additional 10% interest in Cochin
(bringing our total interest to 44.8%) effective December 31, 2001. Revenues
from our Pacific operations increased $1.4 million (2%) primarily as a result of
higher average tariff rates, partially offset by lower non-transportation
revenues.

   Combined operating expenses for our Products Pipelines segment were $35.5
million in the first quarter of 2002 versus $103.8 million in the first quarter
of 2001. The reduction in expenses was primarily due to our agreement with Duke
Energy Merchants, which largely reduced our cost of products sold. Lower accrued
operating and maintenance expenses on the Central Florida Pipeline and at our
West Coast liquids terminal businesses, both acquired from GATX Corporation on
January 1, 2001, also contributed to the decrease in segment operating expenses.
The overall decrease in segment operating expenses was partially offset by
higher fuel and power expenses on our Pacific operations' pipelines.

   Earnings from our Products Pipelines' equity investments, net of amortization
of excess costs, were $7.2 million in the first quarter of 2002 versus $4.9
million in the same quarter of 2001. The $2.3 million increase was mainly
related to higher equity earnings from our 51% ownership interest in Plantation
Pipe Line Company. Plantation reported higher revenues and lower operating and
interest expenses during the first quarter of 2002 compared to the first quarter
of 2001.

                                       28


   Natural Gas Pipelines

   Our Natural Gas Pipelines segment reported earnings of $67.5 million on
revenues of $537.6 million in the first quarter of 2002. In the first quarter of
2001, the segment reported earnings of $58.7 million on revenues of $726.3
million. The $188.7 million decrease in segment revenues reflects a $394.7
million decline in revenues from the segment's Kinder Morgan Texas Pipeline
system, primarily due to lower gas prices. Offsetting the overall decrease in
segment revenues was the inclusion of $246.8 million of revenues earned by
Kinder Morgan Tejas and a $3.6 million (9%) increase in natural gas
transportation revenues earned by Kinder Morgan Texas Pipeline, Kinder Morgan
Intrastate Gas Transmission and Trailblazer Pipeline Company, mainly the result
of an 8% increase in transportation volumes.

   The segment's operating expenses totaled $461.3 million in the first quarter
of 2002 and $662.1 million in the first quarter of 2001. The $200.8 million
decrease in segment operating expenses primarily resulted from the drop in
natural gas prices. KMTP reported a $404.4 million decrease in operating
expenses, mostly consisting of lower gas purchase costs, and KMIGT reported an
$11.5 million decrease in operating expenses, mostly due to lower fuel costs and
less fuel lost and unaccounted for. The overall decrease in segment operating
expenses was partially offset by the inclusion of $232.9 million in expenses
from newly acquired Kinder Morgan Tejas, as well as by higher expenses on the
Trailblazer Pipeline, mainly the result of favorable system imbalance
settlements made in February 2001. For the two months ended March 31, 2002,
Kinder Morgan Tejas reported earnings of $10.9 million.

   Furthermore, Earnings from equity investments, net of amortization of excess
costs, were $6.1 million for the first quarter of 2002 versus $5.3 million for
the same prior year period. The $0.8 million increase in equity earnings was
mainly due to higher earnings from the segment's 49% interest in the Red Cedar
Gathering Company.

   CO2 Pipelines

   Our CO2 Pipelines segment reported earnings of $21.3 million on revenues of
$32.1 million in the first quarter of 2002. Combined operating expenses totaled
$10.8 million for the current quarter. For the same period last year, our CO2
Pipelines segment reported earnings of $23.5 million, revenues of $29.1 million
and combined operating expenses of $8.5 million. The 10% increase in segment
revenues was primarily due to increased oil production volumes from the SACROC
Unit. The decline in segment earnings was primarily due to higher depreciation,
depletion and amortization charges and to an increase in fuel and power
expenses. Non-cash depreciation charges were up $3.4 million as a result of
higher production volumes, the capital expenditures and acquisitions made since
the end of the first quarter of 2001 and a change in the calculation of our
depreciation rate. Higher fuel and power expenses were associated with higher
energy prices and the increase in volumes. The segment reported $8.6 million of
equity earnings, net of amortization of excess costs, in the first quarter of
2002 compared to $8.8 million in the first quarter of 2001. Equity earnings
represent the returns from the segment's 50% ownership interest in Cortez
Pipeline Company and from its 15% ownership interest in MKM Partners, L.P.

   Terminals

   Our Terminals segment, which includes both our bulk and liquid terminal
businesses, reported earnings of $38.9 million, revenues of $98.6 million and
operating expenses of $46.2 million in the first quarter of 2002. This compares
to earnings of $31.1 million, revenues of $82.6 million and operating expenses
of $43.5 million in the first quarter of 2001. The quarter-to-quarter increase
in segment revenue was driven by key acquisitions we have made since March 2001,
including:

    o  Pinney Dock & Transport LLC, acquired effective March 1, 2001;
    o  the terminal businesses we acquired from Koninklijke Vopak N.V.,
       effective July 10, 2001;
    o  the terminal businesses we acquired from The Boswell Oil Company,
       effective August 31, 2001;
    o  the terminal businesses we acquired from an affiliate of Stolt-Nielsen,
       Inc. in November 2001;
    o  Laser Materials Services LLC, acquired effective January 1, 2002; and
    o  a 66 2/3% interest in International Marine Terminals Partnership, 33 1/3%
       interest acquired effective January 1, 2002 and an additional 33 1/3%
       interest acquired effective February 1, 2002.

   In the first quarter of 2002, the acquisitions listed above generated
revenues of $23.6 million. Revenues from our bulk terminals owned during both
periods declined in the first quarter of 2002 due to a 5% decrease in transload
volumes. The decline in volumes was attributable to the mild winter that reduced
both coal and road salt tonnage. Revenues from our liquids terminals owned
during both periods were relatively flat, given continued high levels of
utilization (97%). In the future, we expect that these high utilization levels
will result in expansion opportunities and/or higher prices. The
$2.7 million increase in segment operating expenses in the first quarter of

                                       29




2002 compared to the first quarter of 2001 was mainly the result of the $158.4
million in terminal acquisitions made since the first quarter of 2001, partially
offset by lower engineering expenses.

Segment Operating Statistics

   Operating statistics for the first three months of 2002 and 2001 are as
follows:

                                                     Three Months Ended
                                                     March 31, March 31,
                                                     2002          2001
                                                     ----          ----
Products Pipelines
   Gasoline                                          108.2        100.8
   Diesel                                             36.5         40.2
   Jet Fuel                                           26.3         30.3
   NGL's                                              11.1         11.2
                                                     -----        -----
   Total Delivery Volumes (MBbl)(1)                  182.1        182.5
Natural Gas Pipelines
   Transport Volumes (Bcf) (2)                       214.6        208.1
CO2 Pipelines
   Delivery Volumes (Bcf) (3)                        113.1         98.7
Terminals
   Bulk Terminals
      Transload Tonnage (MMtons)(4)                   12.6         13.3
   Liquids Terminals
      Leaseable Capacity (MMBbl)                      34.5         30.9
      Utilization %                                    97%          97%
   Note:  Historical pro forma for acquired assets.
(1)   Includes Pacific, Plantation, North System, CALNEV, Central Florida,
      Cypress and Heartland pipeline volumes.
(2)   Includes KMIGT, KMTP, KM Tejas and Trailblazer pipeline volumes.
(3)   Includes Cortez, Central Basin and Canyon Reef Carriers pipeline volumes.
(4)   Includes Cora, Grand Rivers and Kinder Morgan Bulk Terminals aggregate
      terminal throughputs.

   Other

   Items not attributable to any segment include general and administrative
expenses, interest income and expense and minority interest. Together, these
items totaled $68.2 million in the first quarter of 2002 versus $81.4 million in
the first quarter of 2001. Our general and administrative expenses totaled $26.4
million in the first quarter of 2002 compared with $28.6 million in the first
quarter of 2001. The quarter-to-quarter decrease in general and administrative
expenses was mainly due to reduced expense relating to the pipeline and terminal
businesses that we acquired from GATX Corporation in 2001. In addition, during
the first quarter of 2001, we incurred additional administrative expenses
related to natural gas and products pipeline assets. We acquired additional
natural gas pipeline assets from Kinder Morgan, Inc. on December 31, 2000 and we
began assuming Plantation Pipe Line Company's operations on December 21, 2000.
We continue to manage aggressively our infrastructure expense and to focus on
our productivity and expense controls. Our total interest expense, net of
interest income, was $39.0 million in the first quarter of 2002 and $49.8
million in the first quarter of 2001. The decrease of $10.8 million was
primarily due to lower average interest rates during the first quarter of 2002
compared with the same period in 2001, partially offset by slightly higher
average borrowings. During the first quarter of 2002, we closed a public
offering of $750 million in principal amount of senior notes and retired a
maturing amount of $200 million in principal amount of senior notes.

Financial Condition

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

                                       30





                                        March 31, 2002  Dec. 31, 2001
                                        --------------  -------------
Long-term debt                            $2,959,661     $2,231,574
Minority interests                            64,480         65,236
Partners' capital                          3,080,206      3,159,034
                                        --------------  -------------
   Total capitalization                    6,104,347      5,455,844
Short-term debt, less cash and cash
equivalents                                  509,316        497,417
                                        --------------  -------------
   Total invested capital                $ 6,613,663     $5,953,261
                                        ==============  =============

Capitalization:
    Long-term debt                           48.5%          40.9%
    Minority interests                        1.0%           1.2%
    Partners' capital                        50.5%          57.9%

Invested Capital:
    Total debt                               52.5%          45.8%
    Partners' capital and minority
interests                                    47.5%          54.2%

   Our primary cash requirements, in addition to normal operating expenses, are
debt service, sustaining capital expenditures, expansion capital expenditures
and quarterly distributions to our common unitholders, class B unitholders and
general partner. In addition to utilizing cash generated from operations, we
could meet our cash requirements (other than distributions to our common
unitholders, class B unitholders and general partner) through borrowings under
our credit facilities or issuing short-term commercial paper, long-term notes,
additional common units or additional i-units to Kinder Morgan Management. In
general, we expect to fund:

        o    future cash distributions and sustaining capital expenditures with
             existing cash and cash flows from operating activities;
        o    expansion capital expenditures and working capital deficits through
             additional borrowings or issuance of additional common units or
             additional i-units to Kinder Morgan Management;
        o    interest payments from cash flows from operating activities; and
        o    debt principal payments with additional borrowings as they become
             due or by issuance of additional common units or additional i-units
             to Kinder Morgan Management.

   At March 31, 2002, our current commitments for capital expenditures were
approximately $66.0 million. This amount has been committed primarily for the
purchase of plant and equipment and is based on the payments we expect to need
for our 2002 sustaining capital expenditure plan. All of our capital
expenditures, with the exception of sustaining capital expenditures, are
discretionary.

   Operating Activities

   Net cash provided by operating activities was $222.6 million for the three
months ended March 31, 2002, versus $137.8 million in the comparable period of
2001. The period-to-period increase in cash flow from operations was the result
of higher cash inflows relative to net changes in current operating liabilities
as well as higher cash earnings from our business portfolio. Higher cash inflows
from net settlements of transportation imbalances with shippers on our natural
gas pipelines and gathering lines, and the additional operating cash flows
generated from our CALNEV and Kinder Morgan Tejas acquisitions accounted for
most of the increase. The overall increase in operating cash flows was partially
offset by lower cash flows relative to net settlement of hedging assets and
liabilities.

   Investing Activities

   Net cash used in investing activities was $849.3 million for the three months
ended March 31, 2002, compared to $1,051.8 million in the comparable 2001
period. The $202.5 million decrease in funds utilized in investing activities
primarily relates to the difference between the $700.9 million used to acquire
Kinder Morgan Tejas in the first quarter of 2002, versus the $979.2 million used
to purchase pipeline and terminal businesses from GATX Corporation in the first
quarter of 2001. Offsetting the overall decline in funds used in investing
activities was a $51.1 million increase in funds used for capital expenditures
in the first quarter of 2002 compared to the first quarter of 2001. Including
expansion and maintenance projects, our capital expenditures were $91.0 million
in the first quarter of 2002. We spent $39.9 million for capital expenditures in
the same year-ago period. The increase was driven primarily by continued
investment in our Natural Gas Pipelines and Terminals business segments.
Specifically, the increase relates to our previously announced construction of a
$70 million, 86-mile, 30-inch natural

                                       31




gas pipeline in Texas as well as an ongoing expansion project at our Carteret,
New Jersey liquids terminal. Our sustaining capital expenditures were $13.2
million for the first quarter of 2002 compared to $16.3 million for the first
quarter of 2001.

   Financing Activities

   Net cash provided by financing activities amounted to $593.2 million for the
three months ended March 31, 2002. The decrease of $521.3 million from the
comparable 2001 period was mainly the result of a $493.7 million decrease in
funds from overall debt financing activities. The decrease reflects higher net
debt issuance in the first quarter of 2001, as well as the payment of our
maturing $200 million in principal amount of Floating Rate senior notes in March
2002. In March 2002, we completed a public offering of $750 million in principal
amount of senior notes, resulting in a net cash inflow of approximately $740.8
million net of discounts and issuing costs. We used the proceeds to reduce our
borrowings under our commercial paper program. In the first quarter of 2001, we
completed a public offering of $1.0 billion in principal amount of senior notes,
resulting in a net cash inflow of approximately $990 million net of discounts
and issuing costs. We used the $990 million to pay for our acquisition of Pinney
Dock & Transport LLC and to reduce our outstanding balance on our credit
facilities and commercial paper borrowings.

   The overall decrease in funds provided by our financing activities also
resulted from a $35.6 million increase in distributions to our partners.
Distributions to all partners increased to $132.3 million in the first quarter
of 2002 compared to $96.7 million in the same year-ago period. The increase in
distributions was due to:

        o   an increase in the per unit cash distributions paid;
        o   an increase in the number of units outstanding; and
        o   an increase in the general partner incentive distributions, which
            resulted from both increased cash distributions per unit and an
            increase in the number of common units and i-units outstanding.

   On February 14, 2002, we paid a quarterly distribution of $0.55 per unit for
the fourth quarter of 2001, 16% greater than the $0.475 distribution paid for
the fourth quarter of 2000. We paid this distribution in cash to our common
unitholders and to our class B unitholders. Kinder Morgan Management, our sole
i-unitholder, received additional i-units based on the $0.55 cash distribution
per common unit. For each outstanding i-unit that Kinder Morgan Management, LLC
held, a fraction of an i-unit was issued. The fraction was determined by
dividing:

        o   the cash amount distributed per common unit

   by

        o   the average of Kinder Morgan Management's shares' closing market
            prices for the ten consecutive trading days preceding the date on
            which the shares began to trade ex-dividend under the rules of the
            New York Stock Exchange.

   On April 17, 2002, we declared a cash distribution for the quarterly period
ended March 31, 2002, of $0.59 per unit. The distribution will be paid on or
before May 15, 2002, to unitholders of record as of April 30, 2002. Our common
unitholders and class B unitholders will receive cash. Kinder Morgan Management,
LLC, our sole i-unitholder will receive a distribution in the form of additional
i-units based on the $0.59 distribution per common unit. We believe that future
operating results will continue to support similar levels of quarterly cash
distributions, however, no assurance can be given that future distributions will
continue at such levels.

   Partnership Distributions

   Our partnership agreement requires that we distribute 100% of available cash
as defined in our partnership agreement to our partners within 45 days following
the end of each calendar quarter in accordance with their respective percentage
interests. Available cash consists generally of all of our cash receipts,
including cash received by our operating partnerships, less cash disbursements
and net additions to reserves (including any reserves required under debt
instruments for future principal and interest payments) and amounts payable to
the former general partner of SFPP, L.P. in respect of its remaining 0.5%
interest in SFPP.

   Our general partner is granted discretion by our partnership agreement, which
discretion has been delegated to Kinder Morgan Management, 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 Kinder Morgan Management
determines our quarterly

                                       32




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 Kinder Morgan Management, the sole
owner of our i-units, receives distributions in additional i-units. For each
outstanding i-unit, a fraction of an i-unit will be issued. The fraction is
calculated by dividing the amount of cash being distributed per common unit by
the average closing price of Kinder Morgan Management's shares over the ten
consecutive trading days preceding the date on which the shares begin to trade
ex-dividend under the rules of the New York Stock Exchange. The cash equivalent
of distributions of i-units will be treated as if it had actually been
distributed for purposes of determining the distributions to our general
partner. We will not distribute cash to i-unit owners but will retain the cash
for use in our business.

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

   Available cash for each quarter is distributed:

   o  first, 98% to the owners of all classes of units pro rata and 2% to our
      general partner until the owners of all classes of units have received a
      total of $0.15125 per unit in cash or equivalent i-units for such quarter;
   o  second, 85% of any available cash then remaining to the owners of all
      classes of units pro rata and 15% to our general partner until the owners
      of all classes of units have received a total of $0.17875 per unit in cash
      or equivalent i-units for such quarter;
   o  third, 75% of any available cash then remaining to the owners of all
      classes of units pro rata and 25% to our general partner until the owners
      of all classes of units have received a total of $0.23375 per unit in cash
      or equivalent i-units for such quarter; and
   o  fourth, 50% of any available cash then remaining to the owners of all
      classes of units pro rata, to owners of common units and class B units in
      cash and to owners of i-units in the equivalent number of i-units, and 50%
      to our general partner.

   Incentive distributions are generally defined as all cash distributions paid
to our general partner that are in excess of 2% of the aggregate amount of cash
being distributed. The general partner's incentive distribution for the
distribution that we declared for the first quarter of 2002 was $61.0 million.
The general partner's incentive distribution for the distribution that we
declared for the first quarter of 2001 was $41.0 million. The general partner's
incentive distribution that we paid to our general partner was $54.4 million
during the first quarter of 2002 and $32.8 million during the first quarter of
2001. All partnership distributions we declare for the fourth quarter of each
year are declared and paid in the first quarter of the following year.

Information Regarding Forward-Looking Statements

   This filing includes forward-looking statements within the meaning of Section
27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act
of 1934. These forward-looking statements are identified as any statement that
does not relate strictly to historical or current facts. They use words such as
"anticipate," "believe," "intend," "plan," "projection," "forecast," "strategy,"
"position," "continue," "estimate," "expect," "may," "will," or the negative of
those terms or other variations of them or comparable terminology. In
particular, statements, express or implied, concerning future operating results
or the ability to generate sales, income or cash flow are forward-looking
statements. Forward-looking statements are not guarantees of performance. They
involve risks, uncertainties and assumptions. The future results of our
operations may differ materially from those expressed in these forward-looking
statements. Many of the factors that will determine these results are beyond our
ability to control or predict. Specific factors which could cause actual results
to differ from those in the forward-looking statements, include:

   o  price trends and overall demand for natural gas liquids, refined petroleum
      products, oil, carbon dioxide, natural gas, coal and other bulk materials
      and chemicals in the United States, which may be affected by consumer
      confidence, economic activity, political instability, weather, alternative
      energy sources, conservation and technological advances;
   o  changes in our tariff rates implemented by the Federal Energy Regulatory
      Commission or the California Public Utilities Commission;
   o  our ability to integrate any acquired operations into our existing
      operations;
   o  any difficulties or delays experienced by railroads, barges, trucks, ships
      or pipelines in delivering products to our terminals;

                                       33


   o  our ability to successfully identify and close strategic acquisitions and
      make cost saving changes in operations;
   o  shut-downs or cutbacks at major refineries, petrochemical or chemical
      plants, utilities, military bases or other businesses that use or supply
      our services;
   o  changes in laws or regulations, third party relations and approvals,
      decisions of courts, regulators and governmental bodies may adversely
      affect our business or our ability to compete;
   o  indebtedness could make us vulnerable to general adverse economic and
      industry conditions, limit our ability to borrow additional funds, place
      us at competitive disadvantages compared to our competitors that have less
      debt or have other adverse consequences;
   o  interruptions of electric power supply to our facilities due to natural
      disasters, power shortages, strikes, riots, terrorism, war or other
      causes;
   o  acts of sabotage, terrorism or other similar acts causing damage greater
      than our insurance coverage;
   o  the condition of the capital markets and equity markets in the United
      States; and
   o  the political and economic stability of the oil producing nations of the
      world.

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

   See Items 1 and 2 "Business and Properties - Risk Factors" of our annual
report filed on Form 10-K for the year ended December 31, 2001, for a more
detailed description of these and other factors that may affect the
forward-looking statements. When considering forward-looking statements, one
should keep in mind the risk factors described in our 2001 Form 10-K report. The
risk factors could cause our actual results to differ materially from those
contained in any forward-looking statement.

Item 3.  Quantitative and Qualitative Disclosures About Market Risk.

   There have been no material changes in market risk exposures that would
affect the quantitative and qualitative disclosures presented as of December 31,
2001, in Item 7a of our 2001 Form 10-K report. For more information on our risk
management activities, see Note 10 to our consolidated financial Statements
included elsewhere in this report.




                                       34




PART II.  OTHER INFORMATION

Item 1.  Legal Proceedings.

   See Part I, Item 1, Note 3 to our consolidated financial statements entitled
"Litigation and Other Contingencies", which is incorporated herein by reference.

Item 2.  Changes in Securities and Use of Proceeds.

   None.

Item 3.  Defaults Upon Senior Securities.

   None.

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

   None.

Item 5.  Other Information.

   None.

Item 6.   Exhibits and Reports on Form 8-K.

   (a) Exhibits

     1.1   -  Form of Underwriting Agreement dated March 11, 2002 between
              Kinder Morgan Energy Partners, L.P. and J.P. Morgan Securities
              Inc., First Union Securities, Inc., Banc One Capital Markets,
              Inc., BMO Nesbitt Burns Corp., Commerzbank Capital Markets
              Corp., Credit Lyonnais Securities (USA) Inc., Scotia Capital
              (USA) Inc. and Sun Trust Capital Markets, Inc.
    *2.1   -  Purchase and Sale Agreement between Intergen (North America),
              Inc. and Kinder Morgan Energy Partners, L.P. dated December 15,
              2001 (filed as Exhibit 2.1 to Kinder Morgan Energy Partners,
              L.P. Form 8-K filed March 15, 2002).
    *2.2   -  First Supplement to Purchase and Sale Agreement between
              Intergen (North America), Inc. and Kinder Morgan Energy
              Partners, L.P. dated February 28, 2002 (filed as Exhibit 2.2 to
              Kindger Morgan Energy Partners, L.P. Form 8-K filed March 15,
              2002).
     4.1   -  Certificate of Vice President and Chief Financial Officer of
              Kinder Morgan Energy Partners, L.P. establishing the terms of
              the 7.125% Notes due March 15, 2012 and the 7.750% Notes due
              March 15, 2032.
     4.2   -  Specimen of 7.125% Notes due March 15, 2012 in book-entry form.
     4.3   -  Specimen of 7.750% Notes due March 15, 2032 in book-entry form.
     4.4   -  Certain instruments with respect to long-term debt of the
              Partnership and its consolidated subsidiaries which relate to debt
              that does not exceed 10% of the total assets of the Partnership
              and its consolidated subsidiaries are omitted pursuant to Item
              601(b) (4) (iii) (A) of Regulation S-K, 17 C.F.R. ss.229.601. The
              Partnership hereby agrees to furnish supplementally to the
              Securities and Exchange Commission a copy of each such instrument
              upon request.
   *10.1   -  Retention Agreement dated January 17, 2002, by and between
              Kinder Morgan, Inc. and C. Park Shaper (incorporated by reference
              from Exhibit 10(l) of Kinder Morgan, Inc.'s Annual Report on Form
              10-K for the period ending December 31, 2001).
    10.2   -  Form of Third Amendment to Credit Agreement dated as of February
              19, 2002 among Kinder Morgan Energy Partners, L.P. and the lender
              parties thereto.
    10.3   -  Form of Bridge Credit Agreement dated as of February 21, 2002
              among Kinder Morgan Energy Partners, L.P. and the lenders party
              thereto.
    11     -  Statement re: computation of per share earnings
- ---------------------
*  Asterisk indicates exhibits incorporated by reference as indicated; all other
   exhibits are filed herewith.

                                       35


   (b) Reports on Form 8-K

   Current report dated January 16, 2002 on Form 8-K was filed on January 16,
2002, pursuant to Item 9 of that form. We provided notice that we, along with
Kinder Morgan, Inc., a subsidiary of which serves as our general partner, and
Kinder Morgan Management, LLC, a subsidiary of our general partner that manages
and controls our business and affairs, intended to make several presentations on
January 17, 2002 at the 2002 Kinder Morgan Analyst Conference to analysts and
others to address various strategic and financial issues relating to the
business plans and objectives of us, Kinder Morgan, Inc. and Kinder Morgan
Management, LLC. Notice was also given that prior to the meeting, interested
parties would be able to view the materials presented at the meetings by
visiting Kinder Morgan, Inc.'s website at:
http://www.kindermorgan.com/investor_relations/presentations/

   Current Report dated March 11, 2002 on Form 8-K was filed on March 12, 2002,
pursuant to Item 7 of that form. We filed the Consolidated Balance Sheet at
December 31, 2001, of Kinder Morgan G.P., Inc., our general partner and a
wholly-owned subsidiary of Kinder Morgan, Inc. as an exhibit pursuant to Item 7
of that form.

   Current report dated March 15, 2002 on Form 8-K was filed on March 15, 2002,
pursuant to Items 2 and 7 of that form. We provided notice that on February 28,
2002, Kinder Morgan Operating L.P. "A", one of our operating partnerships,
completed the acquisition of all the membership interests of Tejas Gas, LLC from
InterGen (North America), Inc. The acquisition was effective as of January 31,
2002 and in consideration for the sale, we paid a base purchase price of
approximately $684.5 million and assumed debt and other liabilities of
approximately $71 million, net of working capital assets. We filed the following
documents as exhibits pursuant to Item 7:

   o  Purchase and Sale Agreement between InterGen (North America), Inc. and
      ourselves dated December 15, 2001;
   o  First Supplement to Purchase and Sale Agreement between InterGen (North
      America), Inc. and ourselves dated February 28, 2002; and
   o  Press release announcing the acquisition of Tejas Gas from InterGen (North
      America), Inc. issued February 28, 2002.



                                       36





                                  SIGNATURES

   Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.

                          KINDER MORGAN ENERGY PARTNERS, L.P.
                          (A Delaware limited partnership)

                           By: KINDER MORGAN G.P., INC.,
                              its General Partner

                            By: KINDER MORGAN MANAGEMENT, LLC,
                              its Delegate

                              By:  /s/ C. Park Shaper
                              ------------------------------
                              C. Park Shaper
                              Vice President, Treasurer and Chief Financial
                                Officer
                              Date:  May 10, 2002