<PAGE>

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

                                   FORM 10-K

<Table>
<C>          <S>
    [X]      ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
             OF THE SECURITIES EXCHANGE ACT OF 1934



               FOR THE FISCAL YEAR ENDED DECEMBER 31, 2001
                                   OR
    [ ]      TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
             OF THE SECURITIES EXCHANGE ACT OF 1934
               FOR THE TRANSITION PERIOD FROM          TO
</Table>

                        COMMISSION FILE NUMBER: 1-11234

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

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

                  500 DALLAS, SUITE 1000, HOUSTON, TEXAS 77002
               (Address of principal executive offices)(zip code)

        REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: 713-369-9000
                             ---------------------

          SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

<Table>
<Caption>
 TITLE OF EACH CLASS   NAME OF EACH EXCHANGE ON WHICH REGISTERED
 -------------------   -----------------------------------------
<S>                    <C>
    Common Units               New York Stock Exchange
</Table>

          SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
                                      NONE

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

     Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K.  [X]

     Aggregate market value of the Common Units held by non-affiliates of the
registrant, based on closing prices in the daily composite list for transactions
on the New York Stock Exchange on January 31, 2002 was approximately
$3,768,143,733. This figure assumes that only the general partner of the
registrant, Kinder Morgan, Inc., Kinder Morgan Management, LLC, their
subsidiaries and their officers and directors were affiliates. As of January 31,
2002, the registrant had 129,862,418 Common Units outstanding.
--------------------------------------------------------------------------------
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<PAGE>

                      KINDER MORGAN ENERGY PARTNERS, L.P.

                               TABLE OF CONTENTS

<Table>
<Caption>
                                                                                  PAGE
                                                                                 NUMBER
                                                                                 ------
<S>               <C>                                                            <C>
                                             PART I
Items 1 and 2.    Business and Properties.....................................        1
                  General.....................................................        1
                  Business Strategy...........................................        4
                  Recent Developments.........................................        5
                  Products Pipelines..........................................        6
                  Natural Gas Pipelines.......................................       16
                  CO(2) Pipelines.............................................       20
                  Terminals...................................................       22
                  Major Customers.............................................       25
                  Employees...................................................       25
                  Regulation..................................................       26
                  Environmental Matters.......................................       29
                  Risk Factors................................................       31
Item 3.           Legal Proceedings...........................................       34
Item 4.           Submission of Matters to a Vote of Security Holders.........       34

                                            PART II
Item 5.           Market for the Registrant's Equity and Related Security
                  Holder Matters..............................................       34
Item 6.           Selected Financial Data.....................................       35
Item 7.           Management's Discussion and Analysis of Financial Condition
                  and Results of Operations...................................       37
                  Critical Accounting Policies and Estimates..................       37
                  Results of Operations.......................................       37
                  Outlook.....................................................       42
                  Liquidity and Capital Resources.............................       44
                  New Accounting Pronouncements...............................       55
                  Information Regarding Forward-Looking Statements............       56
Item 7A.          Quantitative and Qualitative Disclosures About Market
                  Risk........................................................       57
Item 8.           Financial Statements and Supplementary Data.................       59
Item 9.           Changes in and Disagreements with Accountants on Accounting
                  and Financial Disclosure....................................       59

                                            PART III
Item 10.          Directors and Executive Officers of the Registrant..........       60
Item 11.          Executive Compensation......................................       63
Item 12.          Security Ownership of Certain Beneficial Owners and
                  Management..................................................       68
Item 13.          Certain Relationships and Related Transactions..............       70

                                            PART IV
Item 14.          Exhibits, Financial Statement Schedules, and Reports on Form
                  8-K.........................................................       71
                  Financial Statements........................................       71
                                                                                    138
Signatures....................................................................
</Table>
<PAGE>

                                     PART I

ITEMS 1. AND 2.  BUSINESS AND PROPERTIES.

GENERAL

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

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

     - transporting, storing and processing refined petroleum products;

     - transporting, storing and selling natural gas;

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

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

     We focus on providing fee-based services to customers, avoiding commodity
price risks and taking advantage of the low-cost capital available in a limited
partnership structure. The assets we own or operate include:

     - more than 10,000 miles of products pipelines and over 32 associated
       terminals serving customers across the United States;

     - 10,000 miles of natural gas transportation pipelines, plus natural gas
       gathering and storage facilities;

     - ownership interests in carbon dioxide pipelines and carbon dioxide and
       oil reserves, all owned by Kinder Morgan CO(2) Company, L.P., the largest
       transporter and marketer of carbon dioxide used in enhanced oil recovery
       operations in the United States; and

     - over 44 terminal facilities which transload and store refined petroleum
       products, coal, chemicals, and other dry and liquid bulk products.

     On October 7, 1999, K N Energy, Inc., a Kansas corporation that provided
integrated energy services, including the gathering, processing, transportation
and storage of natural gas, the marketing of natural gas and natural gas liquids
and the generation of electric power, acquired Kinder Morgan (Delaware), Inc., a
Delaware corporation. Kinder Morgan (Delaware), Inc. is the sole stockholder of
our general partner, Kinder Morgan G.P., Inc. At the time of the closing of the
acquisition, K N Energy, Inc. changed its name to Kinder Morgan, Inc., referred
to herein as KMI. In connection with the acquisition, Richard D. Kinder,
Chairman and Chief Executive Officer of our general partner and its delegate,
became the Chairman and Chief Executive Officer of KMI. KMI trades on the New
York Stock Exchange under the symbol "KMI" and is one of the largest energy
transportation and storage companies in the United States, operating more than
30,000 miles of natural gas and products pipelines. KMI also has significant
retail distribution and electric generation assets. KMI, including its
consolidated subsidiaries, holds an approximate 18.5% ownership interest in us.

     Kinder Morgan Management, LLC, a Delaware limited liability company, called
"Kinder Morgan Management" in this document, was formed on February 14, 2001.
Our general partner owns all of Kinder Morgan Management's voting securities.

     In May 2001, Kinder Morgan Management issued 2,975,000 of its shares
representing limited liability company interests to KMI and 26,775,000 of its
shares representing limited liability company interests

                                        1
<PAGE>

with limited voting rights to the public in an initial public offering. Its
shares were issued at a price of $35.21 per share, less commissions and
underwriting expenses, and it used substantially all of the net proceeds from
that offering to purchase i-units from us. The i-units are a separate class of
limited partner interests in us and are issued only to Kinder Morgan Management.
Quarterly distributions from operations and from interim capital transactions
are paid to Kinder Morgan Management in additional i-units rather than in cash.
Kinder Morgan Management trades on the New York Stock Exchange under the symbol
"KMR". Kinder Morgan Management shares were split two-for-one on August 31,
2001, and all dollar and numerical references to Kinder Morgan Management shares
in this paragraph and in this report have been adjusted to reflect the effect of
the split.

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

     The address of our principal executive offices is 500 Dallas, Suite 1000,
Houston, Texas 77002, and our telephone number at this address is (713)
369-9000. Our common units trade on the New York Stock Exchange under the symbol
"KMP".

     Our operations are grouped into four reportable business segments. These
segments and their major assets are as follows:

     - Products Pipelines, consisting of refined petroleum products and natural
       gas liquids pipelines, related terminals and transmix processing
       facilities including:

      - our SFPP, L.P. operations, which are part of our Pacific operations and
        comprised of approximately 3,300 miles of pipeline that transports
        refined petroleum products to some of the faster growing population
        centers in the United States, including Los Angeles, San Diego, and
        Orange County, California; the San Francisco Bay Area; Las Vegas, Nevada
        (through our CALNEV pipeline) and Tucson and Phoenix, Arizona, and 13
        truck-loading terminals with an aggregate usable tankage capacity of
        approximately 8.2 million barrels;

      - our CALNEV pipeline operations, which are part of our Pacific operations
        and comprised of a 550 mile pipeline that transports refined petroleum
        products from Colton, California to the growing Las Vegas, Nevada
        market, and two refined petroleum products terminals located in Barstow,
        California and Las Vegas, Nevada;

      - our West Coast terminals operations, which are part of our Pacific
        operations and comprised of six terminal facilities on the West Coast
        that transload and store refined petroleum products;

      - our Central Florida Pipeline, a 195 mile pipeline that transports
        refined petroleum products from Tampa to the Orlando, Florida market;

      - our North System, a 1,600 mile pipeline that transports natural gas
        liquids and refined petroleum products between south central Kansas and
        the Chicago area and various intermediate points, including eight
        terminals;

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

                                        2
<PAGE>

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

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

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

      - our 50% interest in the Heartland Pipeline Company, which ships refined
        petroleum products in the Midwest.

     - Natural Gas Pipelines, consisting of assets primarily acquired in late
       1999 and 2000 including:

      - Kinder Morgan Interstate Gas Transmission LLC, which owns a 6,100 mile
        natural gas pipeline, including the Pony Express pipeline system, that
        extends from northwestern Wyoming east into Nebraska and Missouri and
        south through Colorado and Kansas;

      - our Kinder Morgan Texas Pipeline, a 2,500 mile intrastate natural gas
        pipeline along the Texas Gulf Coast;

      - our 66 2/3% interest in the Trailblazer Pipeline Company, which
        transmits natural gas from Colorado through southeastern Wyoming to
        Beatrice, Nebraska;

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

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

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

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

     - CO(2) Pipelines, consisting of Kinder Morgan CO(2) Company, L.P., which
       transports, markets and produces carbon dioxide for use in enhanced oil
       recovery operations and owns interests in other related assets in the
       continental United States, through the following:

      - Central Basin Pipeline, a 300 mile carbon dioxide pipeline located in
        the Permian Basin of West Texas between Denver City, Texas and McCamey,
        Texas;

      - interests in carbon dioxide pipelines, including an approximate 81%
        interest in the Canyon Reef Carriers Pipeline, a 50% interest in the
        Cortez Pipeline and a 13% interest in the Bravo Dome Pipeline;

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

      - interests in oil-producing fields, including a greater than 80% interest
        in the SACROC Unit and minority interests in the Sharon Ridge Unit, the
        Reinecke Unit and the Yates Field Unit, all of which are located in the
        Permian Basin of West Texas; and

      - approximately 22% ownership interest in the Snyder Gasoline Plant and a
        43% ownership interest in the Diamond M Gas Plant, both of which process
        gas produced from the SACROC unit and neighboring carbon dioxide
        projects in the Permian Basin.

                                        3
<PAGE>

     - Terminals, consisting of 44 owned or operated liquid and bulk terminal
       facilities including:

      - five liquid chemical terminals located in New Orleans, Louisiana,
        Cincinnati, Ohio, Pittsburgh, Pennsylvania and Chicago, Illinois;

      - five liquid terminals located in Houston, Texas, Carteret, New Jersey,
        Chicago, Illinois and Philadelphia, Pennsylvania;

      - one liquid chemical, petroleum and dry-bulk handling facility located in
        Perth Amboy, New Jersey;

      - four coal terminals located in Cora, Illinois; Paducah, Kentucky;
        Newport News, Virginia; and Los Angeles, California;

      - eight petroleum coke terminals located on the lower Mississippi River
        and along the west coast of the United States; and

      - 21 other bulk terminals located throughout the United States handling
        alumina, cement, salt, soda ash, fertilizer and other dry bulk
        materials.

BUSINESS STRATEGY

     Our management's objective is to grow our portfolio of businesses by:

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

     - increasing utilization of assets while containing costs;

     - leveraging economies of scale from incremental acquisitions; and

     - maximizing the benefits of our financial structure.

     Since February 1997, we have announced over 30 acquisitions, including
those listed under "Recent Developments," valued at over $6.1 billion. These
acquisitions and associated cost reductions have assisted us in growing from
$17.7 million of net income in 1997 to $442.3 million of net income in 2001. We
regularly consider and enter into discussions regarding potential acquisitions,
including those from KMI or its affiliates, and are currently contemplating
potential acquisitions. While there are currently no unannounced purchase
agreements for the acquisition of any material business or assets, such
transactions can be effected quickly, may occur at any time and may be
significant in size relative to our existing assets or operations.

     We primarily transport and/or handle products for a fee and generally are
not engaged in the unmatched purchase and sale of commodity products. As a
result, we do not face significant risks relating directly to shifts in
commodity prices.

     Products Pipelines.  We plan to continue to expand our presence in the
rapidly growing refined petroleum products markets in the western and
southeastern United States through incremental expansions of pipelines and
through acquisitions that we believe will increase unitholder distributions.
Because our North system serves a relatively mature market, we intend to focus
on increasing throughput within the system by remaining a reliable,
cost-effective provider of transportation services and by continuing to increase
the range of products transported and services offered.

     Natural Gas Pipelines.  Kinder Morgan Interstate Gas Transmission serves a
stable, mature market, and thus we are focused on reducing costs and securing
throughput for this pipeline. New measurement systems and other improvements
will aid in managing expenses. We will explore expansion and storage
opportunities to increase utilization levels. Kinder Morgan Texas Pipeline
intends to grow its transportation and storage businesses by identifying and
serving significant new customers with demand for capacity on its intrastate
pipeline system. Trailblazer is currently constructing an expansion of its
system supported by

                                        4
<PAGE>

commitments secured in August 2000. Red Cedar Gathering Company, a partnership
with the Southern Ute Indian Tribe, is pursuing additional gathering and
processing opportunities on tribal lands.

     CO(2) Pipelines.  Kinder Morgan CO(2) Company, L.P.'s Permian Basin
strategy is to offer customers "one-stop shopping" for carbon dioxide supply,
transportation and technical support service. Outside the Permian Basin, we
intend to compete aggressively for new supply and transportation projects. Our
management believes these projects will arise as other United States oil
producing basins mature and make the transition from primary production to
enhanced recovery methods.

     Terminals.  We are dedicated to growing our terminals segment through a
core strategy which includes dedicating capital to expand existing facilities,
maintaining a strong commitment to operational safety and efficiency and growing
through strategic acquisitions. During 2001, we significantly enlarged our
ownership and operation of liquids terminals, primarily due to our purchase of
GATX Corporation's domestic liquids terminal businesses. The bulk terminals
industry in the United States is highly fragmented, leading to opportunities for
us to make selective, accretive acquisitions. We will make investments to expand
and improve existing facilities, particularly those facilities that handle low
sulfur western coal. Additionally, we plan to design, construct and operate new
facilities for current and prospective customers. Our management believes we can
use newly acquired or developed facilities to leverage our operational expertise
and customer relationships. In addition, we believe the combination of our
liquids and bulk terminals businesses into one segment gives us a competitive
advantage in pursuing acquisitions of terminals that handle bulk and liquid
materials.

RECENT DEVELOPMENTS

     During 2001, our assets increased 46% and our net income increased 59% from
2000 levels. In addition, distributions per unit increased 16% from $0.475 for
the fourth quarter of 2000 to $0.55 for the fourth quarter of 2001.

     The following is a brief listing of activity since the end of the third
quarter of 2001. Additional information regarding these items is contained in
the rest of this report.

     - On October 2, 2001, we announced plans to construct a $70 million,
       86-mile, 30-inch natural gas pipeline in Texas. The new pipeline will
       transport natural gas from an interconnect with KMI's Natural Gas
       Pipeline Company of America system in Lamar County, Texas to an existing
       1,000-megawatt electric generating facility in Lamar County, as well as a
       new 1,789-megawatt electric generating facility currently being built in
       Kaufman County, Texas by FPL Energy, LLC, a subsidiary of FPL Group, Inc.
       FPL Energy has executed a 30-year binding firm-transportation contract
       with Kinder Morgan North Texas Pipeline, L.P. Additionally, FPL executed
       a 20-year binding firm-transportation contract for 250,000 dekatherms of
       natural gas per day with Natural Gas Pipeline Company of America, which
       will be the primary transportation service provider for the new plant;

     - On October 23, 2001, we announced two separate transactions totaling $25
       million to further expand our Terminals business segment. We signed a
       letter of intent to add a $20 million cement-handling system at our
       Dakota Bulk Terminal located in St. Paul, Minnesota. We also purchased
       for $5 million from International Raw Materials, Ltd. its rights and
       obligations under an agreement with the Port of Longview, Washington, for
       the exclusive use and operation of its bulk-material handling facility;

     - On November 8, 2001, we acquired a liquids terminal in Perth Amboy, New
       Jersey for $51.2 million, including $25 million of assumed debt, from
       Stolthaven Perth Amboy Inc. and Stolt-Nielsen Transportation Group, Ltd.
       The Perth Amboy facility provides liquid chemical and petroleum storage
       and handling, as well as dry-bulk handling of salt and aggregates, with
       liquid capacity exceeding 2.3 million barrels;

     - On November 14, 2001, Kinder Morgan CO(2) Company, L.P., one of our
       operating limited partnerships, purchased Mission Resources Corporation's
       interests in the Snyder Gasoline Plant and

                                        5
<PAGE>

       the Diamond M Gas Plant for approximately $11.5 million. In addition,
       Kinder Morgan CO(2) Company, L.P. initiated a $14.9 million expansion of
       its carbon dioxide project in the SACROC Unit;

     - On November 29, 2001, we acquired a liquids terminal in Chicago, Illinois
       for $18.6 million from Stolthaven Chicago Inc. and Stolt-Nielsen
       Transportation Group, Ltd. The Chicago terminal handles a wide variety of
       liquid chemicals with a working capacity in excess of 0.7 million
       barrels;

     - In December 2001, Kinder Morgan CO(2) Company, L.P. purchased Torch E&P
       Company's interest in the Snyder Gasoline Plant and entered into a
       definitive agreement to purchase Torch's interest in the Diamond M Gas
       Plant. All of these assets are located in the Permian Basin of west
       Texas;

     - On December 12, 2001, we signed a definitive agreement to acquire the
       remaining portion of Trailblazer Pipeline Company that we did not already
       own from Enron Trailblazer Pipeline Company for $68 million. The
       agreement is subject to the approval of the court overseeing the Enron
       Corp. bankruptcy. KMI operates, on our behalf, Trailblazer's 436-mile
       interstate natural gas pipeline that runs from Rockport, Colorado to
       Beatrice, Nebraska;

     - On December 17, 2001, we signed a definitive agreement to purchase Tejas
       Gas, LLC, a wholly-owned subsidiary of InterGen (North America), Inc.,
       for approximately $750 million. InterGen is a joint venture owned by
       affiliates of the Royal Dutch/Shell Group of Companies and Bechtel
       Enterprises Holding, Inc. Tejas Gas owns a 3,400-mile intrastate natural
       gas pipeline that runs 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;

     - In January 2002, we paid approximately $29 million to NOVA Chemicals
       Corporation for an additional 10% ownership interest in the Cochin
       Pipeline System. Including this acquisition, we now own approximately
       44.8% of the Cochin Pipeline System. The acquisition was effective as of
       December 31, 2001; and

     - On February 4, 2002, we announced two acquisitions and a major expansion
       program, both within our Terminals business segment, representing
       approximately $43 million. The purchases included Pittsburgh,
       Pennsylvania-based Laser Materials LLC, operator of 59 transload
       facilities in 18 states, and a 66 2/3% ownership interest in
       International Marine Terminals Partnership, which operates a bulk
       terminal site in Port Sulphur, Louisiana. The expansion project will
       occur at our Carteret, New Jersey liquids terminal and will add 400,000
       barrels of storage within the next year.

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

PRODUCTS PIPELINES

  PACIFIC OPERATIONS

     Our Pacific operations include interstate common carrier pipelines
regulated by the Federal Energy Regulatory Commission, intrastate pipelines in
California regulated by the California Public Utilities Commission and certain
non rate-regulated operations. Our Pacific operations also include our West
Coast Terminals.

     The Pacific operations' pipelines are split into a South Region and a North
Region. Combined, the two regions consist of seven pipeline segments that serve
six western states with approximately 3,900 miles of refined petroleum products
pipeline and related terminal facilities.

                                        6
<PAGE>

     Refined petroleum products and related uses are:

<Table>
<Caption>
PRODUCT                                                       USE
-------                                                       ---
<S>                                        <C>
Gasoline.................................  Transportation
Diesel fuel..............................  Transportation (auto, rail, marine),
                                           farm, industrial and commercial
Jet fuel.................................  Commercial and military air
                                           transportation
</Table>

     Our Pacific operations transport over one million barrels per day of
refined petroleum products, providing pipeline service to approximately 44
customer-owned terminals, four commercial airports and 15 military bases. For
2001, the three main product types transported were gasoline (61%), diesel fuel
(22%) and jet fuel (17%). Our Pacific operations also include 15 truck-loading
terminals (13 on SFPP, L.P. and two on CALNEV).

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

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

     - West Line;

     - East Line;

     - San Diego Line; and

     - CALNEV Line.

     The West Line consists of approximately 630 miles of primary pipeline and
currently transports products for approximately 50 shippers from six refineries
and three pipeline terminals in the Los Angeles Basin to Phoenix and Tucson,
Arizona and various intermediate commercial and military delivery points.
Product for the West Line can also come from foreign sources through the Los
Angeles and Long Beach port complexes and the three pipeline terminals. A
significant portion of West Line volumes is transported to Colton, California
for local distribution and for delivery to our CALNEV Pipeline. The West Line
serves our terminals located in Colton and Imperial, California as well as in
Tucson and Phoenix, Arizona.

     The East Line is comprised of two parallel 8-inch and 12-inch pipelines
originating in El Paso, Texas and continuing approximately 300 miles west to our
Tucson terminal and one line continuing northwest approximately 130 miles from
Tucson to Phoenix. All products received by the East Line at El Paso come from a
refinery in El Paso or are delivered through connections with non-affiliated
pipelines from refineries in Texas and New Mexico. The East Line serves our
terminals located in Tucson and Phoenix as well as various intermediate
commercial and military delivery points.

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

     The CALNEV Pipeline consists of two parallel 248-mile 14-inch and 8-inch
pipelines from our facilities at Colton, California to Las Vegas, Nevada. It
also includes approximately 55 miles of pipeline serving Edwards Air Force Base.
We completed our purchase of the CALNEV Pipeline from GATX on March 30, 2001.
This pipeline originates at Colton, California and serves two CALNEV terminals
at Barstow, California and Las Vegas, Nevada. The CALNEV Pipeline also serves
the military at Edwards Air Force Base and Nellis Air Force Base, as well as
certain smaller delivery points, including the Burlington Northern Santa Fe and
Union Pacific railroad yards.

                                        7
<PAGE>

     North Region.  Our Pacific operations' North Region consists of three
pipeline segments: the North Line, the Bakersfield Line and the Oregon Line.

     The North Line consists of approximately 1,075 miles of pipeline in five
segments originating in Richmond and Concord, California. This line serves our
terminals located in Brisbane, Sacramento, Chico, Fresno and San Jose,
California, and Sparks, Nevada. The products delivered through the North Line
come from refineries in the San Francisco Bay Area. The North Line also receives
product transported from various pipeline and marine terminals that deliver
products from foreign and domestic ports.

     The Bakersfield Line is a 100-mile 8-inch pipeline serving Fresno,
California. A refinery located in Bakersfield, California supplies substantially
all of the products shipped through the Bakersfield Line.

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

     West Coast Terminals.  We acquired the West Coast Terminals on January 1,
2001, as part of our purchase of GATX Corporation's domestic pipeline and
terminal businesses. These terminals are now operated as part of our Pacific
operations.

     The terminals include:

     - the Carson terminal;

     - the Los Angeles terminal;

     - the Gaffey Street terminal;

     - the Richmond terminal;

     - the Linnton and Willbridge terminals; and

     - the Harbor Island terminal.

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

     The Carson Terminal and the connecting Los Angeles Harbor Terminal are
strategically located near the many refineries in the Los Angeles Basin. The
combined Carson/LA Harbor system is connected to numerous other pipelines and
facilities throughout the Los Angeles area, which gives the system significant
flexibility and allows customers to quickly respond to market conditions.
Storage at the Carson facility is primarily arranged via term contracts with
customers, ranging from one to five years. Term contracts represent 47% of total
revenues at the facility. Competitors of the Carson Terminal in the refined
products market include Equilon and Arco Terminal Services Company. In the
crude/black oil market, competitors include Edison Pipeline & Terminal Company,
Wilmington Liquid Bulk Terminals (Vopak) and Arco Terminal Services Company.

     The Gaffey Street Terminal in San Pedro, California, is adjacent to the
Port of Los Angeles. This facility serves as a marine fuel storage and blending
facility for the marketing of local or imported bunker fuels for Los Angeles
ship traffic. Competitors to Gaffey Street include ST Services, Chemoil and
Wilmington Liquid Bulk Terminals (Vopak).

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

                                        8
<PAGE>

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

     The Harbor Island Terminal is located in Seattle, Washington. The facility
is supplied via pipeline and barge from northern Washington-state refineries,
allowing customers to distribute fuels economically to the greater Seattle-area
market by truck. The terminal also has the largest capacity of marine fuel oil
tanks in Puget Sound, along with a multi-component, in-line blending system for
providing customized bunker fuels to the marine industry. Harbor Island competes
primarily with nearby terminals owned by Equilon and Tosco.

     Truck Loading Terminals.  Our Pacific operations include 15 truck-loading
terminals (13 on SFPP, L.P. and two on CALNEV) with an aggregate usable tankage
capacity of approximately nine million barrels. The truck terminals are located
at destination points on each of our Pacific operations' pipelines as well as at
certain intermediate points along each pipeline. The simultaneous truck loading
capacity of each terminal ranges from 2 to 12 trucks. We provide the following
services at these terminals:

     - short-term product storage;

     - truck loading;

     - vapor recovery;

     - deposit control additive injection;

     - dye injection;

     - oxygenate blending; and

     - quality control.

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

     Markets.  Currently our Pacific operations' pipeline system serves in
excess of 80 shippers in the refined products market, with the largest customers
consisting of:

     - major petroleum companies;

     - independent refineries;

     - the United States military; and

     - independent marketers and distributors of products.

     A substantial portion of the product volume transported is gasoline. Demand
for gasoline depends on such factors as prevailing economic conditions,
vehicular use patterns and demographic changes in the markets served. We expect
the majority of our Pacific operations' markets to maintain growth rates that
exceed the national average for the foreseeable future.

     Currently, the California gasoline market is 970,000 barrels per day. The
Arizona gasoline market is served primarily by us at a market demand of 145,000
barrels per day. Nevada's gasoline market is approximately 55,000 barrels per
day and Oregon's is approximately 100,000 barrels per day. The diesel and jet
fuel market is approximately 480,000 barrels per day in California, 80,000
barrels per day in Arizona, 50,000 barrels per day in Nevada and 60,000 barrels
per day in Oregon. We transport over one million barrels of petroleum products
per day in these states.

                                        9
<PAGE>

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

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

     Competition.  The most significant competitors of our Pacific operations'
pipeline system are proprietary pipelines owned and operated by major oil
companies in the area where our pipeline system delivers products as well as
refineries with related trucking arrangements within our market areas. We
believe that high capital costs, tariff regulation and environmental permitting
considerations make it unlikely that a competing pipeline system comparable in
size and scope will be built in the foreseeable future. However, the possibility
of pipelines being constructed to serve specific markets is a continuing
competitive factor. The use by major oil companies of trucks in certain markets
has resulted in minor but notable reductions in product volumes delivered to
certain shorter-haul destinations in the Los Angeles and San Francisco Bay
areas. We cannot predict with certainty whether the use of short-haul trucking
will continue or increase in the future.

     Longhorn Partners Pipeline is a joint venture pipeline project that is
expected to begin transporting refined products from refineries on the Gulf
Coast to El Paso and other destinations in Texas in the second quarter 2002.
Increased product supply in the El Paso area could result in some shift of
volumes transported into Arizona from our West Line to our East Line. While
increased movements into the Arizona market from El Paso would displace higher
tariff volumes supplied from Los Angeles on our West Line, such shift of supply
sourcing has not had, and is not expected to have, a material effect on
operating results.

  CENTRAL FLORIDA PIPELINE

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

     The Central Florida Pipeline system consists of a 110-mile, 16-inch
pipeline that transports gasoline and an 85-mile, 10-inch pipeline that
transports diesel fuel and jet fuel from Tampa to Orlando, with an intermediate
delivery point on the 10-inch pipeline at Intercession City, Florida. The
Central Florida Pipeline represents the only major refined products pipeline in
the state of Florida. In addition to being connected to our Tampa Terminal, the
pipeline system is connected to terminals owned and operated by TransMontaigne,
Citgo, BP, and Marathon Ashland Petroleum. The 10-inch pipeline is connected to
our Taft Terminal and is also the sole pipeline supplying jet fuel to the
Orlando International Airport in Orlando, Florida. In 2001, the pipeline
transported approximately 93,000 barrels per day of refined products, with the
product mix being approximately 66% gasoline, 13% diesel fuel, and 21% jet fuel.

     Markets.  The estimated total refined petroleum product demand in the State
of Florida is approximately 785,000 barrels per day. Gasoline is, by far, the
largest component of that demand at approximately 500,000 barrels per day. The
total demand for the Central Florida region of the state, which includes the
Tampa and Orlando markets, is estimated to be 325,000 barrels per day, or
approximately

                                        10
<PAGE>

42% of the consumption of refined products in the state. Our market share is
approximately 116,000 barrels per day, or approximately 36% of the Central
Florida market. Virtually all of the demand for jet fuel at Orlando
International Airport is moved through our Tampa Terminal and the Central
Florida Pipeline system. The market in Central Florida is seasonal, with demand
peaks in March and April during spring break and again in the summer vacation
season, and is also heavily influenced by tourism, with Disney World and other
amusement parks located in Orlando.

     Supply.  The vast majority of refined petroleum products consumed in
Florida are supplied from major refining centers in the gulf coast of Louisiana
and Mississippi and refineries in the Caribbean basin. A small amount of refined
products are being supplied by refineries in Alabama and by Texas Gulf Coast
refineries via marine vessels and through pipeline networks that extend to
Bainbridge, Georgia. The supply into Florida is generally transported by
ocean-going vessels to the larger metropolitan ports, such as Tampa, Port
Everglades near Miami, and Jacksonville. Individual markets are then supplied
from terminals at these ports and other smaller ports, predominately by trucks,
except the Central Florida region, which is served by a combination of trucks
and pipelines.

     Competition.  With respect to the terminal operations at Tampa, the most
significant competitors are proprietary terminals owned and operated by major
oil companies, such as Marathon Ashland Petroleum, BP and Citgo, located along
the Port of Tampa, and the Chevron and Motiva terminals in Port Tampa. These
terminals generally support the storage requirements of their parent or
affiliated companies' refining and marketing operations and provide a mechanism
for an oil company to enter into exchange contracts with third parties to serve
its storage needs in markets where the oil company may not have terminal assets.
Due to the high capital costs of tank construction in Tampa and state
environmental regulation of terminal operations, we believe it is unlikely that
new competing terminals will be constructed in the foreseeable future.

     With respect to the Central Florida Pipeline system, the most significant
competitors are trucking firms and marine transportation firms. Trucking
transportation is more competitive in serving markets west of Orlando that are a
relatively short haul from Tampa, and with respect to markets east of Orlando,
our competition is trucks and product movements from marine terminals on the
east coast of Florida. We are utilizing tariff incentives to attract volumes to
the pipeline that might otherwise enter the Orlando market area by truck from
Tampa or by marine vessel into Cape Canaveral.

     Federal regulation of marine vessels, including the requirement, under the
Jones Act, that United States flagged vessels contain double-hulls, is a
significant factor in reducing the fleet of vessels available to transport
refined petroleum products. The requirement is being phased-in based on the age
of the vessel and some older vessels are being redeployed into use in other
jurisdictions rather than being retrofitted with a double-hull for use in the
United States. Although we believe it is unlikely that a new pipeline system
comparable in size and scope will be constructed, due to the high cost of
pipeline construction and environmental and right-of-way permitting in Florida,
the possibility of such pipelines being built is a continuing competitive
factor.

  NORTH SYSTEM

     Our North System is an approximately 1,600-mile interstate common carrier
pipeline for natural gas liquids and refined petroleum products.

                                        11
<PAGE>
     Natural gas liquids are typically extracted from natural gas in liquid form
under low temperature and high pressure conditions. Natural gas liquid products
and related uses are as follows:

<Table>
<Caption>
PRODUCT                                          USE
-------                                          ---
<S>                  <C>
Propane...........   Residential heating, industrial and agricultural uses,
                     petrochemical feedstock
Isobutane.........   Further processing
Natural gasoline..   Further processing or blending into gasoline motor fuel
Ethane............   Feedstock for petrochemical plants
Normal butane.....   Feedstock for petrochemical plants or blending into gasoline
                     motor fuel
</Table>

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

     - two parallel pipelines (except for a single 50-mile segment in Nebraska
       and Iowa), that originate at Bushton, Kansas and continue to a major
       storage and terminal area in Des Moines, Iowa;

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

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

     Through interconnections with other major liquids pipelines, our North
System's pipeline system connects mid-continent producing areas to markets in
the Midwest and eastern United States. We also have defined sole carrier rights
to use capacity on an extensive pipeline system owned by The Williams Companies
that interconnects with our North System. This capacity lease agreement requires
us to pay $2.0 million per year, is in place until February 2013 and contains a
five-year renewal option. In addition to our capacity lease agreement with
Williams, we also have a reversal agreement with Williams to help provide for
the transport of summer-time surplus butanes from Chicago area refineries to
storage facilities at Bushton. We have an annual minimum joint tariff commitment
of $0.6 million to Williams for this agreement.

     Our North System has approximately 8.3 million barrels of storage capacity,
which includes caverns, steel tanks, pipeline line-fill and leased storage
capacity. This storage capacity provides operating efficiencies and flexibility
in meeting seasonal demand of shippers as well as propane storage for our truck
loading terminals.

     Truck Loading Terminals.  Our North System has seven propane truck loading
terminals and one multi-product complex at Morris, Illinois, in the Chicago
area. Propane, normal butane and natural gasoline can be loaded at our Morris
terminal.

     Markets.  Our North System currently serves approximately 50 shippers in
the upper Midwest market, including both users and wholesale marketers of
natural gas liquids. These shippers include all three major refineries in the
Chicago area. Wholesale marketers of natural gas liquids primarily make direct
large volume sales to major end-users, such as propane marketers, refineries,
petrochemical plants and industrial concerns. Market demand for natural gas
liquids varies in respect to the different end uses to which natural gas liquid
products may be applied. Demand for transportation services is influenced not
only by demand for natural gas liquids but also by the available supply of
natural gas liquids.

     Supply.  Natural gas liquids extracted or fractionated at the Bushton gas
processing plant have historically accounted for a significant portion
(approximately 40-50%) of the natural gas liquids transported through our North
System. Other sources of natural gas liquids transported in our North System
include large oil companies, marketers, end-users and natural gas processors
that use interconnecting pipelines to transport hydrocarbons. In 2000, KMI sold
to ONEOK, Inc. the Bushton plant along with other assets previously owned by
KMI.

                                        12
<PAGE>

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

  PLANTATION PIPE LINE COMPANY

     We own approximately 51% of Plantation Pipe Line Company, which owns a
3,100-mile pipeline system throughout the southeastern United States. On
December 21, 2000, we assumed day-to-day operations of Plantation pursuant to
agreements with Plantation Services LLC and Plantation Pipe Line Company.
Plantation serves as a common carrier of refined petroleum products to various
metropolitan areas, including Birmingham, Alabama; Atlanta, Georgia; Charlotte,
North Carolina; and the Washington, D.C. area. We believe favorable demographics
in the southeastern United States will serve as a platform for increased
utilization and expansion of Plantation's pipeline system. For the year 2001,
Plantation delivered 618,364 barrels per day, only slightly less than the
record-setting 619,659 barrel per day average achieved in 2000. These delivered
volumes are comprised of gasoline (66%), diesel/heating oil (20%), and jet fuel
(14%).

     Markets.  Plantation ships products for approximately 40 companies to
terminals throughout the southeastern United States. Plantation's principal
customers are Gulf Coast refining and marketing companies, fuel wholesalers, and
the United States Department of Defense. Plantation's top 6 shippers represent
approximately 80% of total system volumes.

     The seven states in which Plantation operates represent a collective
pipeline demand of approximately 2.0 million barrels per day of refined
products. Plantation currently has direct access to about 1.5 million barrels
per day of this overall market. The remaining 0.5 million barrels per day of
demand lies in markets (e.g. Nashville, Tennessee; North Augusta, South
Carolina; Bainbridge, Georgia; and Selma, North Carolina) currently served by
Colonial Pipeline Company. These markets represent potential growth
opportunities for the Plantation system.

     In addition, Plantation delivers jet fuel to the Atlanta, Georgia;
Charlotte, North Carolina; and Washington, D.C. airports (Ronald Reagan National
and Dulles). During 2001, Plantation experienced a significant reduction in jet
fuel shipments subsequent to the terrorist attacks on September 11, 2001. Jet
fuel volumes began to improve by year-end but remain below historical levels. We
anticipate that jet fuel demand at these major airports will return to normal
levels before year-end 2002, except for Ronald Reagan National, where we expect
that flights will total only approximately 77% of pre-September 11, 2001 flights
during 2002.

     Supply.  Products shipped on Plantation originate at various Gulf Coast
refineries from which major integrated oil companies and independent refineries
and wholesalers ship refined petroleum products. Plantation is directly
connected to and supplied by a total of 9 major refineries representing over 2
million barrels per day of refining capacity. Plantation completed the second
phase of a $40 million pipeline expansion in April 2001. This project added
approximately 70,000 barrels per day of capacity to the Plantation system from
its origin in Baton Rouge, Louisiana, to the end of its mainline in Greensboro,
North Carolina. As a result of this expansion, Plantation's overall system
capacity has increased to approximately 710,000 barrels per day. Additionally,
Plantation is spending approximately $1.5 million to increase the capacity of
its main gasoline pipeline between Collins, Mississippi, and Bremen, Georgia by
approximately 40,000 barrels per day. This additional capacity will be available
to handle growth in volumes between Collins and Bremen as well as support
possible future expansion of Plantation's lateral pipelines serving Knoxville,
Tennessee; Macon, Georgia; and Columbus, Georgia.

                                        13
<PAGE>

     Competition.  Plantation competes primarily with the Colonial Pipeline
Company, which also runs from Gulf Coast refineries throughout the southeastern
United States, extending into the northeastern states.

  COCHIN PIPELINE SYSTEM

     We own 44.8% of the Cochin Pipeline System, a 1,938-mile, 12-inch
multi-product pipeline operating between Fort Saskatchewan, Alberta and Sarnia,
Ontario.

     The Cochin Pipeline System and related storage and processing facilities
consist of two components:

     - in Canada, all facilities are operated under the name of Cochin Pipe
       Lines, Ltd.; and

     - in the United States, all facilities are operated under the name of Dome
       Pipeline Corporation.

     Markets.  Formed in the late 1970's as a joint venture, the pipeline
traverses three provinces in Canada and seven states in the United States
transporting high vapor pressure ethane, ethylene, propane, butane and natural
gas liquids to the Midwestern United States and eastern Canadian petrochemical
and fuel markets. The system operates as a National Energy Board (Canada) and
Federal Energy Regulatory Commission (United States) regulated common carrier;
shipping products on behalf of its owners as well as other third parties.

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

     Associated underground storage is available at Fort Saskatchewan, Alberta
and Windsor, Ontario. The system is connected to the Williams pipeline system in
Minnesota and in Iowa, and connects with our North System at Clinton, Iowa. The
Cochin Pipeline System has the ability to access the Canadian Eastern Delivery
System via the Windsor Storage Facility Joint Venture at Windsor, Ontario.
Injection into the system can occur from:

     - BP Amoco, Chevron or Dow fractionation facilities at Fort Saskatchewan,
       Alberta;

     - TransCanada Midstream storage at five points within the provinces of
       Canada; or

     - the Williams Mapco West Junction, in Minnesota.

     Competition.  The pipeline competes with Enbridge Energy Partners for
natural gas longhaul business from Fort Saskatchewan, Alberta and Windsor,
Ontario. The pipeline's primary competition in the Chicago natural gas liquids
market comes from the combination of the Alliance pipeline system, which brings
unprocessed gas into the United States from Canada, and from Aux Sable, which
processes and markets the natural gas liquids in the Chicago market.

  CYPRESS PIPELINE

     Our Cypress Pipeline is an interstate common carrier pipeline system
originating at storage facilities in Mont Belvieu, Texas and extending 104 miles
east to the Lake Charles, Louisiana area. Mont Belvieu, located approximately 20
miles east of Houston, is the largest hub for natural gas liquids gathering,
transportation, fractionation and storage in the United States.

     Markets.  The pipeline was built to service Westlake Petrochemicals
Corporation in the Lake Charles, Louisiana area under a 20-year ship-or-pay
agreement that expires in 2011. The contract requires a minimum volume of 30,000
barrels per day and in 1997, the producer agreed to ship at least an additional
13,700 barrels per day through late 2002. Also in 1997, we expanded the Cypress
Pipeline's capacity by 25,000 barrels per day to 57,000 barrels per day. Our
management continues to pursue projects to increase throughput on our Cypress
Pipeline.

     Supply.  Our Cypress Pipeline originates in Mont Belvieu where it is able
to receive ethane and ethane/propane mix from local storage facilities. Mont
Belvieu has facilities to fractionate natural gas
                                        14
<PAGE>

liquids received from several pipelines into ethane and other components.
Additionally, pipeline systems that transport specification natural gas liquids
from major producing areas in Texas, New Mexico, Louisiana, Oklahoma and the
Mid-Continent Region supply ethane and ethane/propane mix to Mont Belvieu.

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

  TRANSMIX OPERATIONS

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

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

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

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

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

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

     Our Colton processing facility, completed in the spring of 1998, and
located adjacent to our products terminal in Colton, California, produces
refined petroleum products that are delivered into our Pacific operations'
pipelines for shipment to markets in Southern California and Arizona. The
facility can process over 5,000 barrels per day and is supported by a "for fee"
basis contract with Duke Energy Merchants.

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

     Supply.  Transmix generated by Colonial, Plantation, Sun, Teppco, Explorer,
and our Pacific operations provide the vast majority of our supply. These
suppliers are committed to our transmix facilities by long-term contracts.
Individual shippers and terminal operators provide additional supply. Duke
Energy Merchants is responsible for transmix supply acquisition.

                                        15
<PAGE>

     Competition.  Our transmix operations compete mainly with Placid Refining
in the Gulf coast area. Tosco Refining is a major competitor in the New York
harbor area. There are various processors in the Mid-Continent area, mainly
Phillips and Williams Energy Services, who compete with our expansion efforts in
that market. Equilon and a number of smaller organizations operate transmix
processing facilities in the West and Southwest. These operations compete for
supply, which we envision as the basis for growth in the West and Southwest. Our
Colton processing facility also competes with major oil company refineries in
California.

  HEARTLAND PIPELINE COMPANY

     We and Conoco each own 50% of Heartland Pipeline Company. We operate the
pipeline, and Conoco operates Heartland's Des Moines, Iowa terminal and serves
as the managing partner of Heartland. In 2000, Heartland leased to Conoco 100%
of the Heartland terminal capacity at Des Moines, Iowa for $1.0 million per year
on a year-to-year basis. The Heartland lease fee, payable to us for reserved
pipeline capacity, is paid monthly, with an annual adjustment.

     Markets.  Heartland provides transportation of refined petroleum products
from refineries in the Kansas and Oklahoma area to a BP Amoco terminal in
Council Bluffs, Iowa, a Conoco terminal in Lincoln, Nebraska and Heartland's Des
Moines terminal. The demand for, and supply of, refined petroleum products in
the geographic regions served directly affect the volume of refined petroleum
products transported by Heartland.

     Supply.  Refined petroleum products transported by Heartland on our North
System are supplied primarily from the National Cooperative Refinery Association
crude oil refinery in McPherson, Kansas and the Conoco crude oil refinery in
Ponca City, Oklahoma.

     Competition.  Heartland competes with other refined petroleum product
carriers in the geographic market served. Heartland's principal competitor is
The Williams Pipeline Company.

NATURAL GAS PIPELINES

     Our Natural Gas Pipelines consist of natural gas gathering, transportation
and storage for both interstate and intrastate pipelines. Within this segment,
we own over 10,000 miles of natural gas pipelines and associated storage and
supply lines that are strategically located at the center of the North American
pipeline grid. Our transportation network provides access to the major gas
supply areas in the western United States, Texas and the Midwest, as well as
major consumer markets.

  KINDER MORGAN INTERSTATE GAS TRANSMISSION LLC

     Through Kinder Morgan Interstate Gas Transmission LLC, called "KMIGT" in
this document, we own approximately 6,100 miles of transmission lines in
Wyoming, Colorado, Kansas, Missouri and Nebraska. KMIGT provides transportation
and storage services to KMI affiliates, third-party natural gas distribution
utilities and other shippers. Pursuant to transportation agreements and FERC
tariff provisions, KMIGT offers its customers firm and interruptible
transportation and storage services, including no-notice transportation and park
and loan services. Under KMIGT's tariffs, firm transportation and storage
customers pay reservation fees each month plus a commodity charge based on the
actual transported or stored volumes. In contrast, interruptible transportation
and storage customers pay a commodity charge based upon actual transported
and/or stored volumes. Reservation fees are based upon geographical location
(KMIGT does not have seasonal rates) and the distance of the transportation
service provided. Under the no-notice service, customers pay a fee for the right
to use a combination of firm storage and firm transportation to effect
deliveries of natural gas up to a specified volume without making specific
nominations.

     The system is powered by 26 transmission and storage compressor stations
with approximately 147,000 horsepower. The pipeline system provides storage
services to its customers from its Huntsman Storage Field in Cheyenne County,
Nebraska. The facility has approximately 39.4 billion cubic feet of total
storage

                                        16
<PAGE>

capacity, 7.9 billion cubic feet of working gas capacity and can withdraw up to
101 million cubic feet of natural gas per day.

     Markets.  Markets served by KMIGT consist of a stable customer base with
expansion opportunities due to the system's access to growing Rocky Mountain
supply sources. Markets served by KMIGT are comprised mainly of local natural
gas distribution companies and interconnecting interstate pipelines in the
mid-continent area. End-users for the local natural gas distribution companies
typically include residential, commercial, industrial and agricultural
customers. Those pipelines interconnecting with KMIGT in turn deliver gas into
multiple markets including some of the largest population centers in the
Midwest. Natural gas demand for crop irrigation during the summer from
time-to-time exceeds heating season demand and provides KMIGT consistent volumes
throughout the year without a significant impact from seasonality.

     Supply.  Approximately 8%, by volume, of KMIGT's firm contracts expire
within one year and 12% expire within one to five years. Affiliated entities are
responsible for approximately 24% of the total firm transportation and storage
capacity under contract on KMIGT's system. Over 90% of the system's firm
transport capacity is currently subscribed. In February 2000, KMIGT preserved
its transportation rates for 5 years as part of the settlement with its
customers and the Federal Energy Regulatory Commission on its filed rate case.

     Competition.  KMIGT competes with other interstate and intrastate gas
pipelines transporting gas from the supply sources in the Rocky Mountain and
Hugoton Basins to mid-continent pipelines and market centers.

  KINDER MORGAN TEXAS PIPELINE

     Our Kinder Morgan Texas Pipeline, called "KMTP" in this document, system is
principally located in the Texas Gulf Coast area. The system includes
approximately 2,500 miles of pipelines, supply and gathering lines, laterals and
related facilities. KMTP transports natural gas from producing fields in South
Texas, the Gulf Coast and the Gulf of Mexico to markets in southeastern Texas.
In addition, KMTP has interconnections with Natural Gas Pipeline Company of
America, a subsidiary of KMI, and 22 other intrastate and interstate pipelines.

     Markets.  KMTP acts as a seller of natural gas as well as a transporter.
Principal customers of KMTP include the electric and natural gas utilities that
serve the Houston area, and industrial customers located along the Houston Ship
Channel and in the Beaumont/Port Arthur, Texas area.

     This market is one of the largest and most competitive natural gas markets
in the United States. Large industrial end users of natural gas have multiple
pipelines connected to their plants. Large local distribution companies and
electric utilities also have multiple pipeline connections. Consumers of natural
gas have the opportunity to purchase natural gas directly from a number of
pipelines and/or from third parties that may hold capacity on the various
pipelines. For this market, the greatest demand for natural gas deliveries for
heating load occurs in the winter months, while electric generation peak demand
occurs in the summer months. In 2001, KMTP delivered an average of 1.7 billion
cubic feet per day of natural gas to this area, of which 59% of the deliveries
were for sales contracts and 41% were for transportation contracts.

     KMTP has renewed contracts with existing customers and signed a number of
new, long-term contracts to serve gas-fired power generators. For example, KMTP
and Exelon Generation Company, LLC, on behalf of ExTex LaPorte Limited
Partnership, entered into a five-year natural gas supply agreement. KMTP has
also signed a five-year agreement to supply approximately 90 billion cubic feet
of natural gas to chemical facilities owned by Occidental Corporation affiliates
in the Houston area. Also, on July 1, 2001, KMTP's 10-year firm natural gas
transportation and storage agreement with Calpine for 816 billion cubic feet of
transportation natural gas became effective. Other industrial end users'
contracts vary in length from month-to-month to five or more years.

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     KMTP has also developed a salt dome storage facility located near Markham,
Texas with a subsidiary of NiSource Industries, Inc. The facility has two salt
dome caverns and approximately 8.3 billion cubic feet of total storage capacity,
over 5.7 billion cubic feet of working gas capacity and up to 500 million cubic
feet per day of peak deliverability. The storage facility is leased by a
partnership in which KMTP and a subsidiary of NiSource are partners. KMTP has
executed a 20-year sublease with the partnership under which it has rights to
50% of the facility's working gas capacity, 85% of its withdrawal capacity and
approximately 70% of its injection capacity. KMTP also leases a salt dome cavern
from Dow Hydrocarbon & Resources, Inc. in Brazoria County, Texas, referred to as
the Stratton Ridge Facility. The Stratton Ridge Facility has a total capacity of
6.5 billion cubic feet, working gas capacity of 3.6 billion cubic feet and a
peak day deliverability of up to 150 million cubic feet per day.

     Competition.  KMTP competes with marketing companies, interstate and
intrastate pipelines for sales and transport customers in the Houston, Beaumont
and Port Arthur areas, and for acquiring gas supply in South Texas, the Gulf
Coast of Texas and the Gulf of Mexico.

  TRAILBLAZER PIPELINE COMPANY

     We own 66 2/3% of Trailblazer Pipeline Company, called "Trailblazer" in
this document. Enron Trailblazer Pipeline Company, a subsidiary of Enron Corp.
that owns the remaining 33 1/3%, has agreed, subject to customary closing
conditions and approval of the Enron bankruptcy court, to sell us its interest.
Through capital contributions it will make to the current expansion project on
the Trailblazer pipeline, CIG Trailblazer Gas Company, an affiliate of El Paso
Corporation, is expected to become a 7% to 8% equity owner in Trailblazer
Pipeline Company in mid-2002. A committee consisting of management
representatives for each of the partners manages Trailblazer. Natural Gas
Pipeline Company of America, a subsidiary of KMI, manages, maintains and
operates Trailblazer and provides the personnel to operate Trailblazer for which
Natural Gas Pipeline Company of America is reimbursed at cost. Trailblazer's
principal business is to transport and redeliver natural gas to others in
interstate commerce, and it does business in the states of Wyoming, Colorado,
Nebraska and Illinois. Trailblazer's pipeline system originates at an
interconnection with Wyoming Interstate Company Ltd.'s pipeline system near
Rockport, Colorado and runs through southeastern Wyoming to a terminus near
Beatrice, Nebraska where Trailblazer's pipeline system interconnects with
Natural Gas Pipeline Company of America's and Northern Natural Gas Company's
pipeline systems.

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

     Markets.  Significant growth in Rocky Mountain natural gas supplies has
prompted a need for additional pipeline transportation service. In August 2000,
Trailblazer announced an approximate $58.7 million expansion to its system,
which will provide an additional capacity of approximately 324,000 dekatherms of
natural gas per day. The expansion project will start in Rockport, Colorado,
where Trailblazer's pipeline interconnects with pipelines owned by Colorado
Interstate Gas Co., Wyoming Interstate Company, West Gas and KMIGT, and
terminate in Gage County, Nebraska. With this project, Trailblazer will install
two new compressor stations and add additional horsepower at an existing
compressor station. Trailblazer's expansion plan was approved by the FERC in the
second quarter of 2001 and is scheduled for completion in the second quarter of
2002.

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     Transportation Contracts (Post Expansion).  Approximately 17%, by volume,
of Trailblazer's firm contracts expire within one year and 10% expire within one
to five years. Affiliated entities will hold less than 1% of the total firm
transportation capacity after the expansion is completed. 100% of the system's
firm transport capacity is currently subscribed. Trailblazer's last rate
settlement requires it to file revised rates in 2002 that will be effective
January 1, 2003.

     Competition.  While competing pipelines have been announced which would
move gas east out of the Rocky Mountains, the main competition that Trailblazer
faces is that the gas supply in the Rocky Mountain area either stays in the area
or is moved west and therefore is not transported on Trailblazer's pipeline.

  CASPER AND DOUGLAS NATURAL GAS GATHERING AND PROCESSING SYSTEMS

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

     The Douglas gathering system is comprised of approximately 1,500 miles of
4-inch to 16-inch diameter pipe that gathers approximately 50 million cubic feet
per day of natural gas from 650 active receipt points. Douglas Gathering has an
aggregate 24,495 horsepower of compression situated at 17 field compressor
stations. Gathered volumes are processed at our Douglas plant, located in
Douglas, Wyoming. Residue gas is delivered into KMIGT and recovered liquids are
injected in Phillips Petroleum's natural gas liquids pipeline for transport to
Borger, Texas.

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

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

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

  RED CEDAR GATHERING COMPANY

     We own a 49% equity interest in the Red Cedar Gathering Company, a joint
venture organized in August 1994, referred to in this document as "Red Cedar."
The Southern Ute Indian Tribe owns the remaining 51%. Red Cedar owns and
operates natural gas gathering, compression and treating facilities in the
Ignacio Blanco Field in La Plata County, Colorado. The Ignacio Blanco Field lies
within the Colorado portion of the San Juan Basin, most of which is located
within the exterior boundaries of the Southern Ute Indian Tribe Reservation. Red
Cedar gathers coal seam and conventional natural gas at wellheads and at several
central delivery points, for treating, compression and delivery into any one of
four major interstate natural gas pipeline systems and an intrastate pipeline.

     Red Cedar's gas gathering system currently consists of over 800 miles of
gathering pipeline connecting more than 700 producing wells, 65,000 horsepower
of compression at 17 field compressor stations and two carbon dioxide treating
plants. A majority of the natural gas on the system moves through 8-inch to
20-inch diameter pipe. The capacity and throughput of the Red Cedar system as
currently configured is approximately 700 million cubic feet per day of natural
gas.

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  COYOTE GAS TREATING, LLC

     We own a 50% equity interest in Coyote Gas Treating, LLC, a joint venture
organized in December 1996. El Paso Field Services Company owns the remaining
50% interest. The singular asset owned by the joint venture is a 250 million
cubic feet per day natural gas treating facility located in La Plata County,
Colorado known as Coyote Gulch. We are the operator of the plant facility and
the managing partner of Coyote Gas Treating, LLC.

     The inlet gas stream treated by Coyote Gulch contains an average carbon
dioxide content of between 12% and 13%. The plant treats the gas down to a
carbon dioxide concentration of 2% in order to meet interstate natural gas
pipeline quality specifications, and then compresses the natural gas into the
TransColorado Gas Transmission pipeline for transport to the Blanco, New Mexico
San Juan Basin Hub.

  THUNDER CREEK GAS SERVICES, LLC

     We own a 25% equity interest in Thunder Creek Gas Services, LLC, referred
to in this document as "Thunder Creek." Devon Energy owns the other 75% equity
interest. Thunder Creek provides gathering, compression and treating services to
a number of coal seam gas producers in the Powder River Basin. Throughput
volumes include both coal seam and conventional plant residue gas. Thunder Creek
is independently operated from offices located in Denver, Colorado with field
offices in Glenrock and Gillette, Wyoming.

     Thunder Creek's operations are a combination of mainline and low pressure
gathering assets. The mainline assets include 215 miles of 4-inch thru 24-inch
diameter pipeline, 13,350 horsepower of mainline compression and carbon dioxide
removal facilities consisting of a 240 million cubic feet per day carbon dioxide
treating plant complete with dehydration and 3,330 horsepower of compression.
The mainline assets receive gas from 26 receipt points and can deliver treated
gas to three delivery points including Colorado Interstate Gas, Wyoming
Interstate Gas Company and KMIGT. The low pressure gathering assets include 92
miles of 6-inch thru 14-inch gathering pipeline and 46,000 horsepower of field
compression. Gas is gathered from 43 receipt points and delivered to the
mainline at four primary locations.

CO(2) PIPELINES

     On March 5, 1998, we and affiliates of Shell Exploration & Production
Company combined our carbon dioxide activities and assets into a partnership
(Shell CO(2) Company, Ltd.). Shell CO(2) Company, Ltd. was established to
transport, market and produce carbon dioxide for use in enhanced oil recovery
operations in the continental United States. We acquired a 20% interest in Shell
CO(2) Company, Ltd. in exchange for contributing our Central Basin Pipeline and
approximately $25 million in cash. Shell contributed the following assets in
exchange for the remaining 80% ownership interest:

     - an approximate 45% interest in the McElmo Dome carbon dioxide reserves;

     - an 11% interest in the Bravo Dome carbon dioxide reserves;

     - an indirect 50% interest in the Cortez Pipeline;

     - a 13% interest in the Bravo Pipeline; and

     - certain other related assets.

     Our CO(2) pipelines and related assets allow us to market a complete
package of carbon dioxide supply, transportation and technical expertise to the
customer. Carbon dioxide is used in enhanced oil recovery projects as a flooding
medium for recovering crude oil from mature oil fields.

     On April 1, 2000, we acquired the remaining 80% interest in Shell CO(2)
Company, Ltd. from Shell for $212.1 million. After the closing, we renamed Shell
CO(2) Company, Ltd., Kinder Morgan CO(2) Company, L.P., referred to in this
document as "KMCO(2)." We own a 98.9899% limited partner interest in KMCO(2),
and our general partner owns a direct 1.0101% general partner interest.

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     On June 1, 2000, we acquired carbon dioxide asset interests from Devon
Energy Production Company L.P. for approximately $55 million. All of the
properties acquired were located in the Permian Basin of west Texas and the
principal assets were an 81% interest in the Canyon Reef Carriers carbon dioxide
pipeline and a working interest in the SACROC unit (oil field). Additionally, we
acquired minority interests in the Sharon Ridge unit, operated by Exxon Mobil,
the Reinecke unit, operated by Spirit 76, and gas processing plants used to
recover injected carbon dioxide.

     On January 1, 2001, KMCO(2) formed a joint venture, named MKM Partners,
L.P., with Marathon Oil Company in the southern Permian Basin of west Texas. The
joint venture consists of a nearly 13% interest in the SACROC unit and a 49.9%
interest in the Yates Field unit. It is owned 85% by Marathon Oil Company and
15% by KMCO(2).

     McElmo and Bravo Domes.  We operate, and own approximately 45% of, the
McElmo Dome, which contains more than 11 trillion cubic feet of nearly pure
carbon dioxide. Compression capacity exceeds one billion cubic feet per day.
While current wellbore capacity is about 900 million cubic feet per day,
additional wells are planned to increase deliverability to approximately 1
billion cubic feet per day. McElmo Dome produces from the Leadville formation at
8,000 feet with 43 wells that produce at individual rates of up to 50 million
cubic feet per day.

     Bravo Dome, of which we own approximately 11%, holds reserves of
approximately two trillion cubic feet of carbon dioxide. Bravo Dome produces
approximately 320 million cubic feet per day, with production coming from more
than 350 wells in the Tubb Sandstone at 2,300 feet.

     Pipelines.  We operate and own a 50% interest in the 502-mile, 30-inch
Cortez Pipeline. This pipeline carries carbon dioxide from the McElmo Dome
source reservoir to the Denver City, Texas hub. The Cortez Pipeline currently
transports in excess of 700 million cubic feet per day, including approximately
90% of the carbon dioxide transported on our Central Basin Pipeline.

     Placed in service in 1985, our Central Basin Pipeline consists of
approximately 143 miles of 16-inch to 20-inch main pipeline and 157 miles of
4-inch to 12-inch lateral supply lines located in the Permian Basin between
Denver City, Texas and McCamey, Texas with a throughput capacity of 650 million
cubic feet per day. At its origination point in Denver City, our Central Basin
Pipeline interconnects with all three major carbon dioxide supply pipelines from
Colorado and New Mexico, namely the Cortez Pipeline (operated by KMCO(2)) and
the Bravo and Sheep Mountain Pipelines (operated by BP Amoco). Central Basin
Pipeline's mainline terminates near McCamey where it interconnects with the
Canyon Reef Carriers Pipeline.

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

     In addition, we own 81% of the Canyon Reef Carriers Pipeline. The Canyon
Reef Carriers Pipeline, constructed in 1972, is the oldest carbon dioxide
pipeline in West Texas. The Canyon Reef Carriers Pipeline extends 140 miles from
McCamey, Texas, to our SACROC field. This pipeline is 16 inches in diameter and
has a capacity of approximately 290 million cubic feet per day and makes
deliveries to the SACROC, Sharon Ridge, Cogdell and Reinecke units.

     SACROC Unit.  The SACROC unit, in which we have increased our interest to
over 80%, is comprised of approximately 50,000 acres located in the Permian
Basin in Scurry County, Texas. SACROC was discovered in 1948 and has produced
over 1.2 billion barrels of oil since inception. We have continued the
development of the carbon dioxide project initiated by the previous owners and
have arrested the decline in production through increased carbon dioxide
injection. The current carbon dioxide injection rate is 120 million cubic feet
per day, up from 65 million cubic feet per day in 2000, and the oil production
rate is approximately 10,000 barrels of oil per day from 250 producing wells, up
from 8,500 barrels of oil per day in 2000.

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<PAGE>

     Snyder Gasoline Plant.  We own over 20% of, and now operate, the Snyder
Gasoline Plant, 43% of the Diamond M Plant and 100% of the North Snyder Plant.
These plants process gas produced from the SACROC unit and neighboring carbon
dioxide projects, specifically the Sharon Ridge, Cogdell and Reinecke units.

     Markets.  Our principal market for carbon dioxide is for injection into
mature oil fields in the Permian Basin, where industry demand is expected to be
comparable to historical demand for the next several years. During 2001, we
initiated deliveries to two new projects, the Cogdell field, operated by
Occidental Petroleum and the HT Boyd field, operated by Anadarko Petroleum. We
are exploring additional potential markets including southwest and central
Kansas, California and the coal bed methane production in the San Juan Basin of
New Mexico.

     Competition.  Our primary competitors for the sale of carbon dioxide
include suppliers that have an ownership interest in McElmo Dome, Bravo Dome and
Sheep Mountain Dome carbon dioxide reserves. Our ownership interests in the
Cortez and Bravo pipelines are in direct competition with other carbon dioxide
pipelines. We also compete with other interests in McElmo Dome and Cortez
Pipeline, for transportation of carbon dioxide to the Denver City, Texas market
area. There is no assurance that new carbon dioxide source fields will not be
discovered which could compete with us or that new methodologies for enhanced
oil recovery could replace carbon dioxide flooding.

TERMINALS

  LIQUIDS TERMINALS

     Kinder Morgan Liquids Terminals LLC, referred to in this document as
"KMLT," is comprised of 11 bulk liquid terminal facilities with total capacity
of approximately 35 million barrels. In 2001, the terminals handled 491 million
barrels of clean petroleum, petrochemical and vegetable oil products for 210
different customers. The facilities are located in Houston, New York Harbor, New
Orleans, Chicago, Cincinnati and Pittsburgh.

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

     New York Harbor.  KMLT owns two facilities in the New York Harbor area, one
in Carteret, N.J. and the other in Perth Amboy, N.J. The Carteret facility has a
capacity of approximately 6.4 million barrels of petroleum and petrochemical
products. This facility has two ship docks with a 37-foot mean low water depth
and four barge docks. It is connected to the Colonial, Buckeye, Sun and Harbor
pipeline systems and CSX and Norfolk Southern railroads. The Perth Amboy
facility has a capacity of approximately 2.3 million barrels of petroleum and
petrochemical products. Tank sizes range from 2,000 gallons to 300,000 barrels.
The facility has one ship dock and one barge dock. This facility is connected to
the Colonial and Buckeye pipeline systems and CSX and Norfolk Southern
railroads.

     New Orleans.  The KMLT terminal in the Port of New Orleans is located in
Harvey, Louisiana. The facility has approximately 2.9 million barrels of total
tanks ranging in sizes from 416 barrels to 200,000 barrels. There are three ship
docks, one barge dock and the Union Pacific railroad provides rail service. The
terminal also provides ancillary drumming, packaging and cold storage services.

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

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approximately 741,000 barrels of capacity in tanks ranging from 12,000 gallons
to 55,000 barrels. There are two ship docks and four barge docks and the
facility is served by the Norfolk Southern railroad.

     Cincinnati.  KMLT has two facilities along the Ohio River in Cincinnati,
Ohio. The total storage is approximately 850,000 barrels in tankage ranging from
120 barrels to 96,000 barrels. There are 3 barge docks and the NNU and CSX
railroads provide rail service.

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

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

  BULK TERMINALS

     Our Bulk Terminals consist of 33 bulk terminals, which handle approximately
55 million tons of bulk products annually. These terminals have 2 million tons
of covered storage and 14 million tons of open storage.

  Coal Terminals

     We handled over 28 million tons of coal in 2001, which is 51% of our total
volume at our bulk terminals.

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

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

     Our Pier IX Terminal is located in Newport News, Virginia. The terminal
originally opened in 1983 and has the capacity to transload approximately 12
million tons of coal annually. It can store 1.3 million tons of coal on its
30-acre storage site. In addition, the Pier IX Terminal operates a cement
facility, which has the capacity to transload over 400,000 tons of cement
annually.

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

     Markets.  Coal continues to dominate as the fuel for electric generation,
accounting for more than 55% of United States electric generation feedstock.
Forecasts of overall coal usage and power plant usage for the next 20 years show
an increase of about 1.5% per year. Current domestic supplies are predicted to
last for several hundred years. Most coal transloaded through our coal terminals
is destined for use in coal-fired electric generation.

     We believe that obligations to comply with the Clean Air Act Amendments of
1990 will cause shippers to increase the use of cleaner burning low sulfur coal
from the western United States and from

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foreign sources. Approximately 80% of the coal loaded through our Cora Terminal
and our Grand Rivers Terminal is low sulfur coal originating from mines located
in the western United States, including the Hanna and Powder River basins in
Wyoming, western Colorado and Utah. In 2000, four major customers accounted for
approximately 90% of all the coal loaded through our Cora Terminal and our Grand
Rivers Terminal.

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

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

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

     Competition.  Our Cora Terminal and our Grand Rivers Terminal compete with
several coal terminals located in the general geographic area. We believe our
Cora Terminal and our Grand Rivers Terminal can compete successfully with other
terminals because of their favorable location, independent ownership, available
capacity, modern equipment and large storage areas. Our Pier IX Terminal
competes primarily with two modern coal terminals located in the same Virginian
port complex as our Pier IX Terminal. The LAXT terminal exports coal to Japan
and competes with suppliers from other sources, primarily Australia. The current
price of coal produced in the U.S. makes it difficult to compete with foreign
sources and volumes through LAXT are expected to decline in 2002. There are
significant barriers to entry for the construction of new coal terminals,
including the requirement for significant capital expenditures and restrictive
environmental permitting requirements. However, we believe that at least one new
coal terminal will be constructed in Grand Rivers' geographic area and will
compete for coal volumes.

  Petroleum Coke and Other Bulk Terminals

     We own or operate eight petroleum coke terminals in the United States.
Petroleum coke is a by-product of the refining process and has characteristics
similar to coal. Petroleum coke supply in the United States has increased in the
last several years due to the increased use of coking units by domestic
refineries. Petroleum coke is used in domestic utility and industrial steam
generation facilities and is exported to foreign markets. Most of our customers
are large integrated oil companies that choose to outsource the storage and
loading of petroleum coke for a fee. We handled almost 8 million tons of
petroleum coke in 2001.

     We own or operate an additional 12 bulk terminals located primarily on the
southern edge of the lower Mississippi River, the Gulf Coast and the West Coast.
These other bulk terminals serve customers in the alumina, cement, salt, soda
ash, ilminite, fertilizer, ore and other industries seeking specialists who can
build, own and operate bulk terminals.

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

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located in Baton Rouge, Louisiana, is up for competitive bid in the first
quarter of 2002 and is at risk of not being renewed. Many of our other bulk
terminals were constructed pursuant to long-term contracts for specific
customers. As a result, we believe other terminal operators would face a
significant disadvantage in competing for this business.

  New Terminals

     We added nine new terminals to our Terminals segment in 2001. On March 1,
2001, we acquired Pinney Dock and Transport LLC, formerly Pinney Dock &
Transport Company, for approximately $52.5 million. The terminal is located in
Ashtabula, Ohio, on Lake Erie, and handles approximately 5 million tons of bulk
products per year, primarily iron ore and construction aggregates.

     On July 10, 2001, we acquired 4 terminals from Vopak for approximately
$44.3 million. Two of these terminals are located in Tampa, Florida, and
primarily handle various types of fertilizers. One is located in Fernandino
Beach, Florida, and handles containers and break bulk, primarily paper products.
The fourth terminal is located in Chesapeake, Virginia, and handles fertilizers
and various other bulk commodities.

     Effective July 2, 2001, we were hired as the material handling operator for
a titanium dioxide processing plant in Delisle, Mississippi. We handle titanium
ore and calcined petroleum coke on a per ton fee basis on a three year contract.

     On August 31, 2001, we acquired three terminals from Boswell Oil Company
for approximately $22.2 million. Two of these terminals were added to our Bulk
Terminals group and are located in Cincinnati, Ohio, and Vicksburg, Mississippi.
The other terminal handles liquid products and was placed in the Liquids
Terminals group.

     On October 18, 2001, we purchased the Operating and Use Agreement for the
Port of Longview, Washington, from International Raw Materials, Ltd., for $5.0
million. This agreement gives us exclusive use of a bulk material handling
system located in the Port of Longview. Products handled include soda ash,
bentonite clay, and various meal products. The Operating and Use Agreement
continues until 2013.

     We are of the opinion that we have generally satisfactory title to the
properties we own and use in our businesses, subject to liens for current taxes,
liens incident to minor encumbrances, and easements and restrictions which do
not materially detract from the value of such property or the interests therein
or the use of such properties in our businesses.

MAJOR CUSTOMERS

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

EMPLOYEES

     We do not have any employees. Kinder Morgan Services LLC and Kinder Morgan,
Inc. employ all persons necessary for the operation of our business. Generally
we reimburse Kinder Morgan Services LLC and Kinder Morgan, Inc. for the services
of their employees. As of December 31, 2001, Kinder Morgan Services LLC and
Kinder Morgan, Inc. had approximately 4,937 employees. Approximately 600 hourly
personnel at certain terminals are represented by labor unions. Kinder Morgan
Services LLC and Kinder Morgan, Inc. consider relations with employees to be
good. Please refer to Note 12 to our Consolidated Financial Statements.

                                        25
<PAGE>

REGULATION

  INTERSTATE COMMON CARRIER REGULATION

     Some of our pipelines are interstate common carrier pipelines, subject to
regulation by the Federal Energy Regulatory Commission under the Interstate
Commerce Act. The ICA requires that we maintain our tariffs on file with the
FERC, which tariffs set forth the rates we charge for providing transportation
services on our interstate common carrier pipelines as well as the rules and
regulations governing these services. Petroleum pipelines may change their rates
within prescribed ceiling levels that are tied to an inflation index. Shippers
may protest rate increases made within the ceiling levels, but such protests
must show that the portion of the rate increase resulting from application of
the index is substantially in excess of the pipeline's increase in costs. A
pipeline must, as a general rule, utilize the indexing methodology to change its
rates. The FERC, however, uses cost-of-service ratemaking, market-based rates
and settlement as alternatives to the indexing approach in certain specified
circumstances. In 2001, 2000 and 1999, application of the indexing methodology
did not significantly affect our rates.

     The ICA requires, among other things, that such rates be "just and
reasonable" and nondiscriminatory. The ICA permits interested persons to
challenge newly proposed or changed rates and authorizes the FERC to suspend the
effectiveness of such rates for a period of up to seven months and to
investigate such rates. If, upon completion of an investigation, the FERC finds
that the new or changed rate is unlawful, it is authorized to require the
carrier to refund the revenues in excess of the prior tariff collected during
the pendency of the investigation. The FERC may also investigate, upon complaint
or on its own motion, rates that are already in effect and may order a carrier
to change its rates prospectively. Upon an appropriate showing, a shipper may
obtain reparations for damages sustained during the two years prior to the
filing of a complaint.

     On October 24, 1992, Congress passed the Energy Policy Act of 1992. The
Energy Policy Act deemed petroleum pipeline rates that were in effect for the
365-day period ending on the date of enactment or that were in effect on the
365th day preceding enactment and had not been subject to complaint, protest or
investigation during the 365-day period to be just and reasonable under the ICA
(i.e., "grandfathered"). The Energy Policy Act also limited the circumstances
under which a complaint can be made against such grandfathered rates. The rates
we charge for transportation service on our North System and Cypress Pipeline
were not suspended or subject to protest or complaint during the relevant
365-day period established by the Energy Policy Act. For this reason, we believe
these rates should be grandfathered under the Energy Policy Act. Certain rates
on our Pacific operations' pipeline system were subject to protest during the
365-day period established by the Energy Policy Act. Accordingly, certain of the
Pacific pipelines' rates have been, and continue to be, subject to complaints
with the FERC, as is more fully described in Item 3. Legal Proceedings.

     Both the performance of interstate transportation and storage services by
natural gas companies, including interstate pipeline companies, and the rates
charged for such services, are regulated by the FERC under the Natural Gas Act
and, to a lesser extent, the Natural Gas Policy Act.

     Beginning in the mid-1980's, FERC initiated a number of regulatory changes
intended to create a more competitive environment in the natural gas
marketplace. Among the most important of these changes were Order 436 (1985)
requiring open-access, nondiscriminatory transportation of natural gas, Order
497 (1988) which set forth new standards and guidelines imposing certain
constraints on the interaction of interstate natural gas pipelines and their
marketing affiliates and imposing certain disclosure requirements regarding that
interaction, and Order 636 (1992). In Order 636, the FERC required interstate
pipelines that perform open access transportation under blanket certificates to
"unbundle" or separate their traditional merchant sales services from their
transportation and storage services and to provide comparable transportation and
storage services with respect to all natural gas supplies whether purchased from
the pipeline or from other merchants such as marketers or producers. Natural gas
pipelines must now separately state the applicable rates for each unbundled
service they provide (i.e., for the natural gas commodity, transportation and
storage).

                                        26
<PAGE>

     Order 636 contains a number of procedures designed to increase competition
in the industry, including:

     - requiring the unbundling of sales services from other services;

     - permitting holders of firm capacity to release all or a part of their
       capacity for resale by the pipeline; and

     - the issuance of blanket sales certificates to interstate pipelines for
       unbundled services.

     Order 636 has been affirmed in all material respects upon judicial review
and our own FERC orders approving our unbundling plans are final and not subject
to any pending judicial review.

     If any of our interstate natural gas pipelines ever have marketing
affiliates, we would become subject to the requirements of FERC Order Nos. 497,
et. seq., and 566, et. seq., the Marketing Affiliate Rules, which prohibit
preferential treatment by an interstate natural gas pipeline of its marketing
affiliates and govern in particular the provision of information by an
interstate pipeline to its marketing affiliates.

  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. We believe that these matters,
as finally adopted, will not have a material adverse effect on our business,
financial position or results of operations.

  FERC ORDER 637

  Kinder Morgan Interstate Gas Transmission LLC

     On June 15, 2000, KMIGT made its filing to comply with FERC's Orders 637
and 637-A. That filing contained KMIGT's compliance plan to implement the
changes required by FERC dealing with the way business is conducted on
interstate natural gas pipelines. All interstate natural gas pipelines were
required to make such compliance filings, according to a schedule established by
FERC. From October 2000 through June 2001, KMIGT held a series of technical and
phone conferences to identify issues, obtain input, and modify its Order 637
compliance plan, based on comments received from FERC Staff and other interested
parties and shippers. On June 19, 2001, KMIGT received a letter from FERC
encouraging it to file revised pro-forma tariff sheets, which reflected the
latest discussions and input from parties into its Order 637 compliance plan.
KMIGT made such a revised Order 637 compliance filing on July 13, 2001. The July
13, 2001 filing contained little substantive change from the original pro-forma
tariff sheets that KMIGT originally proposed on June 15, 2000. On October 19,
2001, KMIGT received an order from FERC, addressing its July 13, 2001 Order 637
compliance plan. In this Order, KMIGT's plan was accepted, but KMIGT was
directed to make several changes to its tariff, and in doing so, was directed
that it could not place the revised tariff into effect until further order of
the Commission. KMIGT filed its compliance filing with the October 19, 2001
Order on November 19, 2001 and also filed a request for rehearing/clarification
of the FERC's October 19, 2001 Order on November 19, 2001. The November 19, 2001
Compliance filing has been protested by several parties. KMIGT filed responses
to those protests on December 14, 2001. At this time, it is unknown when this
proceeding will be finally resolved. KMIGT currently expects that it may not
have a fully compliant Order 637 tariff approved and in effect until sometime in
the first or second quarter of 2002. The full impact of implementation of Order
637 on the KMIGT system is under evaluation. We believe that these matters will
not have a material adverse effect on our business, financial position or
results of operations.

                                        27
<PAGE>

     Separately, numerous petitioners, including KMIGT, have filed appeals of
Order 637 in the D.C. Circuit, potentially raising a wide array of issues
related to Order 637 compliance. Initial briefs were filed on April 6, 2001,
addressing issues contested by industry participants. Oral arguments on the
appeals were held before the courts in December 2001 and final action is
pending.

  Trailblazer Pipeline Company

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

     - segmentation;

     - scheduling for capacity release transactions;

     - receipt and delivery point rights;

     - treatment of system imbalances;

     - operational flow orders;

     - penalty revenue crediting; and

     - right of first refusal language.

     On October 15, 2001, FERC issued its order on Trailblazer'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. Trailblazer was required to make a filing in compliance with the order by
November 14, 2001. On November 14, 2001, Trailblazer made its compliance filing
pursuant to the FERC order of October 15, 2001. That compliance filing has been
protested. 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. Separately, also on November 14, 2001,
Trailblazer filed for rehearing of that FERC order. Trailblazer anticipates no
adverse impact on its business as a result of the implementation of Order No.
637.

  CALIFORNIA PUBLIC UTILITIES COMMISSION

     The intrastate common carrier operations of our Pacific operations'
pipelines in California are subject to regulation by the California Public
Utilities Commission under a "depreciated book plant" methodology, which is
based on an original cost measure of investment. Intrastate tariffs filed by us
with the CPUC have been established on the basis of revenues, expenses and
investments allocated as applicable to the California intrastate portion of our
Pacific operation's business. Tariff rates with respect to intrastate pipeline
service in California are subject to challenge by complaint by interested
parties or by independent action of the CPUC. A variety of factors can affect
the rates of return permitted by the CPUC and certain other issues similar to
those which have arisen with respect to our FERC regulated rates could also
arise with respect to our intrastate rates. Certain of our Pacific operations'
pipeline rates have been, and continue to be, subject to complaints with the
CPUC, as is more fully described in Item 3. Legal Proceedings.

  STATE AND LOCAL REGULATION

     Our activities are subject to various state and local laws and regulations,
as well as orders of regulatory bodies, governing a wide variety of matters,
including:

     - marketing;

     - production;

     - pricing;

                                        28
<PAGE>

     - pollution;

     - protection of the environment; and

     - safety.

  SAFETY REGULATION

     Our pipelines are subject to regulation by the United States Department of
Transportation with respect to their design, installation, testing,
construction, operation, replacement and management. In addition, we must permit
access to and copying of records, and make certain reports and provide
information as required by the Secretary of Transportation. Comparable
regulation exists in some states in which we conduct pipeline operations. In
addition, our truck and terminal loading facilities are subject to U.S. DOT
regulations dealing with the transportation of hazardous materials for motor
vehicles and rail cars. We believe that we are in substantial compliance with
U.S. DOT and comparable state regulations.

     We are also subject to the requirements of the Federal Occupational Safety
and Health Act and comparable state statutes. We believe that we are in
substantial compliance with Federal OSHA requirements, including general
industry standards, recordkeeping requirements and monitoring of occupational
exposure to hazardous substances.

     In general, we expect to increase expenditures in the future to comply with
higher industry and regulatory safety standards. Such expenditures cannot be
accurately estimated at this time, although we do not expect that such
expenditures will have a material adverse impact on us, except to the extent
additional hydrostatic testing requirements are imposed.

ENVIRONMENTAL MATTERS

     Our operations are subject to federal, state and local laws and regulations
governing the release of regulated materials into the environment or otherwise
relating to environmental protection or human health or safety. We believe that
our operations and facilities are in substantial compliance with applicable
environmental laws and regulations. Any failure to comply with these laws and
regulations may result in the assessment of administrative, civil and criminal
penalties, imposition of remedial requirements and issuance of injunction as to
future compliance. We have an ongoing environmental compliance program. However,
risks of accidental leaks or spills are associated with the transportation of
natural gas liquids, refined petroleum products, natural gas and carbon dioxide,
the handling and storage of liquid and bulk materials and the other activities
conducted by us. There can be no assurance that we will not incur significant
costs and liabilities relating to claims for damages to property and persons
resulting from the operation of our businesses. Moreover, it is possible that
other developments, such as increasingly strict environmental laws and
regulations and enforcement policies thereunder, could result in increased costs
and liabilities to us.

     Environmental laws and regulations have changed substantially and rapidly
over the last 25 years, and we anticipate that there will be continuing changes.
The clear trend in environmental regulation is to increase reporting obligations
and place more restrictions and limitations on activities, such as emissions of
pollutants, generation and disposal of wastes and use, storage and handling of
chemical substances, that may impact human health, the environment and/or
endangered species. Increasingly strict environmental restrictions and
limitations have resulted in increased operating costs for us and other similar
businesses throughout the United States. It is possible that the costs of
compliance with environmental laws and regulations will continue to increase. We
will attempt to anticipate future regulatory requirements that might be imposed
and to plan accordingly in order to remain in compliance with changing
environmental laws and regulations and to minimize the costs of such compliance.

     Although no assurance can be given, we believe that the ultimate resolution
of all these environmental matters will not have a material adverse effect on
our business, financial position or results of operations. We have recorded a
total reserve for environmental claims in the amount of $75.8 million at
December 31, 2001.

                                        29
<PAGE>

  SOLID WASTE

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

     We generate both hazardous and nonhazardous solid wastes that are subject
to the requirements of the Federal Resource Conservation and Recovery Act and
comparable state statutes. From time to time, state regulators and the United
States Environmental Protection Agency consider the adoption of stricter
disposal standards for nonhazardous waste. Furthermore, it is possible that some
wastes that are currently classified as nonhazardous, which could include wastes
currently generated during pipeline or bulk terminal operations, may in the
future be designated as "hazardous wastes." Hazardous wastes are subject to more
rigorous and costly disposal requirements. Such changes in the regulations may
result in additional capital expenditures or operating expenses for us.

  SUPERFUND

     The Comprehensive Environmental Response, Compensation and Liability Act,
also known as the "Superfund" law, and analogous state laws, impose liability,
without regard to fault or the legality of the original conduct, on certain
classes of "potentially responsible persons" for releases of "hazardous
substances" into the environment. These persons include the owner or operator of
a site and companies that disposed of or arranged for the disposal of the
hazardous substances found at the site. CERCLA authorizes the U.S. EPA and, in
some cases, third parties to take actions in response to threats to the public
health or the environment and to seek to recover from the responsible classes of
persons the costs they incur. Although "petroleum" is excluded from CERCLA's
definition of a "hazardous substance," in the course of our ordinary operations,
we will generate wastes that may fall within the definition of "hazardous
substance." By operation of law, if we are determined to be a potentially
responsible person, we may be responsible under CERCLA for all or part of the
costs required to clean up sites at which such wastes have been disposed.

     We are currently involved in cleanup activities at 13 federal or state
sites but do not believe costs associated with these sites will have a material
adverse effect on our results of operations.

  CLEAN AIR ACT

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

     Numerous amendments to the Clean Air Act were adopted in 1990. These
amendments contain lengthy, complex provisions that may result in the imposition
over the next several years of certain pollution control requirements with
respect to air emissions from the operations of our pipelines, storage
facilities and terminals. The U.S. EPA is developing, over a period of many
years, regulations to implement those requirements. Depending on the nature of
those regulations, and upon requirements that may be imposed by state and local
regulatory authorities, we may be required to incur certain capital expenditures
over the next several years for air pollution control equipment in connection
with maintaining or obtaining operating permits and approvals and addressing
other air emission-related issues.

                                        30
<PAGE>

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

  CLEAN WATER ACT

     Our operations can result in the discharge of pollutants. The Federal Water
Pollution control Act of 1972, as amended, also known as the Clean Water Act,
and analogous state laws impose restrictions and strict controls regarding the
discharge of pollutants into state waters or waters of the United States. The
discharge of pollutants into regulated waters is prohibited, except in accord
with the terms of a permit issued by applicable federal or state authorities.
The Oil Pollution Act was enacted in 1990 and amends provisions of the Clean
Water Act as they pertain to prevention and response to oil spills. Spill
prevention control and countermeasure requirements of the Clean Water Act and
some state laws require diking and similar structures to help prevent
contamination of navigable waters in the event of an overflow or release. We are
in substantial compliance with these laws.

  EPA GASOLINE VOLATILITY RESTRICTIONS

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

RISK FACTORS

     Pending Federal Energy Regulatory Commission and California Public
Utilities Commission proceedings seek substantial refunds and reductions in
tariff rates on some of our pipelines. If the proceedings are determined
adversely, they could have a material adverse impact on us.  In 1992, 1995 and
1999, some shippers on our pipelines filed complaints with the Federal Energy
Regulatory Commission and California Public Utilities Commission that seek
substantial refunds for alleged overcharges during the years in question and
prospective reductions in the tariff rates on our Pacific operations' pipeline
system.

     The complaints predominantly attacked the interstate pipeline tariff rates
of our Pacific operations' pipeline system, contending that the rates were not
just and reasonable under the Interstate Commerce Act and should not be entitled
to "grandfathered" status under the Energy Policy Act. Complaining shippers seek
substantial reparations for alleged overcharges during the years in question and
request prospective rate reductions on each of the challenged facilities.
Hearings on these complaints began in October 2001, and an initial decision by
the administrative law judge is expected in the first quarter of 2002.

     The complaints filed before the Federal Energy Regulatory Commission and
the California Public Utilities Commission challenge the rates charged for
intrastate transportation of refined petroleum through

                                        31
<PAGE>

the Pacific operations' pipeline system in California. After the California
Public Utilities Commission dismissed these complaints and subsequently granted
a limited rehearing on April 10, 2000, the complainants filed a new complaint
with the California Public Utilities Commission asserting the intrastate rates
were not just and reasonable.

     The Federal Energy Regulatory Commission complaint seeks approximately $137
million in tariff refunds and approximately $22 million in prospective annual
tariff reductions. The California Public Utilities Commission complaint seeks
approximately $20 million in tariff refunds and approximately $12 million in
prospective annual tariff reductions. Amounts, if any, ultimately owed will be
impacted by the passage of time and the application of interest. Decisions
regarding these complaints could negatively impact our cash flow. Additional
challenges to tariff rates could be filed with the Federal Energy Regulatory
Commission and California Public Utilities Commission in the future. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" in this report.

     Our rapid growth may cause difficulties integrating new operations.  As
discussed above, part of our business strategy includes acquiring additional
businesses that will allow us to increase distributions to our unitholders.
Unexpected costs or challenges may arise whenever businesses with different
operations and management are combined. Successful business combinations require
management and other personnel to devote significant amounts of time to
integrating the acquired business with existing operations. These efforts may
temporarily distract their attention from day-to-day business, the development
or acquisition of new properties and other business opportunities. In addition,
the management of the acquired business often will not join our management team.
The change in management may make it more difficult to integrate an acquired
business with our existing operations.

     Our acquisition strategy requires access to new capital. Tightened credit
markets or more expensive capital would impair our ability to grow.  Part of our
business strategy includes acquiring additional businesses that will allow us to
increase distributions to unitholders. During the period from December 31, 1996
to December 31, 2001, we made a significant number of acquisitions that
increased our asset base over 22 times and increased our net income over 37
times. We regularly consider and enter into discussions regarding potential
acquisitions and are currently contemplating potential acquisitions. These
transactions can be effected quickly, may occur at any time and may be
significant in size relative to our existing assets and operations. We may need
new capital to finance these acquisitions. Limitations on our access to capital
will impair our ability to execute this strategy. Expensive capital will limit
our ability to make acquisitions that increase net income and distributable cash
on a per unit basis. Our ability to maintain our capital structure may impact
the market value of our common units and our debt securities.

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

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

     We do not own approximately 97.5% of the land on which our pipelines are
constructed and we are subject to the possibility of increased costs to retain
necessary land use.  We obtain the right to construct and operate the pipelines
on other people's land for a period of time. If we were to lose these rights,
our business could be affected negatively.
                                        32
<PAGE>

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

     Whether we have the power of eminent domain for our pipelines varies from
state to state depending upon the type of pipeline -- petroleum liquids, natural
gas or carbon dioxide -- and the laws of the particular state. Our inability to
exercise the power of eminent domain could negatively affect our business if we
were to lose the right to use or occupy the property on which our pipelines are
located.

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

     If we were to be treated as a corporation for federal income tax purposes,
we would pay federal income tax on our income at the corporate tax rate, which
is currently a maximum of 35% and would pay state income taxes at varying rates.
Distributions to unitholders would generally be taxed as a corporate
distribution. Because a tax would be imposed upon us as a corporation, the cash
available for distribution to a unitholder would be substantially reduced.
Treatment of us as a corporation would cause a substantial reduction in the
value of our units.

     Our debt instruments may limit our financial flexibility and increase our
financing costs.  The instruments governing our debt contain restrictive
covenants that may prevent us from engaging in certain transactions that we deem
beneficial and that may be beneficial to us. The agreements governing our debt
generally require us to comply with various affirmative and negative covenants,
including the maintenance of certain financial ratios and restrictions on:

     - incurring additional debt;

     - entering into mergers, consolidations and sales of assets; and

     - granting liens.

     The instruments governing any future debt may contain similar restrictions.

                                        33
<PAGE>

ITEM 3.  LEGAL PROCEEDINGS.

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

ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

     There were no matters submitted to a vote of our unitholders during the
fourth quarter of 2001.

                                    PART II

ITEM 5.  MARKET FOR THE REGISTRANT'S EQUITY AND RELATED SECURITY HOLDER MATTERS.

     The following table sets forth, for the periods indicated, the high and low
sale prices per common unit, as reported on the New York Stock Exchange, the
principal market in which our common units are traded, and the amount of
distributions declared per common unit. All information has been adjusted to
give effect to the two-for-one split of common units effective August 31, 2001.

<Table>
<Caption>
                                                            PRICE RANGE
                                                          ---------------       CASH
                                                           HIGH     LOW     DISTRIBUTIONS
                                                          ------   ------   -------------
<S>                                                       <C>      <C>      <C>
2001
First Quarter...........................................  $31.73   $26.13      $0.5250
Second Quarter..........................................   36.70    30.67       0.5250
Third Quarter...........................................   37.08    30.75       0.5500
Fourth Quarter..........................................   39.05    34.55       0.5500
2000
First Quarter...........................................  $22.28   $19.25      $0.3875
Second Quarter..........................................   19.97    18.56       0.4250
Third Quarter...........................................   23.69    19.81       0.4250
Fourth Quarter..........................................   28.16    23.00       0.4750
</Table>

     All of the information is for distributions declared with respect to that
quarter. The declared distributions were paid within 45 days after the end of
the quarter. We currently expect that we will continue to pay comparable cash
distributions in the future assuming no adverse change in our operations,
economic conditions and other factors. However, we can give no assurance that
future distributions will continue at such levels.

     As of February 14, 2002, there were approximately 56,000 beneficial owners
of our common units, one holder of our Class B units and one holder of our
i-units.

                                        34
<PAGE>

ITEM 6.  SELECTED FINANCIAL DATA.

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

<Table>
<Caption>
                                                   YEAR ENDED DECEMBER 31,
                                 ------------------------------------------------------------
                                  2001(3)      2000(4)      1999(5)      1998(6)       1997
                                 ----------   ----------   ----------   ----------   --------
                                             (IN THOUSANDS, EXCEPT PER UNIT DATA)
<S>                              <C>          <C>          <C>          <C>          <C>
INCOME AND CASH FLOW DATA:
Revenues.......................  $2,946,676   $  816,442   $  428,749   $  322,617   $ 73,932
Cost of product sold...........   1,657,689      124,641       16,241        5,860      7,154
Operating expense..............     410,885      190,329      111,275       77,162     17,982
Fuel and power.................      73,188       43,216       31,745       22,385      5,636
Depreciation and
  amortization.................     142,077       82,630       46,469       36,557     10,067
General and administrative.....      99,009       60,065       35,612       39,984      8,862
                                 ----------   ----------   ----------   ----------   --------
Operating income...............     563,828      315,561      187,407      140,669     24,231
Earnings from equity
  investments..................      84,834       71,603       42,918       25,732      5,724
Amortization of excess cost of
  equity investments...........      (9,011)      (8,195)      (4,254)        (764)        --
Interest expense...............    (175,930)     (97,102)     (54,336)     (40,856)   (12,605)
Interest income and other,
  net..........................      (5,005)      10,415       22,988       (5,992)      (353)
Income tax (provision)
  benefit......................     (16,373)     (13,934)      (9,826)      (1,572)       740
                                 ----------   ----------   ----------   ----------   --------
Income before extraordinary
  charge.......................     442,343      278,348      184,897      117,217     17,737
Extraordinary charge...........          --           --       (2,595)     (13,611)        --
                                 ----------   ----------   ----------   ----------   --------
Net income.....................  $  442,343   $  278,348   $  182,302   $  103,606   $ 17,737
General partners' interest in
  net income...................  $  202,095   $  109,470   $   56,273   $   33,447   $  4,074
Limited partners' interest in
  net income...................  $  240,248   $  168,878   $  126,029   $   70,159   $ 13,663
Basic Limited Partners' income
  per unit before extraordinary
  charge(1)....................  $     1.56   $     1.34   $     1.31   $     1.04   $   0.51
Basic Limited Partners' net
  income per unit..............  $     1.56   $     1.34   $     1.29   $     0.87   $   0.51
Diluted Limited Partners' net
  income per unit(2)...........  $     1.56   $     1.34   $     1.29   $     0.87   $   0.51
Per unit cash distribution
  paid.........................  $     2.08   $     1.60   $     1.39   $     1.19   $   0.82
Additions to property, plant
  and equipment................  $  295,088   $  125,523   $   82,725   $   38,407   $  6,884

BALANCE SHEET DATA (AT END OF
  PERIOD):
Net property, plant and
  equipment....................  $5,082,612   $3,306,305   $2,578,313   $1,763,386   $244,967
Total assets...................  $6,732,666   $4,625,210   $3,228,738   $2,152,272   $312,906
Long-term debt.................  $2,231,574   $1,255,453   $  989,101   $  611,571   $146,824
Partners' capital..............  $3,159,034   $2,117,067   $1,774,798   $1,360,663   $150,224
</Table>

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

(1) Represents income before extraordinary charge per unit adjusted for the
    two-for-one splits of units on October 1, 1997 and on August 31, 2001. Basic
    Limited Partners' income per unit before

                                        35
<PAGE>

    extraordinary charge was computed by dividing the interest of our
    unitholders in income before extraordinary charge by the weighted average
    number of units outstanding during the period.

(2) 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.

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

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

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

(6) Includes results of operations for Pacific operations' pipeline system,
    Kinder Morgan Bulk Terminals and 24% interest in Plantation Pipe Line
    Company since dates of acquisition. Kinder Morgan Bulk Terminals were
    acquired on July 1, 1998 and our 24% interest in Plantation Pipe Line
    Company was acquired on September 15, 1998.

                                        36
<PAGE>

ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.

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

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

     Certain amounts included in or affecting our Consolidated Financial
Statements and related disclosures must be estimated, requiring us to make
certain assumptions with respect to values or conditions that cannot be known
with certainty at the time the financial statements are prepared.

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

     - the amounts we report for assets and liabilities;

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

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

     Therefore, the reported amounts of our assets and liabilities, revenues and
expenses and associated disclosures with respect to contingent assets and
obligations are necessarily affected by these estimates. We evaluate these
estimates on an ongoing basis, utilizing historical experience, consultation
with experts and other methods we consider reasonable in the particular
circumstances. Nevertheless, actual results may differ significantly from our
estimates. Any effects on our business, financial position or results of
operations resulting from revisions to these estimates are recorded in the
period in which the facts that give rise to the revision become known.

     In preparing our financial statements and related disclosures, we must use
estimates in determining the economic useful lives of our assets, provisions for
uncollectible accounts receivable, exposures under contractual indemnifications
and various other recorded or disclosed amounts. However, we believe that
certain accounting policies are of more significance in our financial statement
preparation process than others. With respect to our environmental exposure, we
utilize both internal staff and external experts to assist us in identifying
environmental issues and in estimating the costs and timing of remediation
efforts. Often, as the remediation evaluation and effort progresses, additional
information is obtained, requiring revisions to estimated costs. These revisions
are reflected in our income in the period in which they are reasonably
determinable. Finally, we are subject to litigation as the result of our
business operations and transactions. We utilize both internal and external
counsel in evaluating our potential exposure to adverse outcomes from judgments
or settlements. To the extent that actual outcomes differ from our estimates, or
additional facts and circumstances cause us to revise our estimates, our
earnings will be affected.

RESULTS OF OPERATIONS

     Our revenues, operating income, net income, earnings per unit and
distributable cash flow again reached record levels, driven by acquisitions,
strong internal growth and favorable performances by existing and newly acquired
pipelines and terminal facilities. In 2001, we continued our strategy of:

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

     - increasing utilization of assets while containing costs;

     - leveraging economies of scale from incremental acquisitions; and

     - maximizing the benefits of our financial structure.

     In 2001, our net income was $442.3 million ($1.56 per diluted unit) on
revenues of $2,946.7 million, compared to net income of $278.3 million ($1.34
per diluted unit) on revenues of $816.4 million in 2000,

                                        37
<PAGE>

and net income of $182.3 million ($1.29 per diluted unit) on revenues of $428.7
million in 1999. Included in our net income for 1999 was an extraordinary charge
of $2.6 million, associated with debt refinancing transactions, and a benefit of
$10.1 million related to the sale of our 25% interest in the Mont Belvieu
fractionation facility, partially offset by special non-recurring charges.

     Our total consolidated operating income was $563.8 million in 2001, $315.6
million in 2000 and $187.4 million in 1999. Our total consolidated net income
before extraordinary charges was $442.3 million in 2001, $278.3 million in 2000
and $184.9 million in 1999. Operating expenses, consisting of our combined cost
of sales, fuel, power and operating and maintenance expenses, were $2,087.5
million in 2001, compared with $332.2 million in 2000 and $143.1 million in
1999.

     Our increases in overall revenues, expenses and net income in 2001 compared
to 2000 resulted from assets and businesses that we acquired from GATX
Corporation in the first quarter of 2001, from KMI on December 31, 2000, and
from other acquisitions made during 2001 as well as internal growth from
existing assets. Our increases in overall revenues, expenses and net income in
2000 compared to 1999 primarily resulted from the inclusion of our Natural Gas
Pipelines segment, acquired from KMI on December 31, 1999, and our acquisition
of the remaining 80% ownership interest in Kinder Morgan CO(2) Company, L.P.
(formerly Shell CO(2) Company, Ltd.) effective April 1, 2000. Prior to that
date, we owned a 20% equity interest in Kinder Morgan CO(2) Company, L.P. and
reported its results under the equity method of accounting. The results of
Kinder Morgan CO(2) Company, L.P. are included in our CO(2) Pipelines segment.

  PRODUCTS PIPELINES

     Our Products Pipelines segment reported earnings of $308.8 million on
revenues of $605.4 million in 2001. In 2000, the segment reported earnings of
$221.1 million on revenues of $420.3 million. In 1999, the segment reported
earnings of $208.8 million on revenues of $313.0 million. The $87.7 million
increase in segment earnings in 2001 compared to 2000 is attributable to
acquisitions we made since December 2000 and cost savings resulting from our
operation of Plantation Pipe Line Company. Our revenues increased by $185.1
million as a result of our acquisitions, operating reimbursements from
Plantation and an 8% improvement in our Pacific operations' revenues. Our
Pacific operations achieved a 3% increase in mainline delivery volumes and an
over 4% increase in average tariff rates. Acquisitions made since the fourth
quarter of 2000, which contributed to our segment's results include:

     - Kinder Morgan Transmix Company, LLC;

     - the remaining 50% interest in the Colton Transmix Processing Facility;

     - a 34.8% interest in the Cochin Pipeline System (in January 2002, we
       acquired an additional 10% ownership interest, which was made effective
       December 31, 2001, bringing our total interest to 44.8%); and

     - assets acquired from GATX Corporation, consisting of Central Florida
       Pipeline LLC, CALNEV Pipe Line LLC and petroleum product and chemical
       terminals.

     Together, these businesses generated $202.0 million in revenues in 2001.
The segment's overall increase in revenues was partially offset by lower
transmix revenues. 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.

     Higher segment revenues in 2000 over 1999 resulted primarily from the
inclusion of a full year of operations from our initial acquisition of transmix
assets, acquired in September 1999, and the inclusion of two months of
operations from Kinder Morgan Transmix Company, LLC, acquired in late October
2000. Additionally, higher throughput volumes on both our Pacific operations and
North System pipelines contributed to the increase in segment revenues in 2000.
On our Pacific operations, average tariff rates remained relatively flat between
2000 and 1999, but an almost 3% increase in mainline delivery volumes

                                        38
<PAGE>

resulted in a 3% increase in revenues. On our North System, revenues grew 14% in
2000 compared to 1999. The increase was due to an almost 10% increase in
throughput revenue volumes, primarily due to strong refinery demand in the
Midwest, as well as a 5% increase in average tariff rates.

     Combined operating expenses for the Products Pipelines segment were $222.5
million in 2001, $172.4 million in 2000 and $76.4 million in 1999. The increase
in segment operating expenses in 2001 over the prior year resulted primarily
from our acquisitions, costs incurred under our operations agreement with
Plantation Pipe Line Company, as well as higher fuel and power expenses on our
Pacific operations' pipelines. This increase was partially offset by a reduction
in transmix cost due to our agreement with Duke Energy Merchants.

     The increase in 2000 expenses over 1999 levels resulted mainly from the
inclusion of our transmix operations and the higher delivery volumes on our
Pacific operations' pipelines. Segment operating income was $295.3 million in
2001, $193.4 million in 2000 and $186.0 million in 1999.

     Earnings from our Products Pipelines' equity investments, net of
amortization of excess costs, were $22.7 million in 2001, $29.1 million in 2000
and $21.4 million in 1999. The decrease in the segment's equity earnings in 2001
versus 2000 was due to lower equity earnings from Plantation Pipe Line Company
as a result of lower throughput and the absence of equity earnings from our
Colton Transmix Processing Facility during 2001. On December 31, 2000, we
acquired the remaining 50% ownership interest in the facility and since that
date, we have included Colton's operational results in our consolidated
financial statements.

     The increase in equity earnings in 2000 versus 1999 was chiefly due to our
investments in Plantation Pipe Line Company. We acquired our initial 24%
ownership interest in September 1998 and an additional 27% ownership interest in
June 1999.

     We are parties to proceedings at the Federal Energy Regulatory Commission
and the California Public Utilities Commission that challenge certain tariffs on
our Pacific operations. The Federal Energy Regulatory Commission complaint seeks
approximately $137 million in tariff refunds and approximately $22 million in
prospective annual tariff reductions. The California Public Utilities Commission
complaint seeks approximately $20 million in tariff refunds and approximately
$12 million in prospective annual tariff reductions. Amounts, if any, ultimately
owed will be impacted by the passage of time and the application of interest.
Decisions regarding these complaints could negatively impact our cash flow, and
additional challenges to tariff rates could be filed with the Federal Energy
Regulatory Commission and California Public Utilities Commission in the future.
We believe we have meritorious defenses in the proceedings challenging our
pipeline tariffs, and we are defending these proceedings vigorously. We believe
the ultimate resolutions of these proceedings will be more favorable to us than
the outcomes sought by the protesting shippers and expect these resolutions will
not have a material adverse effect on our financial condition or results of
operations; nonetheless, a decision by either or both of the California Public
Utilities Commission and Federal Energy Regulatory Commission granting the
complaining shippers the relief they seek may have a material adverse effect on
our financial condition or results of operations.

  NATURAL GAS PIPELINES

     Our Natural Gas Pipelines segment reported earnings of $193.7 million on
revenues of $1,869.3 million in 2001. In 2000, the segment reported earnings of
$113.0 million on revenues of $174.2 million. The segment's operating expenses
totaled $1,656.1 million in 2001 and $51.3 million in 2000. Segment results for
1999 primarily represent activity from a partnership interest in the Mont
Belvieu fractionation facility. Total segment earnings of $17.0 million in 1999
include $2.5 million in equity earnings from our 25% interest in the Mont
Belvieu Fractionator and $14.1 million from our third quarter gain on the sale
of that interest to Enterprise Products Partners, L.P.

                                        39
<PAGE>

     The year-to-year increases in operating results during 2001 and 2000 were
primarily due to the inclusion of assets acquired from KMI on December 31, 1999
and December 31, 2000, and the strong performance from existing assets.
Effective December 31, 1999, we acquired:

     - KMIGT;

     - a 33 1/3% interest in Trailblazer, having previously acquired a 33 1/3%
       interest in November 1999; and

     - a 49% interest in Red Cedar.

     Effective on December 31, 2000, we acquired:

     - Kinder Morgan Texas Pipeline, L.P.;

     - our Casper and Douglas natural gas gathering and processing systems;

     - a 50% interest in Coyote Gas Treating, LLC; and

     - a 25% interest in Thunder Creek.

     Kinder Morgan Texas Pipeline, L.P. purchases and sells natural gas, which
is transported through its pipeline. The purchase and sale activity results in
significantly higher revenues and operating expenses compared to the natural gas
pipelines acquired earlier from KMI. The earlier pipelines acquired charge a
transportation fee but do not purchase and sell gas. Combined, Kinder Morgan
Texas Pipeline, L.P. and the Casper and Douglas systems produced operating
revenues of $1,688.6 million and operating expenses of $1,608.0 million in 2001.
The segment's overall increase in revenues in 2001 over 2000 also resulted from
a 6% increase in revenues earned by KMIGT, mainly due to higher fuel recovery
revenues, driven by a reduction in fuel losses. The overall increase in segment
operating expenses was partially offset by lower expenses on the Trailblazer
Pipeline, primarily the result of favorable system imbalance settlements.

     Transported gas volumes on our natural gas assets increased almost 6% in
2000 compared with 1999 when KMI owned these assets. The overall increase
includes an almost 9% increase in volumes shipped on the Trailblazer Pipeline in
2000 compared to 1999. Higher capacity to receive natural gas on the Trailblazer
Pipeline during 2000 resulted in an increase in the available quantity of gas
delivered to the Trailblazer Pipeline. Segment operating income was $171.8
million in 2001 and $97.3 million in 2000.

     We account for our investments in Red Cedar, Coyote Gas Treating, LLC and
Thunder Creek under the equity method of accounting. Earnings from equity
investments, net of amortization, were $21.2 million for 2001 versus $15.0
million for the same prior year period. The $6.2 million increase in equity
earnings resulted from the inclusion of $3.5 million of net equity earnings from
the segment's investments in Coyote and Thunder Creek and a $2.7 million
increase in earnings from its 49% interest in the Red Cedar Gathering Company,
primarily the result of higher revenues from custom compression projects.

  CO(2) PIPELINES

     Our CO(2) Pipelines segment consists of KMCO(2). In 2001, CO(2) Pipelines
earned $91.8 million on revenues of $122.1 million. The segment reported
operating expenses of $37.4 million and operating income of $59.3 million.
Equity earnings, net of amortization of excess costs, were $32.0 million,
consisting of $23.7 million from a full year of earnings from the segment's
interest in Cortez Pipeline Company and $8.3 million from a full year of
earnings from its 15% equity investment in MKM Partners, L.P., an oil and gas
joint venture with Marathon Oil Company that began January 1, 2001.

     Prior to our acquisition of the remaining 80% interest in KMCO(2), on April
1, 2000, we accounted for our investment under the equity method of accounting.
Furthermore, under the terms of the prior KMCO(2) partnership agreement, we
received a priority distribution of $14.5 million per year during 1999 and the
first quarter of 2000. After our acquisition of the remaining 80% ownership
interest, we amended this partnership agreement, among other things, to
eliminate the priority distribution and other provisions rendered irrelevant by
our sole ownership and we included the company's financial results in our

                                        40
<PAGE>

consolidated financial statements. The segment's 2000 results include one
quarter of equity earnings from our original 20% interest in KMCO(2) and returns
from the significant carbon dioxide pipeline assets and oil-producing property
interests that we acquired from Devon Energy on June 1, 2000.

     For the year 2000, the CO(2) Pipelines segment reported earnings of $68.0
million on revenues of $89.2 million. The segment reported operating expenses of
$26.8 million and operating income of $47.9 million. Equity earnings, net of
amortization of excess costs, totaled $19.3 million, representing $3.6 million
from our 20% interest in KMCO(2) and $15.7 million from the segment's 50%
interest in the Cortez Pipeline Company.

     Our 1999 results primarily represent equity earnings from our original 20%
interest in KMCO(2). Segment earnings of $15.2 million in 1999 included $14.5
million in equity earnings from our 20% interest in KMCO(2)

  TERMINALS

     Effective in the third quarter of 2001, our Terminals segment reflects
changes we made in the organization of our business segments. We have combined
our previous Bulk Terminals and Liquids Terminals business segments to present
our current Terminals segment. The segment reported earnings of $129.9 million
on revenues of $349.9 million in 2001. This compares to earnings of $37.6
million on revenues of $132.8 million in 2000 and to earnings of $35.0 million
on revenues of $114.6 million in 1999.

     The year-to-year increases in our Terminals revenues, expenses and earnings
were driven principally by key acquisitions we have made since December 1999.
The acquisitions include:

     - Milwaukee Bulk Terminals, Inc., acquired effective January 1, 2000;

     - Dakota Bulk Terminal, Inc., acquired effective January 1, 2000;

     - Delta Terminal Services LLC, acquired effective December 1, 2000;

     - KMLT, acquired from GATX Corporation effective January 1, 2001;

     - Pinney Dock & Transport LLC, acquired effective March 1, 2001;

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

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

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

     In 2001, the acquisitions listed above generated revenues of $215.6
million. On an aggregate basis, bulk tonnage transfer volumes, including coal
and all other bulk materials, increased 22% over 2000 levels. Our transfers of
liquids volumes, including refined petroleum products, chemicals and all other
liquids volumes increased 8% in 2001 compared with 2000 when the liquids
terminals were owned by other entities. In 2000, the acquisitions listed above
as 2000 acquisitions generated revenues of $11.4 million. Bulk tonnage transfer
volumes, including coal and all other bulk material transfers, increased 6% in
2000 over 1999 levels.

     Combined operating expenses for our Terminals segment totaled $171.5
million in 2001 versus $81.7 million in 2000 and $66.6 million in 1999. The
increase in 2001 operating expenses over 2000 was the result of acquisitions
made in 2001 and higher maintenance and operating expenses associated with the
transfer of higher volumes. The increase in 2000 versus 1999 was the result of
acquisitions made in 2000, higher operating expenses associated with the
transfer of higher coal volumes and an increase in fuel costs.

  OTHER

     Items not attributable to any segment include general and administrative
expenses, interest income and expense and minority interest. General and
administrative expenses totaled $99.0 million in 2001

                                        41
<PAGE>

compared with $60.1 million in 2000 and $35.6 million in 1999. The year-to-year
increases in our general and administrative expenses were mainly due to our
larger and more diverse operations. During 2001, we incorporated pipeline and
terminal businesses that we acquired from GATX Corporation, incorporated
additional natural gas pipeline assets that we acquired from KMI on December 31,
2000 and operated Plantation Pipe Line Company for a full year. During 2000, we
formed our natural gas pipelines and CO(2) pipelines business segments. 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 $171.5 million in
2001, $93.3 million in 2000 and $52.6 million in 1999. The 2001 increase was
primarily due to the additional debt we issued related to the financing of the
acquisitions that we have made since the end of 2000 and to the $134.8 million
in third-party debt we assumed as part of the assets acquired from GATX
Corporation. In March 2001, we closed a public offering of $1.0 billion in
principal amount of senior notes. The 2000 increase was primarily due to the
additional debt we incurred related to the financing of our 2000 and 1999
investments.

     Minority interest increased to $11.4 million in 2001 compared with $8.0
million in 2000 and $2.9 million in 1999. The $3.4 million increase in 2001 over
2000 resulted from earnings attributable to MidTex Gas Storage Company, L.P., a
partnership controlled by Kinder Morgan Texas Pipeline L.P. as well as to our
higher overall income. The $5.1 million increase in 2000 over 1999 primarily
resulted from the inclusion of earnings attributable to the Trailblazer Pipeline
Company.

OUTLOOK

     We actively pursue a strategy to increase our operating income. We will use
a three-pronged approach to accomplish this goal.

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

     - Internal Growth.  We intend to expand the operations of our current
       facilities. We have taken a number of steps that management believes will
       increase revenues from existing operations, including the following:

      - a $25 million expansion of our carbon dioxide project in the SACROC unit
        in Scurry County of west Texas. The project is expected to increase
        deliveries of carbon dioxide to SACROC by nearly 80%, to 125 million
        cubic feet of carbon dioxide per day. The project is expected to be
        completed in the first quarter of 2002;

      - a $9 million expansion project on the CALNEV pipeline. The project will
        bolster the jet fuel supply to McCarran International Airport in Las
        Vegas, Nevada. We will share the costs of the project with LASFUEL, the
        McCarran International Airport fuel consortium. The project is expected
        to be completed in the second quarter of 2002; and

      - a $16.3 million plan to expand our Pasadena and Galena Park, Texas
        facilities, which, collectively, are the largest independently operated
        liquids terminals in the world. The expansion will increase tank storage
        capacity by an additional 830,000 barrels within the next year and will
        include pipe modifications to enhance docking facilities.

                                        42
<PAGE>

     - Strategic Acquisitions.  Since January 1, 2001, we have made the
       following acquisitions:

<Table>
<S>                                      <C>
- Kinder Morgan Liquids Terminals LLC    January 1, 2001;
- Central Florida Pipeline LLC           January 1, 2001;
- Pinney Dock & Transport LLC            March 1, 2001;
- CALNEV Pipe Line LLC                   March 30, 2001;
- Additional 2.3% interest in Cochin
  Pipeline System                        June 20, 2001;
- Vopak terminal LLC's                   July 10, 2001;
- Kinder Morgan Texas Pipeline           July 18, 2001;
- Boswell bulk and liquids terminal
  assets                                 August 31, 2001;
- Stolt-Nielsen liquids terminal assets  November 8 and 29, 2001;
- Snyder and Diamond M gas plant
  interests                              November 14, 2001; and
- Additional 10% interest in Cochin
  Pipeline System                        effective as of December 31, 2001.
</Table>

     The costs and methods of financing for each of these acquisitions are
discussed under "Capital Requirements for Recent Transactions."

     We regularly seek opportunities to make additional strategic acquisitions,
to expand existing businesses and to enter into related businesses. We
periodically consider potential acquisition opportunities as they are
identified, but we cannot assure you that we will be able to consummate any such
acquisition. Our management anticipates that we will finance acquisitions by
borrowings under our bank credit facilities or by issuing commercial paper, and
subsequently reduce these short-term borrowings by issuing new long-term debt
securities, common units and/or i-units to Kinder Morgan Management.

     We are continuing to assess the effect of the terrorist attacks of
September 11, 2001 on our businesses. In response to the attacks, we have
increased security at our liquids terminals and performed security surveys on
certain sections of our pipelines. We face the possibility that during 2002,
property insurance carriers generally may terminate insurance coverage for all
companies for incidents of sabotage and terrorism. We are exploring the
availability of sabotage and terrorism insurance from other sources, though
proposed federal legislation may provide an insurance framework that will cause
current insurers to continue to provide sabotage and terrorism coverage under
standard property insurance policies. Nonetheless, there is no assurance that
federal legislation will be passed or adequate sabotage and terrorism insurance
will be available throughout 2002.

     We do not believe that the increased cost associated with these measures
will have a material effect on our operating results. As of December 31, 2001,
we have not noticed a significant decrease in the volumes of product that we are
moving through our operations as a result of the September 11, 2001 attacks.
However, if demand for the products that we handle were to significantly
decrease, our shippers would decrease the volumes that they ship through our
systems or that we handle and store for them, which may have a negative impact
on our financial performance.

     With respect to certain related party transactions, see Note 12 to the
Consolidated Financial Statements included elsewhere in this report.

                                        43
<PAGE>

LIQUIDITY AND CAPITAL RESOURCES

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

<Table>
<Caption>
                                                               DECEMBER 31,
                                                   ------------------------------------
                                                      2001         2000         1999
                                                   ----------   ----------   ----------
<S>                                                <C>          <C>          <C>
Long-term debt...................................  $2,231,574   $1,255,453   $  989,101
Minority interests...............................      65,236       58,169       48,299
Partners' capital................................   3,159,034    2,117,067    1,774,798
                                                   ----------   ----------   ----------
  Total capitalization...........................   5,455,844    3,430,689    2,812,198
Short-term debt, less cash and cash
  equivalents....................................     497,417      589,630      169,148
                                                   ----------   ----------   ----------
     Total invested capital......................  $5,953,261   $4,020,319   $2,981,346
                                                   ==========   ==========   ==========
Capitalization:
  Long-term debt.................................        40.9%        36.6%        35.2%
  Minority interests.............................         1.2%         1.7%         1.7%
  Partners' capital..............................        57.9%        61.7%        63.1%
Invested Capital:
  Total debt.....................................        45.8%        45.9%        38.8%
  Partners' capital and minority interests.......        54.2%        54.1%        61.2%
</Table>

  SUMMARY OF OFF BALANCE SHEET FINANCING

     We have obligations with respect to other entities which are not
consolidated in our financial statements as shown below (in millions):

<Table>
<Caption>
                                                                                                   OUR
                                       OUR                                TOTAL      TOTAL      CONTINGENT
                       INVESTMENT   OWNERSHIP   REMAINING INTEREST(S)     ENTITY     ENTITY      SHARE OF
ENTITY                    TYPE      INTEREST          OWNERSHIP         ASSETS(4)     DEBT    ENTITY DEBT(5)
------                 ----------   ---------   ---------------------   ----------   ------   --------------
<S>                    <C>          <C>         <C>                     <C>          <C>      <C>
Cortez Pipeline
  Company............  General         50%              (1)                $171       $282         $142(2)
                       Partner
Plantation Pipe Line
  Company............  Common          51%      ExxonMobil                 $243       $175         $ 10
                       Shareholder              Corporation
Red Cedar Gas
  Gathering Company..  General         49%      Southern Ute               $163       $ 55         $ 55
                       Partner                  Indian Tribe
Nassau County,                                  Nassau County,
  Florida Ocean                                 Florida Ocean
  Highway and                                   Highway and Port
  Port
     Authority(3)....  N/A             N/A      Authority                   N/A        N/A         $ 28
</Table>

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

(1) The remaining general partner interests are owned by ExxonMobil Cortez
    Pipeline, Inc., an indirect wholly-owned subsidiary of ExxonMobil
    Corporation and Cortez Vickers Pipeline Company, an indirect subsidiary of
    M.E. Zuckerman Energy Investors Incorporated.

(2) We are severally liable for our percentage ownership share of the Cortez
    Pipeline Company debt. Further, pursuant to a Throughput and Deficiency
    Agreement, the owners of Cortez Pipeline

                                        44
<PAGE>

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

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

(4) Principally property, plant and equipment.

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

     Our share of earnings, based on our ownership percentage, before income
taxes and amortization of excess investment cost was $25.7 million from Cortez
Pipeline Company, $25.3 million from Plantation Pipe Line Company and $18.8
million from Red Cedar Gathering Company. Additional information regarding these
investments is included in Note 7 to the Consolidated Financial Statements
included elsewhere in this report.

  SUMMARY OF CERTAIN CONTRACTUAL OBLIGATIONS

<Table>
<Caption>
                                               AMOUNT OF COMMITMENT EXPIRATION PER PERIOD
                                       -----------------------------------------------------------
                                                    LESS THAN                            AFTER 5
                                         TOTAL       1 YEAR     2-3 YEARS   4-5 YEARS     YEARS
                                       ----------   ---------   ---------   ---------   ----------
                                                             (IN THOUSANDS)
<S>                                    <C>          <C>         <C>         <C>         <C>
Commercial paper outstanding.........  $  590,503   $590,503    $     --    $     --    $       --
Senior Notes due March 22, 2002......     200,000    200,000          --          --            --
SFPP First Mortgage Notes............      42,500     42,500          --          --            --
Other short-term borrowings..........       3,500      3,500          --          --            --
Long-term debt.......................   1,955,290         16      92,090     199,772     1,663,412
Operating leases.....................     134,180     16,735      26,835      21,817        68,793
                                       -----------------------------------------------------------
Total................................  $2,925,973   $853,254    $118,925    $221,589    $1,732,205
</Table>

  PRIMARY CASH REQUIREMENTS

     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:

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

     - expansion capital expenditures and working capital deficits through
       additional borrowings or issuance of additional common units or
       additional i-units to Kinder Morgan Management;

     - interest payments from cash flows from operating activities; and

     - 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.

                                        45
<PAGE>

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

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

     Of the $836.5 million scheduled to mature in 2002, we intend, and have the
ability, to refinance $276.3 million on a long-term basis under our $300 million
multi-year credit facility. We plan to refinance the remaining $560.2 million
under a new credit agreement, through an extension of our existing $750 million
unsecured 364-day credit facility, by newly issued long-term debt, or by the
issuance of additional i-units to Kinder Morgan Management. Our existing $750
million credit facility expires in October 2002.

     During the first quarter of 2002, we will need approximately $890 million
for the following acquisitions and expansion projects (see Note 3 to our
Consolidated Financial Statements):

     - the remaining 33 1/3% ownership interest in Trailblazer;

     - Tejas Gas, LLC;

     - an additional 10% ownership interest in the Cochin Pipeline System; and

     - two terminal acquisitions and a liquids terminal expansion project.

     We expect to fund these acquisitions using a combination of borrowings
under our commercial paper program, the issuance of new long-term debt, and/or
the issuance of additional i-units to Kinder Morgan Management. We expect to
secure a new temporary credit facility in the amount of $750 million to support
an increase in outstanding commercial paper until permanent financing is put in
place.

     We announced on February 15, 2002 the termination of the proposed Sonoran
Pipeline project, a proposed joint venture with Calpine Corporation, due to
insufficient binding commitments from shippers to support the project. We did
not spend significant dollars on the proposed development of the pipeline and it
was not expected to begin service until 2004. The Sonoran Pipeline would have
extended from the Blanco Hub and terminated near Needles and Topock, California,
with the possibility of a second phase extending into northern California.

     At December 31, 2001, our current commitments for capital expenditures were
approximately $73.8 million. This amount has primarily been committed for the
purchase of plant and equipment and is based on the payments we expect to need
for our 2002 sustaining capital expenditure plan. We fund sustaining capital
expenditures with cash flows from operating activities. All of our capital
expenditures, with the exception of sustaining capital expenditures, are
discretionary.

  OPERATING ACTIVITIES

     Net cash provided by operating activities was $581.2 million in 2001 versus
$301.6 million in 2000. The $279.6 million increase in 2001 was driven by a
$211.0 million increase in cash earnings, reflecting the strong performance and
growth that occurred across most of our business portfolio. The year-to-year
increase in operating cash flows also reflects the $52.5 million of tariff rate
refund payments we made during 2000. The payment of these rate refunds was made
under settlement agreements between shippers and our Natural Gas Pipelines.
Distributions from our equity investments increased $21.3 million, mainly due to
distributions received from our 50% investment in Cortez Pipeline Company.
Following our

                                        46
<PAGE>

acquisition of the remaining ownership interest in KMCO(2) on April 1, 2000, we
accounted for our investment in Cortez Pipeline Company under the equity method
of accounting. The overall increase in cash provided by operating activities was
partially offset by lower cash inflows relative to payments made on current
accounts, primarily due to the business acquisitions we made during 2001.

  INVESTING ACTIVITIES

     Net cash used in investing activities was $1,818.9 million for the year
ended December 31, 2001, compared to $1,197.6 million for the prior year. The
$621.3 million increase in funds utilized in investing activities was mainly
attributable to higher amounts spent on both asset acquisitions and capital
expenditures. We continue to invest significantly in strategic acquisitions in
order to fuel future growth and increase unitholder value. In 2001, we spent
$1,523.5 million to acquire new assets and businesses. In 2000, our expenditures
on acquisitions were $1,008.6 million.

     Our expenditures in 2001 included:

     - $982.7 million for the acquisition of GATX Corporation's domestic
       pipelines and terminals business, including KMLT, CALNEV Pipe Line LLC
       and Central Florida Pipeline LLC;

     - $359.1 million for KM Texas Pipeline, L.P.;

     - $44.8 million for liquids terminals acquired from an affiliate of
       Stolt-Nielsen, Inc.;

     - $43.6 million for bulk terminal LLC's acquired from Koninklijke Vopak
       N.V.;

     - $41.7 million for Pinney Dock & Transport LLC; and

     - $18.0 million for bulk and liquids terminal assets acquired from Boswell
       Oil Company.

     We expended an additional $169.6 million for capital expenditures in 2001
compared to 2000. Including expansion and maintenance projects, our capital
expenditures were $295.1 million in 2001 and $125.5 million in 2000. The
increase was driven primarily by continued investment in our CO(2) Pipelines and
Natural Gas Pipelines business segments. Our overall increase in cash used in
investing activities was partially offset by a reduction in expenditures for
acquisitions of investments during 2001.

     Our 2000 investment outlays included:

     - $34.2 million for our 7.5% interest in the Yates field unit subsequently
       contributed to the carbon dioxide joint venture with Marathon Oil Company
       (MKM Partners, L.P.); and

     - $44.6 million for our 25% interest in Thunder Creek and our 50% interest
       in Coyote Gas Treating, LLC.

  FINANCING ACTIVITIES

     Net cash provided by financing activities amounted to $1,241.2 million in
2001. This increase of $325.9 million from the prior year was the result of an
additional $829.5 million we received from the issuance of limited partner
units. In May 2001, we received net proceeds of approximately $996.9 million
from Kinder Morgan Management for the issuance of i-units. In connection with
Kinder Morgan Management's public offering of its shares, i-units were issued as
follows:

     - 2,975,000 units to KMI; and

     - 26,775,000 to the public.

     We used the proceeds from our i-unit issuance to reduce the debt we
incurred in our acquisition of GATX Corporation's domestic pipeline and liquids
terminal businesses during the first quarter of 2001. The i-units are a separate
class of limited partner interest in us. All of our i-units are owned by Kinder
Morgan Management and are not publicly traded.

                                        47
<PAGE>

     The overall increase in funds received from the issuance of units increased
in 2001 although proceeds from the issuance of common units decreased by $167.4
million. This was attributable to our 9 million common unit public offering on
April 4, 2000, which resulted in net proceeds of $171.2 million. Additionally,
our issuance of debt, net of repayments, provided $729.6 million in cash during
2001 versus $1,033.4 million during 2000. Our debt repayments increased as a
result of the use of proceeds from our i-unit issuance. Funds received from our
issuance of debt is attributable to our 2001 public offering of $1.0 billion in
principal amount of senior notes, resulting in a net cash inflow of $990
million, net of discounts and issuing costs. We used the proceeds to pay for our
acquisition of Pinney Dock & Transport LLC and to reduce the outstanding
balances on our credit facilities and commercial paper borrowings. During 2000,
we completed two private placements totaling $650 million in debt securities
resulting in a cash inflow of $644.7 million, net of discounts and issuing
costs.

     The overall increase in funds provided by our financing activities was also
offset by a $179.6 million increase in cash distributions to our partners. Cash
distributions to all partners increased to $473.2 million in 2001 compared to
$293.6 million in 2000. The increase in distributions was due to:

     - an increase in the per unit cash distributions paid;

     - an increase in the number of units outstanding; and

     - 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.

     We paid distributions of $2.08 per unit in quarterly distributions in 2001
compared to $1.60 per unit in 2000. The 30% increase in paid distributions per
unit resulted from favorable operating results in 2001.

     We also distributed 886,361 i-units in quarterly distributions during 2001
to Kinder Morgan Management, our sole i-unitholder. The amount of i-units
distributed was based upon the amount of cash we distributed to the owners of
our common units for the second and third quarters of 2001. For each outstanding
i-unit that Kinder Morgan Management held, a fraction of an i-unit was issued.
The fraction was determined by dividing:

     - the cash amount distributed per common unit

by

     - the average of 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.

  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 as described below. Available Cash consists generally of
all of our cash receipts, including cash received by our operating partnerships,
and net reductions in reserves less cash disbursements and net additions to
reserves (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, L.P.

     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 distributions, it considers current and expected
reserve needs along with current and expected cash flows to identify the
appropriate sustainable distribution level. For 2001, 2000 and 1999, we
distributed 100%, 102% and 97%, of the total of cash receipts less cash

                                        48
<PAGE>

disbursements, respectively. The difference between these numbers and 100%
reflects net additions to or reductions in reserves.

     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;

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

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

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

     - fourth, 50% of any available cash then remaining to the owners of all
       classes of units pro rata, to owners of common units and Class B units in
       cash and to 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 that we
declared for 2001 was $199.7 million, while the incentive distribution paid to
our general partner during 2001 was $178.1 million. All partnership
distributions we declared for the fourth quarters of each year were declared and
paid in the first quarter of the following year.

     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 and 5% greater than the $0.525 distribution paid
for the first quarter of 2001. 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.

  DEBT AND CREDIT FACILITIES

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

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

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

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

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

                                        49
<PAGE>

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

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

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

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

     - $25 million of New Jersey Economic Development Revenue Refunding Bonds
       due January 15, 2018 (our subsidiary, KMLT, is the obligor on the bonds);

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

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

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

     - $87.9 million of Industrial Revenue Bonds with final maturities ranging
       from September 2019 to December 2024 (our subsidiary, KMLT, is the
       obligor on the bonds);

     - $35 million of 7.84% Senior Notes, with a final maturity of July 2008
       (our subsidiary, Central Florida Pipe Line LLC, is the obligor on the
       notes); and

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

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

     - $590.5 million of commercial paper borrowings;

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

     - $42.5 million under SFPP L.P.'s 10.70% Series F First Mortgage Notes; and

     - $3.5 million in other borrowings.

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

     During 2001, our cash used for acquisitions and expansions exceeded $1.5
billion. We utilized our short-term credit facilities and issued long-term debt
securities to fund these acquisitions and then reduced our short-term borrowings
with the proceeds from our May 2001 issuance of i-units. Historically, we have
utilized our short-term credit facilities to fund acquisitions and expansions
and then refinanced our short-term borrowings utilizing long-term credit
facilities and by issuing equity or long-term debt securities. We intend to
refinance our short-term debt during 2002 through a combination of long-term
debt, equity and the issuance of additional commercial paper to replace maturing
commercial paper borrowings.

  Credit Facilities

     Our $750 million and $300 million credit facilities referred to above are
with a syndicate of financial institutions. First Union National Bank is the
administrative agent under these facilities. Interest on borrowings is payable
quarterly, and accrues at our option at a floating rate equal to either:

     - First Union National Bank's base rate (but not less than the Federal
       Funds Rate, plus 0.5%) (as of December 31, 2001, First Union National
       Bank's base rate was 4.75%); or

     - LIBOR, plus a margin, which varies depending upon the credit rating of
       our long-term senior unsecured debt (as of December 31, 2001, we could
       borrow for one month at a rate of 2.395% under our 364-day facility and
       2.345% under our 5-year facility).

                                        50
<PAGE>

     These rates have decreased since the beginning of 2001 as short-term
interest rates have fallen. Our five-year credit facility also permits us to
obtain bids for fixed rate loans from members of the lending syndicate.

     Our credit facilities include the following restrictive covenants as of
December 31, 2001:

     - requirements to maintain certain financial ratios: total debt divided by
       EBITDA for the prior four quarters may not exceed 4.0, and EBITDA for the
       prior four quarters divided by interest expense for the prior four
       quarters may not fall below 3.5;

     - limitations on our ability to incur additional debt having a senior
       position to the indebtedness under our credit facilities and on the
       amount of additional indebtedness that may be incurred by our
       subsidiaries;

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

     - limitations on granting liens;

     - prohibitions on making cash distributions to holders of units more
       frequently than quarterly;

     - prohibitions on making cash distributions in excess of 100% of available
       cash for the immediately preceding calendar quarter; and

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

     We are in compliance with these covenants. No borrowings were outstanding
under our two credit facilities at December 31, 2001. After taking into account
outstanding commercial paper borrowings and letters of credit, the amount
available for borrowing under our credit facilities was $435.8 million as of
December 31, 2001. We intend to secure promptly after the date of this document
an additional $750 million credit facility to back-up an increase in our
commercial paper program to $1.8 billion to fund the Tejas acquisition. We
expect to terminate this facility once we have issued debt and equity to
permanently finance the acquisition. At that time, our commercial paper capacity
will be reduced to $1.05 billion. We expect to increase the debt to EBITDA ratio
allowed by our credit facilities to 4.25 to 1 through June 30, 2002.

     We have an outstanding letter of credit issued under our five-year credit
facility in the amount of $23.7 million that backs-up our tax-exempt bonds due
2024. The letter of credit reduces the amount available for borrowing under that
credit facility. 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. At December 31, 2001, the
interest rate was 1.70%.

  Commercial Paper Program

     In December 1999, we established a commercial paper program providing for
the issuance of up to $200 million of commercial paper, subsequently increased
to $300 million in January 2000. On October 25, 2000, in conjunction with our
new 364-day credit facility, we also increased our commercial paper program to
provide for the issuance of up to $600 million of commercial paper. During the
first quarter of 2001, we increased our commercial paper program to provide for
the issuance of an additional $1.1 billion of commercial paper, and during the
second quarter of 2001, we decreased our commercial paper program back to $600
million. On October 17, 2001, we increased our commercial paper program to $900
million. Borrowings under our commercial paper program reduce the borrowings
allowed under our credit facilities. As of December 31, 2001, we had $590.5
million of commercial paper outstanding with an interest rate of 2.6585%. The
borrowings under our commercial paper program were used to finance acquisitions
and expansion projects that occurred during 2001. On February 11, 2002, our
commercial paper program was increased to provide for the issuance of up to $1.8
billion of commercial paper. We intend to secure promptly after the date of this
document an additional $750 million credit facility to back-up the increase in
our commercial paper program. We expect to terminate this facility once we have

                                        51
<PAGE>

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

  Trailblazer Pipeline Company Debt

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

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

     On September 23, 1992, pursuant to the terms of a Note Purchase Agreement,
Trailblazer Pipeline Company issued and sold an aggregate principal amount of
$101 million of Senior Secured Notes to a syndicate of fifteen insurance
companies. The Senior Secured Notes had a fixed annual interest rate of 8.03%
and the $20.2 million balance as of December 31, 2000 was to be repaid in
semiannual installments of $5.05 million from March 1, 2001 through September 1,
2002, the final maturity date. Interest was payable semiannually in March and
September. Trailblazer provided collateral for the notes principally by an
assignment of certain Trailblazer transportation contracts, and pursuant to the
terms of this Note Purchase Agreement, Trailblazer's partnership distributions
were restricted by certain financial covenants. Effective April 29, 1997,
Trailblazer amended the Note Purchase Agreement. This amendment allowed
Trailblazer to include several additional transportation contracts as collateral
for the notes, added a limitation on the amount of additional money that
Trailblazer could borrow and relieved Trailblazer from its security deposit
obligation. On June 26, 2001, Trailblazer prepaid the $15.2 million balance
outstanding under the Senior Secured Notes, plus $0.8 million for interest and a
make-whole premium, using its new two-year unsecured revolving credit facility.

  SFPP, L.P. Debt

     At December 31, 2001, the outstanding balance under SFPP, L.P.'s Series F
notes was $79.6 million. The annual interest rate on the Series F notes is
10.70%, the maturity is December 2004, and interest is payable semiannually in
June and December. We expect to repay the Series F notes prior to maturity as a
result of SFPP, L.P. taking advantage of certain optional prepayment provisions
without penalty in 1999 and 2000. Remaining annual installments are $42.6
million in 2002 and $37.0 million in 2003. Additionally, the Series F notes may
be prepaid in full or in part at a price equal to par plus, in certain
circumstances, a premium. We agreed as part of the acquisition of SFPP, L.P.'s
operations (which constitute a significant portion of our Pacific operations)
not to take actions with respect to $190 million of SFPP, L.P.'s debt that would
cause adverse tax consequences for the prior general partner of SFPP, L.P. The
Series F notes are secured by mortgages on substantially all of the properties
of SFPP, L.P. The Series F notes contain certain covenants limiting the amount
of additional debt or equity that may be issued by SFPP, L.P. and limiting the
amount of cash distributions, investments, and property dispositions by SFPP,
L.P. We do not believe that these restrictions will materially affect
distributions to our partners.

                                        52
<PAGE>

  Kinder Morgan Liquids Terminals LLC Debt

     Effective January 1, 2001, we acquired KMLT. As part of our purchase price,
we assumed debt of $87.9 million, consisting of five series of Industrial
Revenue Bonds. The Bonds consist of the following:

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

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

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

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

     - $3.6 million of 6.625% Texas Industrial Revenue Bonds due February 1,
       2024.

     In November 2001, we closed on a sale and purchase agreement with
Stolthaven Perth Amboy Inc. and Stolt-Nielsen Transportation Group, Ltd. to
acquire a liquids terminal in Perth Amboy, New Jersey. As part of our purchase
price, we assumed debt of $25.0 million, consisting of $25.0 million of Economic
Development Revenue Refunding Bonds issued by the New Jersey Economic
Development Authority. The bonds have a maturity date of January 15, 2018.
Interest on these bonds will be computed on the basis of a year of 365 or 366
days, as applicable, for the actual number of days elapsed during Commercial
Paper, Daily or Weekly Rate Periods and on the basis of a 360-day year
consisting of twelve 30-day months during a Term Rate Period. As of December 31,
2001, the interest rate was 1.391%.

     We have an outstanding letter of credit issued by Citibank in the amount of
$25.3 million that backs-up our $25 million of New Jersey Economic Development
Revenue Refunding Bonds due January 15, 2018. The letter of credit backs-up the
$25.0 million principal amount of the bonds and $0.3 million of interest on the
bonds for up to 42 days computed at 12% on a per annum basis on the principal
thereof.

  Central Florida Pipeline LLC Debt

     Effective January 1, 2001, we acquired Central Florida Pipeline LLC. As
part of our purchase price, we assumed an aggregate principal amount of $40
million of Senior Notes originally issued to a syndicate of eight insurance
companies. The Senior Notes have a fixed annual interest rate of 7.84% and will
be repaid in annual installments of $5 million beginning July 23, 2001. The
final payment is due July 23, 2008. Interest is payable semiannually on January
1 and July 23 of each year. At December 31, 2001, Central Florida's outstanding
balance under the Senior Notes was $35.0 million.

  CALNEV Pipe Line LLC Debt

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

  Senior Notes

     From time to time we issue long-term debt securities. All of our long-term
debt securities issued to date, other than those issued under our revolving
credit facilities, generally have the same terms except for interest rates,
maturity dates and prepayment restrictions. All of our outstanding debt
securities are unsecured obligations that rank equally with all of our other
senior debt obligations. Our outstanding debt securities as of December 31,
2001, consist of the following:

     - $250 million in principal amount of 6.3% senior notes due February 1,
       2009. These notes were issued on January 29, 1999 at a price to the
       public of 99.67% per note. In the offering, we received proceeds, net of
       underwriting discounts and commissions, of approximately $248 million. We
       used

                                        53
<PAGE>

       the proceeds to pay the outstanding balance on our credit facility and
       for working capital and other partnership purposes;

     - $200 million of floating rate notes due March 22, 2002 and $200 million
       of 8.0% notes due March 15, 2005. In the offering, we received proceeds,
       net of underwriting discounts and commissions of approximately $397.9
       million. We used the proceeds to reduce outstanding commercial paper. At
       December 31, 2001, the interest rate on our floating rate notes was
       3.1025%;

     - $250 million of 7.5% notes due November 1, 2010. These notes were issued
       on November 8, 2000. The proceeds from this offering, net of underwriting
       discounts, were $246.8 million. These proceeds were used to reduce our
       outstanding commercial paper; and

     - $700 million of 6.75% notes due March 15, 2011 and $300 million of 7.40%
       notes due March 15, 2031. In the offering, we received proceeds, net of
       underwriting discounts and commissions of approximately $990.0 million.
       We used the proceeds 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 fixed rate notes provide that we may redeem the notes at any time at a
price equal to 100% of the principal amount of the notes plus accrued interest
to the redemption date plus a make-whole premium. We may not prepay the floating
rate notes prior to their maturity.

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

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

  CAPITAL REQUIREMENTS FOR RECENT TRANSACTIONS

     During 2001, our cash outlays for the acquisitions of assets totaled
$1,523.5 million. We utilized our short-term credit facilities and issued
long-term debt securities to fund these acquisitions and then reduced our
short-term borrowings with the proceeds from our May 2001 issuance of i-units.
We intend to refinance the remainder of our current short-term debt and any
additional short-term debt incurred during 2002 through a combination of
long-term debt, equity and the issuance of additional commercial paper to
replace maturing commercial paper borrowings.

     GATX Domestic Pipelines and Terminals Businesses.  Effective January 1,
2001 and March 30, 2001, we acquired GATX Corporation's United States pipelines
and terminals businesses for approximately $1,231.6 million in aggregate
consideration, consisting of $975.4 million in cash, $134.8 million in assumed
debt and $121.4 million in assumed liabilities. We borrowed the necessary funds
under our commercial paper program.

     Pinney Dock & Transport LLC.  Effective March 1, 2001, we acquired Pinney
Dock & Transport LLC for approximately $52.5 million in aggregate consideration,
consisting of $41.7 million in cash and $10.8 million in assumed liabilities. We
borrowed the necessary funds under our offering of $1.0 billion in principal
amount of senior notes during the first quarter of 2001.

     Cochin Pipeline.  On June 20, 2001, we acquired an additional 2.3%
ownership interest in the Cochin Pipeline system for approximately $8.0 million
in cash. We borrowed the necessary funds under our commercial paper program.

                                        54
<PAGE>

     Vopak.  Effective July 10, 2001, we acquired certain bulk terminal
businesses, which were converted or merged into six single-member limited
liability companies, for approximately $44.3 million in aggregate consideration,
consisting of $43.6 million in cash and $0.7 million in assumed liabilities. We
borrowed the necessary funds under our commercial paper program.

     KM Texas Pipeline, L.P.  Effective July 18, 2001, we acquired KM Texas
Pipeline, L.P., a partnership that owns a natural gas pipeline system that we
previously leased, for approximately $326.1 million in aggregate consideration,
consisting of $359.1 million in cash, and a reduction of $33.0 million from the
release of a previously held deferred credit. We borrowed the necessary funds
under our commercial paper program.

     Boswell.  Effective August 31, 2001, we acquired certain bulk and liquids
terminal assets from The Boswell Oil Company for approximately $22.2 million in
aggregate consideration, consisting of $18.1 million in cash, $3.0 million from
the issuance of a short-term note payable and $1.1 million in assumed
liabilities. We borrowed the necessary funds under our commercial paper program.

     Stolt-Nielsen.  On November 8, 2001 and November 29, 2001, we acquired from
affiliates of Stolt-Nielsen, Inc. certain liquids terminal assets for totaling
approximately $69.8 million in aggregate consideration, consisting of $44.8
million in cash and $25.0 million in assumed debt. We borrowed the necessary
funds under our commercial paper program.

     Carbon Dioxide Business Interests.  In November and December 2001, we paid
approximately $14.7 million in cash for additional ownership interests in the
Snyder Gasoline Plant and the Diamond M Gas Plant, both located in the Permian
Basin of west Texas. We borrowed the necessary funds under our commercial paper
program.

NEW ACCOUNTING PRONOUNCEMENTS

     Statement of Financial Accounting Standards No. 141 supercedes Accounting
Principles Board Opinion No. 16 and requires that all transactions fitting the
description of a business combination be accounted for using the purchase method
and prohibits the use of the pooling of interests for all business combinations
initiated after June 30, 2001. The Statement also modifies the accounting for
the excess of fair value of net assets acquired as well as intangible assets
acquired in a business combination. The provisions of this statement apply to
all business combinations initiated after June 30, 2001, and all business
combinations accounted for by the purchase method that are completed after July
1, 2001. This Statement requires disclosure of the primary reasons for a
business combination and the allocation of the purchase price paid to the assets
acquired and liabilities assumed by major balance sheet caption. After July 1,
2001, we completed four acquisitions and have initiated or announced four
additional acquisitions. Refer to Note 3 to the Consolidated Financial
Statements included elsewhere in this report for more detail about our
acquisitions.

     SFAS No. 142 "Goodwill and Other Intangible Assets" supercedes Accounting
Principles Board Opinion No. 17 and requires that goodwill no longer be
amortized but should be tested, at least on an annual basis, for impairment. A
benchmark assessment of potential impairment must also be completed within six
months of adopting SFAS No. 142. After the first six months, goodwill will be
tested for impairment annually. SFAS No. 142 applies to any goodwill acquired in
a business combination completed after June 30, 2001. Other intangible assets
are to be amortized over their useful life and reviewed for impairment in
accordance with the provisions of SFAS No. 121,"Accounting for the Impairment of
Long-Lived Assets and Long-Lived Assets to be Disposed Of". An intangible asset
with an indefinite useful life can no longer be amortized until its useful life
becomes determinable. This Statement requires disclosure of information about
goodwill and other intangible assets in the years subsequent to their
acquisition that was not previously required. Required disclosures include
information about the changes in the carrying amount of goodwill from period to
period and the carrying amount of intangible assets by major intangible asset
class. After June 30, 2001, we completed two acquisitions, our Boswell and
Stolt-Nielsen acquisitions, which resulted in the recognition of goodwill. We
adopted SFAS No. 142 on January 1, 2002, and we expect that SFAS No. 142 will
not have a material impact on our business,

                                        55
<PAGE>

financial position or results of operations. With the adoption of SFAS No. 142,
goodwill of approximately $546.7 million is no longer subject to amortization
over its estimated useful life.

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

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

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 or to
make distributions 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:

     - 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. Consumer confidence,
       economic activity, political instability, weather, alternative energy
       sources, conservation and technological advances may affect price trends
       and demand;

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

     - our ability to integrate any acquired operations into our existing
       operations;

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

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

     - shut-downs or cutbacks at major refineries, petrochemical or chemical
       plants, utilities, military bases or other businesses that use or supply
       our services;

     - 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;

                                        56
<PAGE>

     - 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;

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

     - acts of sabotage and terrorism for which insurance is not available at
       reasonable premiums;

     - the condition of the capital markets and equity markets in the United
       States; and

     - 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" for a more
detailed description of these and other factors that may affect the
forward-looking statements. Our future results also could be adversely impacted
by unfavorable results of litigation and the fruition of contingencies referred
to in Note 16 to the Consolidated Financial Statements included elsewhere in
this report. When considering forward-looking statements, one should keep in
mind the risk factors described in "Risk Factors" above. The risk factors could
cause our actual results to differ materially from those contained in any
forward-looking statement. We disclaim any obligation to update the above list
or to announce publicly the result of any revisions to any of the
forward-looking statements to reflect future events or developments.

ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

ENERGY FINANCIAL INSTRUMENTS

     We use energy financial instruments to reduce our risk of price changes in
the spot and fixed price natural gas, natural gas liquids, crude oil and carbon
dioxide markets. For a complete discussion of our risk management activities,
see Note 14 to the Consolidated Financial Statements included elsewhere in this
report.

     To minimize the risks associated with changes in the market price of
natural gas and associated transportation, natural gas liquids, crude oil and
carbon dioxide, we use certain financial instruments for hedging purposes. These
instruments include energy products traded on the New York Mercantile Exchange
and over-the-counter markets including, but not limited to, futures and options
contracts, fixed-price swaps and basis swaps. We are exposed to credit-related
losses in the event of nonperformance by counterparties to these financial
instruments but, given their existing credit ratings, we do not expect any
counterparties to fail to meet their obligations. The credit ratings of the
primary parties from whom we purchase financial instruments are as follows:

<Table>
<Caption>
                                                              CREDIT RATING
                                                              -------------
<S>                                                           <C>
Sempra Energy...............................................     A
Coral Energy Holding L.P....................................    AAA
Duke Energy Trading and Marketing, LLC......................     A-
</Table>

     During the fourth quarter of 2001, we determined that Enron Corp. was no
longer likely to honor the obligations it had to us in conjunction with
derivatives we were accounting for as hedges under Statement of Financial
Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities". Upon making that determination, we:

     - ceased to account for those derivatives as hedges;

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

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

                                        57
<PAGE>

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

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

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

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

     - natural gas purchases; and

     - system use and storage.

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

     Through December 31, 2000, gains and losses on hedging positions were
deferred and recognized as cost of sales in the periods in which the underlying
physical transactions occur. On January 1, 2001, we began accounting for
derivative instruments under Statement of Financial Accounting Standards No. 133
"Accounting for Derivative Instruments and Hedging Activities" (after amendment
by SFAS 137 and SFAS 138). As discussed above, our principal use of derivative
financial instruments is to mitigate the market price risk associated with
anticipated transactions for the purchase and sale of natural gas, natural gas
liquids, crude oil and carbon dioxide. SFAS No. 133 allows these transactions to
continue to be treated as hedges for accounting purposes, although the changes
in the market value of these instruments will affect comprehensive income in the
period in which they occur and any ineffectiveness in the risk mitigation
performance of the hedge will affect net income currently. The change in the
market value of these instruments representing effective hedge operation will
continue to affect net income in the period in which the associated physical
transactions are consummated. Adoption of SFAS No. 133 has resulted in $63.8
million of deferred net gain being reported as accumulated other comprehensive
income in the accompanying balance sheet at December 31, 2001.

     We measure the risk of price changes in the natural gas, natural gas
liquids, crude oil and carbon dioxide markets utilizing a Value-at-Risk model.
Value-at-Risk is a statistical measure of how much the mark-to-market value of a
portfolio could change during a period of time, within a certain level of
statistical confidence. We utilize a closed form model to evaluate risk on a
daily basis. The Value-at-Risk computations utilize a confidence level of 97.7%
for the resultant price movement and a holding period of one day chosen for the
calculation. The confidence level used means that there is a 97.7% probability
that the mark-to-market losses for a single day will not exceed the
Value-at-Risk number presented. Financial instruments evaluated by the model
include commodity futures and options contracts, fixed price swaps, basis swaps
and over-the-counter options. During 2001, Value-at-Risk reached a high of $19.9
million and a low of $12.8 million. Value-at-Risk at December 31, 2001, was
$14.6 million and averaged $16.7 million for 2001.

     Our calculated Value-at-Risk exposure represents an estimate of the
reasonably possible net losses that would be recognized on our portfolio or
derivatives assuming hypothetical movements in future market rates, and is not
necessarily indicative of actual results that may occur. It does not represent
the maximum possible loss or any expected loss that may occur, since actual
future gains and losses will differ from those estimated. Actual gains and
losses may differ from estimates due to actual fluctuations in market rates,
operating exposures and the timing thereof, as well as changes in our portfolio
of derivatives during the year.

                                        58
<PAGE>

INTEREST RATE RISK

     The market risk inherent in our debt instruments and positions is the
potential change arising from increases or decreases in interest rates as
discussed below. Generally, our market risk sensitive instruments and positions
are characterized as "other than trading." Our exposure to market risk as
discussed below includes forward-looking statements and represents an estimate
of possible changes in fair value or future earnings that would occur assuming
hypothetical future movements in interest rates. Our views on market risk are
not necessarily indicative of actual results that may occur and do not represent
the maximum possible gains and losses that may occur, since actual gains and
losses will differ from those estimated, based on actual fluctuations in
interest rates and the timing of transactions.

     We utilize both variable rate and fixed rate debt in our financing
strategy. See Note 9 to the Consolidated Financial Statements included elsewhere
in this report for additional information related to our debt instruments. For
fixed rate debt, changes in interest rates generally affect the fair value of
the debt instrument, but not our earnings or cash flows. Conversely, for
variable rate debt, changes in interest rates generally do not impact the fair
value of the debt instrument, but may affect our future earnings and cash flows.
We do not have an obligation to prepay fixed rate debt prior to maturity and, as
a result, interest rate risk and changes in fair value should not have a
significant impact on our fixed rate debt until we would be required to
refinance such debt.

     As of December 31, 2001 and 2000, the carrying values of our long-term
fixed rate debt were approximately $1,900.6 million and $836.7 million,
respectively, compared to fair values of $2,197.9 million and $944.1 million,
respectively. Fair values were determined using quoted market prices, where
applicable, or future cash flow discounted at market rates for similar types of
borrowing arrangements. A hypothetical 10% change in the average interest rates
applicable to such debt for 2001 and 2000, respectively, would result in changes
of approximately $77.4 million and $23.6 million, respectively, in the fair
values of these instruments.

     The carrying value and fair value of our variable rate debt, including
accrued interest, was $885.4 million as of December 31, 2001 and $1,070.5
million as of December 31, 2000. Fair value was determined using future cash
flows discounted based on market rates for similar types of borrowing
arrangements. A hypothetical 10% change in the average interest rate applicable
to this debt would result in a change of approximately $5.5 million in our 2001
annualized pre-tax earnings.

     As of December 31, 2001, we were party to interest rate swap agreements
with a notional principal amount of $900 million for the purpose of hedging the
interest rate risk associated with our fixed rate debt obligations. A
hypothetical 10% change in the average interest rates related to these swaps
would not have a material effect on our annual pre-tax earnings. We monitor our
mix of fixed rate and variable rate debt obligations in light of changing market
conditions and from time to time may alter that mix by, for example, refinancing
balances outstanding under our variable rate debt with fixed rate debt (or vice
versa) or by entering into interest rate swaps or other interest rate hedging
agreements.

     As of December 31, 2001, our cash and investment portfolio did not include
fixed-income securities. Due to the short-term nature of our investment
portfolio, a hypothetical 10% increase in interest rates would not have a
material effect on the fair market value of our portfolio. Since we have the
ability to liquidate this portfolio, we do not expect our operating results or
cash flows to be materially affected to any significant degree by the effect of
a sudden change in market interest rates on our investment portfolio.

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

     The information required in this Item 8 is included in this report as set
forth in the "Index to Financial Statements" on page 74.

ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.

     None.

                                        59
<PAGE>

                                    PART III

ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.

DIRECTORS AND EXECUTIVE OFFICERS OF OUR GENERAL PARTNER AND THE DELEGATE

     Set forth below is certain information concerning the directors and
executive officers of our general partner and Kinder Morgan Management, LLC as
the delegate of our general partner. All directors of our general partner are
elected annually by, and may be removed by, Kinder Morgan (Delaware), Inc. as
its sole shareholder, and all directors of the delegate are elected annually by,
and may be removed by, our general partner as the sole holder of the delegate's
voting shares. All officers of the general partner and the delegate serve at the
discretion of the board of directors of our general partner. In addition to the
individuals named below, KMI is a director of the delegate.

<Table>
<Caption>
NAME                                AGE   POSITION WITH OUR GENERAL PARTNER AND THE DELEGATE
----                                ---   --------------------------------------------------
<S>                                 <C>   <C>
Richard D. Kinder.................  57    Director, Chairman and Chief Executive Officer
William V. Morgan.................  58    Director and Vice Chairman
Michael C. Morgan.................  33    President
Edward O. Gaylord.................  70    Director
Gary L. Hultquist.................  58    Director
Perry M. Waughtal.................  66    Director
William V. Allison................  54    President, Natural Gas Pipelines
Thomas A. Bannigan................  48    President, Products Pipelines
R. Tim Bradley....................  46    President, Kinder Morgan CO(2) Company, L.P.
David G. Dehaemers, Jr. ..........  41    Vice President, Corporate Development
Joseph Listengart.................  33    Vice President, General Counsel and Secretary
C. Park Shaper....................  33    Vice President, Treasurer and Chief Financial
                                          Officer
Thomas B. Stanley.................  51    President, Terminals
James E. Street...................  45    Vice President, Human Resources and Administration
</Table>

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

     William V. Morgan is Director and Vice Chairman of Kinder Morgan
Management, LLC, Kinder Morgan G.P., Inc. and KMI. Mr. Morgan served as the
President of Kinder Morgan Management, LLC from February 2001 to July 2001. He
served as President of KMI from October 1999 to July 2001. He served as
President of Kinder Morgan G.P., Inc. from February 1997 to July 2001. Mr.
Morgan has served as Director and Vice Chairman of Kinder Morgan Management, LLC
since its formation in February 2001. Mr. Morgan has served as Director and Vice
Chairman of KMI since October 1999. Mr. Morgan was elected Vice Chairman of
Kinder Morgan G.P., Inc. in February 1997. On January 17, 2002, we announced
that Mr. Morgan would transition to a non-executive role in April 2003. At that
time, Mr. Morgan will retain his Vice Chairman title and remain an active board
member, but he will be less involved in our day-to-day operations. Mr. Morgan is
the father of Michael C. Morgan, President of Kinder Morgan Management, LLC,
Kinder Morgan G.P., Inc. and KMI.

     Michael C. Morgan is President of Kinder Morgan Management, LLC, Kinder
Morgan G.P., Inc. and KMI. Mr. Morgan was elected to each of these positions in
July 2001. Mr. Morgan served as Vice President, Strategy and Investor Relations
of Kinder Morgan Management, LLC from February 2001 to July 2001. He served as
Vice President, Strategy and Investor Relations of KMI and Kinder Morgan G.P.,
Inc. from January 2000 to July 2001. He served as Vice President, Corporate
Development of Kinder
                                        60
<PAGE>

Morgan G.P., Inc. from February 1997 to January 2000. Mr. Morgan was the Vice
President, Corporate Development of KMI from October 1999 to January 2000. From
August 1995 until February 1997, Mr. Morgan was an associate with McKinsey &
Company, an international management consulting firm. In 1995, Mr. Morgan
received a Masters in Business Administration from the Harvard Business School.
From March 1991 to June 1993, Mr. Morgan held various positions, including
Assistant to the Chairman, at PSI Energy, Inc. Mr. Morgan received a Bachelor of
Arts in Economics and a Masters of Arts in Sociology from Stanford University in
1990. Mr. Morgan is the son of William V. Morgan.

     Edward O. Gaylord is a Director of Kinder Morgan Management, LLC and Kinder
Morgan G.P., Inc. Mr. Gaylord was elected Director of Kinder Morgan Management,
LLC upon its formation in February 2001. Mr. Gaylord was elected Director of
Kinder Morgan G.P., Inc. in February 1997. Since 1989, Mr. Gaylord has been the
Chairman of the Board of Directors of Jacintoport Terminal Company, a liquid
bulk storage terminal on the Houston, Texas ship channel. Mr. Gaylord serves on
the Board of Directors of Seneca Foods Corporation and is Chairman of the Board
of Directors of the Houston Branch of the Federal Reserve Bank of Dallas.

     Gary L. Hultquist is a Director of Kinder Morgan Management, LLC and Kinder
Morgan G.P., Inc. Mr. Hultquist was elected Director of Kinder Morgan
Management, LLC upon its formation in February 2001. He was elected Director of
Kinder Morgan G.P., Inc. in October 1999. Since 1995, Mr. Hultquist has been the
Managing Director of Hultquist Capital, LLC, a San Francisco-based strategic and
merger advisory firm. Mr. Hultquist is a member of the Board of Directors of
netMercury, Inc., a supplier of automated supply chain services, critical spare
parts and consumables used in semiconductor manufacturing. Previously, Mr.
Hultquist practiced law in two San Francisco area firms for over 15 years,
specializing in business, intellectual property, securities and venture capital
litigation.

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

     William V. Allison is President, Natural Gas Pipelines of Kinder Morgan
Management, LLC, Kinder Morgan G.P., Inc. and KMI. Mr. Allison was elected
President, Natural Gas Pipelines of Kinder Morgan Management, LLC upon its
formation in February 2001. He was elected President, Natural Gas Pipelines of
Kinder Morgan G.P., Inc. and of KMI in September 1999. He was President,
Pipeline Operations of Kinder Morgan G.P., Inc. from February 1999 to September
1999. Mr. Allison served as Vice President and General Counsel of Kinder Morgan
G.P., Inc. from April 1998 to February 1999. From May 1997 to April 1998, Mr.
Allison managed his personal investments. From April 1996 through May 1997, Mr.
Allison served as President of Enron Liquid Services Corporation. On February 8,
2002, we announced that Mr. Allison will retire effective June 1, 2002.

     Thomas A. Bannigan is President, Product Pipelines of Kinder Morgan
Management, LLC and Kinder Morgan G.P., Inc. and President and Chief Executive
Officer of Plantation Pipe Line Company. Mr. Bannigan was elected President,
Product Pipelines of Kinder Morgan Management, LLC upon its formation in
February 2001. He was elected President, Products Pipelines of Kinder Morgan
G.P., Inc. in October 1999. Mr. Bannigan has served as President and Chief
Executive Officer of Plantation Pipe Line Company since May 1998. From 1985 to
May 1998, Mr. Bannigan was Vice President, General Counsel and Secretary of
Plantation Pipe Line Company.

     R. Tim Bradley is President, CO(2) Pipelines of Kinder Morgan Management,
LLC and of Kinder Morgan G.P., Inc. and President of Kinder Morgan CO(2)
Company, L.P. Mr. Bradley was elected President, CO(2) Pipelines of Kinder
Morgan Management, LLC and Vice President (President, CO(2) Pipelines) of Kinder
Morgan G.P., Inc. in April 2001. Mr. Bradley has been President of Kinder Morgan
                                        61
<PAGE>

CO(2) Company, L.P. (which name changed from Shell CO(2) Company, Ltd. in April
2000) since March 1998. From May 1996 to March 1998, Mr. Bradley was Manager of
CO(2) Marketing for Shell Western E&P, Inc. Mr. Bradley received a Bachelor of
Science in Petroleum Engineering from the University of Missouri at Rolla.

     David G. Dehaemers, Jr. is Vice President, Corporate Development of Kinder
Morgan Management, LLC, Kinder Morgan G.P., Inc. and KMI. Mr. Dehaemers was
elected Vice President, Corporate Development of Kinder Morgan Management, LLC
upon its formation in February 2001. Mr. Dehaemers was elected Vice President,
Corporate Development of Kinder Morgan G.P., Inc. and Vice President, Corporate
Development of KMI in January 2000. He served as Vice President and Chief
Financial Officer of KMI from October 1999 to January 2000. He served as Vice
President and Chief Financial Officer of Kinder Morgan G.P., Inc. from July 1997
to January 2000 and Treasurer of Kinder Morgan G.P., Inc. from February 1997 to
January 2000. He served as Secretary of Kinder Morgan G.P., Inc. from February
1997 to August 1997. Mr. Dehaemers was previously employed by the national CPA
firms of Ernst & Whinney and Arthur Young. Mr. Dehaemers received his law degree
from the University of Missouri-Kansas City and is a member of the Missouri Bar.
He is also a CPA and received his undergraduate Accounting degree from Creighton
University in Omaha, Nebraska.

     Joseph Listengart is Vice President, General Counsel and Secretary of
Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and KMI. Mr. Listengart
was elected Vice President, General Counsel and Secretary of Kinder Morgan
Management, LLC upon its formation in February 2001. He was elected Vice
President and General Counsel of Kinder Morgan G.P., Inc. and Vice President,
General Counsel and Secretary of KMI in October 1999. Mr. Listengart was elected
Kinder Morgan G.P., Inc.'s Secretary in November 1998 and became an employee of
Kinder Morgan G.P., Inc. in March 1998. From March 1995 through February 1998,
Mr. Listengart worked as an attorney for Hutchins, Wheeler & Dittmar, a
Professional Corporation. Mr. Listengart received his Masters in Business
Administration from Boston University in January 1995, his Juris Doctor, magna
cum laude, from Boston University in May 1994, and his Bachelor of Arts degree
in Economics from Stanford University in June 1990.

     C. Park Shaper is Vice President, Treasurer and Chief Financial Officer of
Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and KMI. Mr. Shaper was
elected Vice President, Treasurer and Chief Financial Officer of Kinder Morgan
Management, LLC upon its formation in February 2001. He has served as Treasurer
of KMI since April 2000 and Vice President and Chief Financial Officer of KMI
since January 2000. Mr. Shaper was elected Vice President, Treasurer and Chief
Financial Officer of Kinder Morgan G.P., Inc. in January 2000. From June 1999 to
December 1999, Mr. Shaper was President and Director of Altair Corporation, an
enterprise focused on the distribution of web-based investment research for the
financial services industry. He served as Vice President and Chief Financial
Officer of First Data Analytics, a wholly-owned subsidiary of First Data
Corporation, from 1997 to June 1999. From 1995 to 1997, he was a consultant with
The Boston Consulting Group. He received a Masters in Business Administration
degree from the J.L. Kellogg Graduate School of Management at Northwestern
University. Mr. Shaper also has a Bachelor of Science degree in Industrial
Engineering and a Bachelor of Arts degree in Quantitative Economics from
Stanford University.

     Thomas B. Stanley is President, Terminals of Kinder Morgan Management, LLC
and Kinder Morgan G.P., Inc. Mr. Stanley became President of our Terminals
segment in July 2001 when we combined our previously separate Bulk Terminals and
Liquids Terminals segments. Prior to that, Mr. Stanley served as President, Bulk
Terminals of Kinder Morgan G.P., Inc. since August 1998 and of Kinder Morgan
Management, LLC since February 2001. From 1993 to July 1998, he was President of
Hall-Buck Marine, Inc. (now known as Kinder Morgan Bulk Terminals, Inc.), for
which he has worked since 1980. Mr. Stanley is a CPA with ten years' experience
in public accounting, banking, and insurance accounting prior to joining
Hall-Buck. He received his bachelor's degree from Louisiana State University in
1972.

     James E. Street is Vice President, Human Resources and Administration of
Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and KMI. Mr. Street was
elected Vice President, Human Resources and Administration of Kinder Morgan
Management, LLC upon its formation in February 2001.

                                        62
<PAGE>

He was elected Vice President, Human Resources and Administration of Kinder
Morgan G.P., Inc. and KMI in August 1999. From October 1996 to August 1999, Mr.
Street was Senior Vice President, Human Resources and Administration for Coral
Energy, a subsidiary of Shell Oil Company. Mr. Street received a Masters of
Business Administration degree from the University of Nebraska at Omaha and a
Bachelor of Science degree from the University of Nebraska at Kearney.

ITEM 11.  EXECUTIVE COMPENSATION.

     As is commonly the case for publicly traded limited partnerships, we have
no officers. Under our limited partnership agreement, Kinder Morgan G.P., Inc.,
as the general partner of the partnership, is to direct, control and manage all
of our activities. Pursuant to a delegation of control agreement, Kinder Morgan
G.P., Inc. has delegated to Kinder Morgan Management, the management and control
of our business and affairs to the maximum extent permitted by the partnership
agreement and Delaware law, subject to the general partner's right to approve
certain actions by Kinder Morgan Management. The executive officers and
directors of Kinder Morgan G.P., Inc. serve in the same capacities for Kinder
Morgan Management. Certain of those executive officers, including all of the
named officers below, also serve as executive officers of KMI. All information
in this report with respect to compensation of executive officers describes the
total compensation received by those persons in all capacities for Kinder Morgan
G.P., Inc., Kinder Morgan Management, KMI and their respective affiliates.

                           SUMMARY COMPENSATION TABLE

<Table>
<Caption>
                                                                         LONG-TERM
                                                                    COMPENSATION AWARDS
                                                                  -----------------------
                                                                                 UNITS/
                                        ANNUAL COMPENSATION       RESTRICTED   KMI SHARES
                                     --------------------------     STOCK      UNDERLYING      ALL OTHER
NAME AND PRINCIPAL POSITION          YEAR    SALARY    BONUS(3)   AWARDS(4)     OPTIONS     COMPENSATION(7)
---------------------------          ----   --------   --------   ----------   ----------   ---------------
<S>                                  <C>    <C>        <C>        <C>          <C>          <C>
Richard D. Kinder(1)...............  2001   $      1   $     --    $     --           --        $    --
  Director, Chairman and CEO         2000          1         --          --           --             --
                                     1999    150,003         --          --           --          7,554
Michael C. Morgan..................  2001    200,000    350,000     569,900           --          7,835
  President                          2000    200,000    300,000(5)   498,750   0/150,000(6)      10,836
                                     1999    161,249    250,000(5)        --   0/250,000          7,408
David G. Dehaemers, Jr. ...........  2001    200,000    350,000     569,900           --          7,570
  Vice President,                    2000    200,000    300,000(5)   498,750   0/150,000(6)      10,920
  Corporate Development              1999    161,249    250,000(5)        --   0/250,000          7,408
William V. Allison.................  2001    200,000    350,000     569,900           --          7,816
  President,                         2000    200,000    300,000     498,750           --         11,466
  Gas Pipeline Group                 1999    192,497    250,000          --    0/250,000          9,335
Joseph Listengart..................  2001    200,000    350,000     569,900           --          7,186
  Vice President,                    2000    181,250    225,000     498,750      0/6,300(8)      10,798
  General Counsel and Secretary      1999    124,336    175,000          --    0/175,000          5,890
C. Park Shaper(2)..................  2001    200,000    350,000     569,900           --          7,186
  Vice President,                    2000    175,000         --     498,750    0/150,000(9)      10,836
  Treasurer and CFO                  1999         --         --          --           --             --
</Table>

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

(1) Effective October 1, 1999, Mr. Kinder's annual salary was reduced to $1.00.
    Mr. Kinder is not eligible for annual bonuses or option grants.

(2) Mr. Shaper commenced employment with our general partner in January 2000.

(3) Amounts earned in year shown and paid the following year.

(4) Represent shares of restricted KMI stock awarded in 2002 and 2001 that
    relate to performance in 2001 and 2000, respectively. Value computed as the
    number of shares awarded (10,000) times the closing price on date of grant
    ($56.99 at January 16, 2002 and $49.875 at January 17, 2001). Twenty-

                                        63
<PAGE>

    five percent of the shares in each grant vest on each of the first four
    anniversaries after the date of grant. The holders of the restricted stock
    awards are eligible to vote and to receive dividends declared on such
    shares.

(5) Does not include for 1999, $3,753,868, or for 2000, $7,010,000 paid to
    Messrs. Dehaemers and Morgan under our Executive Compensation Plan. The
    payments made in 2000 were the last payments Messrs. Dehaemers and Morgan
    are to receive under our Executive Compensation Plan. We do not intend to
    compensate any employees providing services to us under the Executive
    Compensation Plan on a going forward basis. See "-- Executive Compensation
    Plan."

(6) The 150,000 options in KMI shares were granted and became fully vested on
    April 20, 2000. The options were granted to Messrs. Dehaemers and Morgan in
    connection with the execution of their employment agreements. See
    "-- Employment agreements."

(7) For 1999 and 2000, amounts represent our general partner's contributions to
    the Retirement Savings Plan (a 401(k) plan), the imputed value of general
    partner-paid group term life insurance exceeding $50,000, and compensation
    attributable to taxable moving and parking expenses allowed. For 2001,
    amounts represent contributions to Retirement Savings Plan, value of
    group-term life insurance exceeding $50,000, parking compensation and a $50
    cash payment.

(8) The 6,300 options in KMI shares were granted in 2001, but relate to
    performance in 2000. The options were granted and became fully exercisable
    on January 17, 2001 at a grant price of $49.875 per share.

(9) The year 2000 options in KMI shares include 25,000 options granted in 2001,
    but relating to performance in 2000. These options were granted and became
    fully exercisable on January 17, 2001 at a grant price of $49.875 per share.
    The remaining 125,000 options were granted on January 20, 2000 at a grant
    price of $24.75. These options vest at twenty five percent on each of the
    first four anniversaries after the date of grant.

     Executive Compensation Plan.  Pursuant to our Executive Compensation Plan,
executive officers of our general partner are eligible for awards equal to a
percentage of the "incentive compensation value", which is defined as cash
distributions to our general partner during the four calendar quarters preceding
the date of redemption multiplied times eight (less a participant adjustment
factor, if any). Under the plan, no eligible employee may receive a grant in
excess of 2 percent and total awards under the plan may not exceed 10 percent.
In general, participants may redeem vested awards in whole or in part from time
to time by written notice. We may, at our option, pay the participant in units
(provided, however, the unitholders approve the plan prior to issuing such
units) or in cash. We may not issue more than 400,000 units in the aggregate
under the plan. Units will not be issued to a participant unless such units have
been listed for trading on the principal securities exchange on which the units
are then listed. The plan terminates January 1, 2007 and any unredeemed awards
will be automatically redeemed. However, the plan may be terminated before such
date, and upon such early termination, we will redeem all unpaid grants of
compensation at an amount equal to the highest incentive compensation value,
using as the determination date any day within the previous twelve months,
multiplied by 1.5. The plan was established in July 1997 and on July 1, 1997,
the board of directors of our general partner granted awards totaling 2 percent
of the incentive compensation value to each of David Dehaemers and Michael
Morgan. Originally, 50 percent of such awards were to vest on each of January 1,
2000 and January 1, 2002. No awards were granted during 1998 and 1999.

     On January 4, 1999, the awards granted to Mr. Dehaemers and Mr. Morgan were
amended to provide for the immediate vesting and pay-out of 50 percent of their
awards, or 1 percent of the incentive compensation value. On April 28, 2000, the
awards granted to Mr. Dehaemers and Mr. Morgan were amended to provide for the
immediate vesting and pay-out of the remaining 50 percent of their awards, or 1
percent of the incentive compensation value. The board of directors of our
general partner believes that accelerating the vesting and pay-out of the awards
was in our best interest because it capped the total payment the participants
were entitled to receive with respect to their awards.

                                        64
<PAGE>

     Retirement Savings Plan.  Effective July 1, 1997, our general partner
established the Kinder Morgan Retirement Savings Plan, a defined contribution
401(k) plan. This plan was subsequently amended and merged to form the Kinder
Morgan Savings Plan. The plan now permits all full-time employees of Kinder
Morgan, Inc. and Kinder Morgan Services LLC to contribute 1 percent to 50
percent of base compensation, on a pre-tax basis, into participant accounts. In
addition to a mandatory contribution equal to 4 percent of base compensation per
year for most plan participants, our general partner may make discretionary
contributions in years when specific performance objectives are met. Certain
employees' contributions are based on collective bargaining agreements. The
mandatory contributions are made each pay period on behalf of each eligible
employee. Any discretionary contributions are made during the first quarter
following the performance year. All contributions, including discretionary
contributions, are in the form of KMI stock that is immediately convertible into
other available investment vehicles at the employee's discretion. In the first
quarter of 2002, no discretionary contributions were made to individual accounts
for 2001. All contributions, together with earnings thereon, are immediately
vested and not subject to forfeiture. Participants may direct the investment of
their contributions into a variety of investments. Plan assets are held and
distributed pursuant to a trust agreement. Because levels of future
compensation, participant contributions and investment yields cannot be reliably
predicted over the span of time contemplated by a plan of this nature, it is
impractical to estimate the annual benefits payable at retirement to the
individuals listed in the Summary Compensation Table above.

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

     No individual employee may be granted options for more than 20,000 common
units in any year. Our board of directors or the committee referred to in the
prior paragraph will determine the duration and vesting of the options to
employees at the time of grant. As of December 31, 2001, outstanding options for
379,400 common units were granted to 106 employees of Kinder Morgan, Inc. and
Kinder Morgan Services LLC. Forty percent of such options will vest on the first
anniversary of the date of grant and twenty percent on each anniversary,
thereafter. The options expire seven years from the date of grant.

     The option plan also granted to each of our non-employee directors as of
April 1, 1998, an option to acquire 10,000 common units at an exercise price
equal to the fair market value of the common units on such date. In addition,
each new non-employee director will receive options to acquire 10,000 common
units on the first day of the month following his or her election. Under this
provision, as of December 31, 2001, outstanding options for 30,000 common units
had been granted to Kinder Morgan G.P., Inc.'s three non-employee directors.
Forty percent of such options will vest on the first anniversary of the date of
grant and twenty percent on each anniversary, thereafter. The non-employee
director options will expire seven years from the date of grant.

     No common unit options were granted during 2001 to any of the individuals
named in the Summary compensation table above. The following table sets forth
certain information at December 31, 2001 with respect to common unit options
previously granted to the individuals named in the Summary Compensation Table
above. Mr. Allison and Mr. Listengart were the only persons named in the Summary
Compensation Table that were granted common unit options. No common unit options
were granted at an option price below fair market value on the date of grant.

                                        65
<PAGE>

 AGGREGATED COMMON UNIT OPTION EXERCISES IN 2001, AND 2001 YEAR-END COMMON UNIT
                                 OPTION VALUES

<Table>
<Caption>
                                                            NUMBER OF UNITS            VALUE OF UNEXERCISED
                                                        UNDERLYING UNEXERCISED         IN-THE-MONEY OPTIONS
                                                       OPTIONS AT 2001 YEAR END         AT 2001 YEAR-END(1)
                          UNITS ACQUIRED    VALUE     ---------------------------   ---------------------------
NAME                       ON EXERCISE     REALIZED   EXERCISABLE   UNEXERCISABLE   EXERCISABLE   UNEXERCISABLE
----                      --------------   --------   -----------   -------------   -----------   -------------
<S>                       <C>              <C>        <C>           <C>             <C>           <C>
William V. Allison......         --            --       16,000          4,000        $340,120        $85,030
Joseph Listengart.......         --            --        8,000          2,000        $164,310        $41,078
</Table>

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

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

     KMI Option Plan.  Under KMI's stock option plans, employees of KMI and its
affiliates, including employees of Kinder Morgan, Inc. and its direct and
indirect subsidiaries, are eligible to receive grants of options to acquire
shares of common stock of KMI. KMI's board of directors administers this option
plan. The primary purpose for granting stock options under this plan to
employees of our general partner and our subsidiaries is to provide them with an
incentive to increase the value of common stock of KMI. A secondary purpose of
the grants is to provide compensation to those employees for services rendered
to our subsidiaries and us.

     The following tables set forth certain information at December 31, 2001 and
for the fiscal year then ended with respect to KMI stock options granted to the
individuals named in the Summary Compensation Table above. Mr. Listengart and
Mr. Shaper are the only persons named in the Summary Compensation Table that
were granted KMI stock options during 2001. None of these KMI stock options were
granted with an exercise price below the fair market value of the common stock
on the date of grant. The options were granted and became fully exercisable on
January 17, 2001, but relate to performance in 2000. The options expire 10 years
after the date of grant.

                        KMI STOCK OPTION GRANTS IN 2001

<Table>
<Caption>
                                                                               POTENTIAL REALIZABLE VALUE
                            NUMBER OF    % OF TOTAL                              AT ASSUMED ANNUAL RATES
                            SECURITIES    OPTIONS                              OF STOCK PRICE APPRECIATION
                            UNDERLYING   GRANTED TO   EXERCISE                     FOR OPTION TERM(1)
                             OPTIONS     EMPLOYEES      PRICE     EXPIRATION   ---------------------------
NAME                         GRANTED      IN 2001     PER SHARE      DATE          5%             10%
----                        ----------   ----------   ---------   ----------   -----------   -------------
<S>                         <C>          <C>          <C>         <C>          <C>           <C>
Joseph Listengart.........     6,300       0.28%       $49.875    01/17/2011    $197,600      $  500,756
C. Park Shaper............    25,000       1.14%       $49.875    01/17/2011    $784,125      $1,987,125
</Table>

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

(1) The dollar amounts under these columns use the 5% and 10% rates of
    appreciation prescribed by the Securities and Exchange Commission. The 5%
    and 10% rates of appreciation would result in per share prices of $81.24 and
    $129.36, respectively. We express no opinion regarding whether this level of
    appreciation will be realized and expressly disclaim any representation to
    that effect.

                                        66
<PAGE>

AGGREGATED KMI STOCK OPTION EXERCISES IN 2001 AND 2001 YEAR-END KMI STOCK OPTION
                                     VALUES

<Table>
<Caption>
                                                             NUMBER OF SHARES            VALUE OF UNEXERCISED
                                                          UNDERLYING UNEXERCISED         IN-THE-MONEY OPTIONS
                                                         OPTIONS AT 2001 YEAR END         AT 2001 YEAR-END(1)
                         SHARES ACQUIRED     VALUE      ---------------------------   ---------------------------
NAME                       ON EXERCISE      REALIZED    EXERCISABLE   UNEXERCISABLE   EXERCISABLE   UNEXERCISABLE
----                     ---------------   ----------   -----------   -------------   -----------   -------------
<S>                      <C>               <C>          <C>           <C>             <C>           <C>
Michael C. Morgan......      62,500        $2,107,013     212,500        125,000      $5,377,250     $3,985,000
David G. Dehaemers,
  Jr. .................      62,500        $2,012,994     212,500        125,000      $5,377,250     $3,985,000
William V. Allison.....      75,000        $2,291,020     175,000             --      $5,579,000     $       --
Joseph Listengart......      48,750        $1,416,511      45,050         87,500      $1,271,985     $2,789,500
C. Park Shaper.........          --                --      56,250         93,750      $1,112,250     $2,900,625
</Table>

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

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

     Cash Balance Retirement Plan.  Employees of our general partner and our
subsidiaries are eligible to participate in a new Cash Balance Retirement Plan
that was put into effect on January 1, 2001. Certain employees continue to
accrue benefits through a career-pay formula, "grandfathered" according to age
and years of service on December 31, 2000, or collective bargaining
arrangements. All other employees will accrue benefits through a personal
retirement account in the new Cash Balance Retirement Plan. Employees with prior
service and not grandfathered converted to the Cash Balance Retirement Plan and
were credited with the current fair value of any benefits they had previously
accrued through the defined benefit plan. Under the plan, we make contributions
on behalf of participating employees equal to 3% of eligible compensation every
pay period. In addition, we may make discretionary contributions to the plan
based on our performance. In the first quarter of 2002, an additional 1%
discretionary contribution was made to individual accounts based on achieving
2001 financial targets to unitholders. Interest will be credited to the personal
retirement accounts at the 30-year U.S. Treasury bond rate in effect each year.
Employees will be fully vested in the plan after five years, and they may take a
lump sum distribution upon termination of employment or retirement.

     Compensation Committee Interlocks and Insider Participation.  We do not
have a separate compensation committee. Kinder Morgan Management's compensation
committee, comprised of Mr. Edward O. Gaylord, Mr. Gary L. Hultquist and Mr.
Perry M. Waughtal, makes compensation decisions regarding our executive
officers. Mr. Richard D. Kinder and Mr. William V. Morgan, who are executive
officers of Kinder Morgan Management, participate in the deliberations of the
board of directors of Kinder Morgan Management concerning executive officer
compensation. Messrs. Kinder and Morgan each receive $1.00 annually in total
salary compensation for services to KMI and us.

     Directors fees.  During 2001, each of the three non-employee members of the
board of directors of Kinder Morgan Management was paid $10,000 for each quarter
in 2001 in which they served on the board of directors. Each will receive
$10,000 for each quarter in 2002 in which they serve. Directors are reimbursed
for reasonable expenses in connection with board meetings.

     Employment agreements.  In April 2000, Mr. David G. Dehaemers, Jr. and Mr.
Michael C. Morgan entered into four-year employment agreements with KMI and our
general partner. Under the employment agreements, each of Mr. David G.
Dehaemers, Jr. and Mr. Michael C. Morgan receives an annual base salary of
$200,000 and bonuses at the discretion of the compensation committee of our
general partner. In connection with the execution of the employment agreements,
Messrs. Dehaemers and Morgan no longer participate under our Executive
Compensation Plan. In addition, each are prevented from competing with KMI and
us for a period of four years from the date of the agreements, provided Mr.
Richard D. Kinder or Mr. William V. Morgan continues to serve as chief executive
officer of KMI or its successor.

     Retention Agreement.  Effective January 17, 2002, KMI entered into a
retention agreement with C. Park Shaper, an officer of KMI, our general partner
and its delegate. Pursuant to the terms of the agreement, Mr. Shaper received a
$5 million personal loan guaranteed by us. Mr. Shaper was required to

                                        67
<PAGE>

purchase KMI common shares and our common units in the open market with the loan
proceeds. If he voluntarily leaves us prior to the end of five years, then he
must repay the entire loan. On the fifth anniversary date of the agreement,
provided Mr. Shaper has continued to be employed by our general partner, we and
KMI will assume Mr. Shaper's obligations under the loan. The agreement contains
provisions that address termination for cause, death, disability and change of
control.

     Lines of Credit. Kinder Morgan Energy Partners, L.P. has agreed to
guarantee potential borrowings under lines of credit available from First Union
National Bank to Messrs. M. Morgan, Dehaemers, Listengart and Shaper. Each of
these officers is primarily liable for any borrowing on his line of credit, and
if Kinder Morgan Energy Partners, L.P. makes any payment with respect to an
outstanding loan, the officer on behalf of whom payment is made must surrender a
percentage of his Kinder Morgan, Inc. stock options. To date, Kinder Morgan
Energy Partners, L.P. has made no payment with respect to these lines of credit.

ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.

     The following table sets forth information as of January 31, 2002,
regarding (a) the beneficial ownership of (i) our units, (ii) the common stock
of KMI, the parent company of our general partner, and (iii) Kinder Morgan
Management shares by all directors of our general partner and its delegate, each
of the named executive officers and all directors and executive officers as a
group and (b) the beneficial ownership of our common units by all persons known
by our general partner to own beneficially more than 5% of our units or shares
of Kinder Morgan Management. Unless otherwise noted, the address of each person
below is c/o Kinder Morgan Energy Partners, L.P., 500 Dallas Street, Suite 1000,
Houston, Texas 77002. All references to the number of our common units and to
the number of Kinder Morgan Management shares have been restated to reflect the
effect of the two-for-one splits of our outstanding common units and Kinder
Morgan Management shares that occurred on August 31, 2001.

                  AMOUNT AND NATURE OF BENEFICIAL OWNERSHIP(1)

<Table>
<Caption>
                                                                                     KINDER MORGAN
                                   COMMON UNITS            CLASS B UNITS           MANAGEMENT SHARES         KMI VOTING STOCK
                              ----------------------   ----------------------   -----------------------   -----------------------
                                NUMBER      PERCENT      NUMBER      PERCENT       NUMBER      PERCENT       NUMBER      PERCENT
                              OF UNITS(2)   OF CLASS   OF UNITS(3)   OF CLASS   OF SHARES(4)   OF CLASS   OF SHARES(5)   OF CLASS
                              -----------   --------   -----------   --------   ------------   --------   ------------   --------
<S>                           <C>           <C>        <C>           <C>        <C>            <C>        <C>            <C>
Richard D. Kinder(6)........     305,200         *             --         --        25,595          *      23,995,092     19.41%
William V. Morgan(7)........       4,000         *             --         --            --         --       4,500,000      3.64%
Michael C. Morgan(8)........       6,000         *             --         --         3,057          *         242,500         *
Edward O. Gaylord(9)........      38,000         *             --         --            --         --              --        --
Gary L. Hultquist(10).......       9,000         *             --         --            --         --             500        --
Perry M. Waughtal(11).......      21,300         *             --         --        20,595          *          10,000         *
William V. Allison(12)......      16,000         *             --         --            --         --          20,000         *
David G. Dehaemers,
  Jr.(13)...................      17,000         *             --         --            --         --         232,500         *
Joseph Listengart(14).......      12,698         *             --         --            --         --          65,050         *
C. Park Shaper(15)..........      85,000         *             --         --         2,057          *         145,500         *
Directors and Executive
  Officers as a group (14
  persons)(16)..............     657,330         *             --         --        53,846          *      29,454,140     23.68%
Kinder Morgan, Inc.(17).....  19,726,026     15.19%     5,313,400     100.00%    6,014,546      19.63%             --        --
Fayez Sarofim(18)...........   6,993,697      5.39%            --         --            --         --              --        --
Goldman, Sachs & Co.(19)....   7,402,780      5.70%            --         --            --         --              --        --
Capital Group International,
  Inc.(20)..................          --        --             --         --     3,261,210      10.64%             --        --
FMR Corp.(21)...............          --        --             --         --     3,204,988      10.46%             --        --
Massachusetts Financial
  Services Company(22)......          --        --             --         --     1,597,781       5.22%             --        --
</Table>

                                        68
<PAGE>

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

  *  Less than 1%.

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

 (2) As of January 31, 2002, we had 129,862,418 common units issued and
     outstanding.

 (3) As of January 31, 2002, we had 5,313,400 Class B units issued and
     outstanding.

 (4) Represent the limited liability company shares of Kinder Morgan Management.
     As of January 31, 2002, there were 30,636,363 issued and outstanding Kinder
     Morgan Management shares. In all cases, our i-units will be voted in
     proportion to the affirmative and negative votes, abstentions and non-
     votes of owners of Kinder Morgan Management shares. Through the provisions
     in our partnership agreement and Kinder Morgan Management's limited
     liability company agreement, the number of outstanding Kinder Morgan
     Management shares, including voting shares owned by our general partner,
     and the number of our i-units will at all times be equal. Furthermore,
     Kinder Morgan Management shareholders have the option to exchange any or
     all of their shares for common units owned by KMI, directly or indirectly
     through its subsidiaries, at an exchange rate of one common unit per one
     share. At any time, instead of delivering a common unit, KMI may elect to
     make a cash payment in respect of any share surrendered for exchange by
     giving notice of the election to the tendering holder not more that three
     trading days after such share is surrendered for exchange. The numbers of
     our common units reported in the table do not include any common units
     which might be received upon surrender of the Kinder Morgan Management
     shares reflected in the table.

 (5) As of January 31, 2002, KMI had a total of 123,622,415 shares of
     outstanding voting common stock.

 (6) Includes (a) 7,100 common units owned by Mr. Kinder's spouse and (b) 5,100
     KMI shares held by Mr. Kinder's spouse. Mr. Kinder disclaims any and all
     beneficial or pecuniary interest in these units and shares.

 (7) Porticullis Partners, LP, a Texas limited partnership beneficially owned by
     Mr. Morgan and his wife Sara S. Morgan, holds the KMI shares. Mr. Morgan
     may be deemed to own the 4,500,000 KMI shares and thereby shares in the
     voting and disposition power with Porticullis Partners, LP. Includes
     1,000,000 KMI shares with respect to which Porticullis Partners, LP wrote a
     costless collar that expires in August 2003.

 (8) Includes options to purchase 212,500 KMI shares exercisable within 60 days
     of January 31, 2002, and includes 17,520 shares of restricted KMI stock.

 (9) Includes options to purchase 8,000 common units exercisable within 60 days
     of January 31, 2002.

(10) Includes options to purchase 6,000 common units exercisable within 60 days
     of January 31, 2002.

(11) Includes options to purchase 4,000 common units exercisable within 60 days
     of January 31, 2002.

(12) Includes options to purchase 16,000 common units and includes 17,500 shares
     of restricted KMI stock.

(13) Includes options to purchase 212,500 KMI shares exercisable within 60 days
     of January 31, 2002, and includes 17,520 shares of restricted KMI stock.

(14) Includes options to purchase 10,000 common units and 45,050 KMI shares
     exercisable within 60 days of January 31, 2002, and includes 17,520 shares
     of restricted KMI stock.

(15) Includes options to purchase 87,500 KMI shares exercisable within 60 days
     of January 31, 2002, and includes 17,520 shares of restricted KMI stock.

(16) Includes options to purchase 60,000 common units and 756,050 KMI shares
     exercisable within 60 days of January 31, 2002, and includes 122,500 shares
     of restricted KMI stock.

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

(18) As reported on the Schedule 13G filed February 15, 2002 by Fayez Sarofim &
     Co. and Fayez Sarofim. Mr. Sarofim reports that he has sole voting power
     over 2,000,000 common units, shared voting power over 4,107,830 common
     units, sole disposition power over 2,000,000 common units and

                                        69
<PAGE>

     shared disposition power over 4,993,697 common units. Mr. Sarofim's address
     is 2907 Two Houston Center, Houston, Texas 77010.

(19) As reported on the Schedule 13G/A filed February 14, 2002 by Goldman, Sachs
     & Co. and The Goldman Sachs Group, Inc. Goldman Sachs & Co. and The Goldman
     Sachs Group, Inc. report that each has sole voting power over 0 common
     units, shared voting power over 7,402,780 common units, sole disposition
     power over 0 common units and shared disposition power over 7,402,780
     common units. The address of Goldman Sachs & Co. and The Goldman Sachs
     Group, Inc. is 10 Hanover Square, New York, New York 10005.

(20) As reported on the Schedule 13G/A filed February 11, 2002 by Capital Group
     International, Inc. and Capital Guardian Trust Company. Capital Group
     International, Inc. and Capital Guardian Trust Company report that in
     regard to Kinder Morgan Management shares, each has sole voting power over
     2,515,030 shares, shared voting power over 0 shares, sole disposition power
     over 3,261,210 shares and shared disposition power over 0 shares. Capital
     Group International, Inc. and Capital Guardian Trust Company disclaim
     beneficial ownership of the shares but may be deemed to be the beneficial
     owners of the shares. Capital Group International, Inc.'s and Capital
     Guardian Trust Company's address is 11100 Santa Monica Blvd., Los Angeles,
     California 90025.

(21) As reported on the Schedule 13G/A filed February 14, 2002 by FMR Corp. FMR
     Corp. reports that in regard to Kinder Morgan Management shares, it has
     sole voting power over 154,146 shares, shared voting power over 0 shares,
     sole disposition power over 3,204,988 shares and shared disposition power
     over 0 shares. FMR Corp.'s address is 82 Devonshire Street, Boston,
     Massachusetts 02109.

(22) As reported on the Schedule 13G filed February 12, 2002 by Massachusetts
     Financial Services Company. Massachusetts Financial Services Company
     reports that in regard to Kinder Morgan Management shares, it has sole
     voting power over 1,597,781 shares, shared voting power over 0 shares, sole
     disposition power over 1,597,781 shares and shared disposition power over 0
     shares. Massachusetts Financial Services Company's address is 500 Boylston
     Street, Boston, Massachusetts 02116.

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.

     See Note 12 of the Notes to the Consolidated Financial Statements included
elsewhere in this report.

                                        70
<PAGE>

                                    PART IV

ITEM 14.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.

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

     FINANCIAL STATEMENTS -- See "Index to Financial Statements" set forth on
page 74.

     FINANCIAL STATEMENT SCHEDULES

              KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

               SCHEDULE II. -- VALUATION AND QUALIFYING ACCOUNTS
                                 (IN THOUSANDS)

<Table>
<Caption>
                                                        YEAR ENDED DECEMBER 31, 2001
                              --------------------------------------------------------------------------------
                               BALANCE AT       ADDITIONS           ADDITIONS                       BALANCE AT
                              BEGINNING OF   CHARGED TO COSTS   CHARGED TO OTHER                      END OF
                                 PERIOD        AND EXPENSES        ACCOUNTS(1)      DEDUCTIONS(2)     PERIOD
                              ------------   ----------------   -----------------   -------------   ----------
<S>                           <C>            <C>                <C>                 <C>             <C>
Allowance for Doubtful
  Accounts..................     $4,151           $3,641             $1,362            $(1,598)       $7,556
</Table>

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

(1) Additions represent the allowance recognized when we acquired CALNEV Pipe
    Line LLC and Kinder Morgan Liquids Terminals LLC, as well as transfers from
    other accounts.

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

<Table>
<Caption>
                                                 YEAR ENDED DECEMBER 31, 2000
                       --------------------------------------------------------------------------------
                        BALANCE AT       ADDITIONS           ADDITIONS                       BALANCE AT
                       BEGINNING OF   CHARGED TO COSTS   CHARGED TO OTHER                      END OF
                          PERIOD        AND EXPENSES        ACCOUNTS(1)      DEDUCTIONS(2)     PERIOD
                       ------------   ----------------   -----------------   -------------   ----------
<S>                    <C>            <C>                <C>                 <C>             <C>
Allowance for
  Doubtful
  Accounts...........     $6,717           $  --              $2,718            $(5,284)       $4,151
</Table>

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

(1) Additions represent the allowance recognized when we acquired our Natural
    Gas Pipelines.

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

<Table>
<Caption>
                                                 YEAR ENDED DECEMBER 31, 1999
                       --------------------------------------------------------------------------------
                        BALANCE AT       ADDITIONS           ADDITIONS                       BALANCE AT
                       BEGINNING OF   CHARGED TO COSTS   CHARGED TO OTHER                      END OF
                          PERIOD        AND EXPENSES         ACCOUNTS        DEDUCTIONS(1)     PERIOD
                       ------------   ----------------   -----------------   -------------   ----------
<S>                    <C>            <C>                <C>                 <C>             <C>
Allowance for
  Doubtful
  Accounts...........     $9,883           $  --               $  --            $(3,166)       $6,717
</Table>

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

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

     (a)(3) Exhibits

<Table>
<S>     <C>   <C>
 *3.1     --  Third Amended and Restated Agreement of Limited Partnership
              of Kinder Morgan Energy Partners, L.P. (filed as Exhibit 3.1
              to Kinder Morgan Energy Partners, L.P. Form 10-Q for the
              quarter ended June 30, 2001, filed on August 9, 2001).
 *4.1     --  Specimen Certificate evidencing Common Units representing
              Limited Partner Interests (filed as Exhibit 4.1 to Amendment
              No. 1 to Kinder Morgan Energy Partners, L.P. Registration
              Statement on Form S-4, file No. 333-44519, filed on February
              4, 1998).
 *4.2     --  Indenture dated as of January 29, 1999 among Kinder Morgan
              Energy Partners, L.P. the guarantors listed on the signature
              page thereto and U.S. Trust Company of Texas, N.A., as
              trustee, relating to Senior Debt Securities (filed as
              Exhibit 4.1 to the Partnership's Current Report on Form 8-K
              filed February 16, 1999 (the "February 16, 1999 Form 8-K")).
</Table>

                                        71
<PAGE>
<Table>
<S>     <C>   <C>
 *4.3     --  First Supplemental Indenture dated as of January 29, 1999
              among Kinder Morgan Energy Partners, L.P., the subsidiary
              guarantors listed on the signature page thereto and U.S.
              Trust Company of Texas, N.A., as trustee, relating to
              $250,000,000 of 6.30% Senior Notes due February 1, 2009
              (filed as Exhibit 4.2 to the February 16, 1999 Form 8-K).
 *4.4     --  Second Supplemental Indenture dated as of September 30, 1999
              among Kinder Morgan Energy Partners, L.P. and U.S. Trust
              Company of Texas, N.A., as trustee, relating to release of
              subsidiary guarantors under the $250,000,000 of 6.30% Senior
              Notes due February 1, 2009 (filed as Exhibit 4.4 to the
              Partnership's Form 10-Q for the quarter ended September 30,
              1999 (the "1999 Third Quarter Form 10-Q")).
 *4.5     --  Indenture dated March 22, 2000 between Kinder Morgan Energy
              Partners and First Union National Bank, as Trustee (filed as
              Exhibit 4.1 to Kinder Morgan Energy Partners, L.P.
              Registration Statement on Form S-4 (file no. 333-35112)
              filed on April 19, 2000 (the "April 2000 Form S-4")).
 *4.6     --  Form of Floating Rate Note and Form of 8% Note (contained in
              the Indenture filed as Exhibit 4.1 to the April 2000 Form
              S-4).
 *4.7     --  Indenture dated November 8, 2000 between Kinder Morgan
              Energy Partners and First Union National Bank, as Trustee.
 *4.8     --  Form of 7.50% Note (contained in the Indenture filed as
              Exhibit 4.8).
 *4.9     --  Indenture dated January 2, 2001 between Kinder Morgan Energy
              Partners and First Union National Bank, as trustee, relating
              to Senior Debt Securities (including form of Senior Debt
              Securities) (filed as Exhibit 4.11 to Kinder Morgan Energy
              Partners, L.P. Form 10-K for 2000).
 *4.10    --  Indenture dated January 2, 2001 between Kinder Morgan Energy
              Partners and First Union National Bank, as trustee, relating
              to Subordinate Debt Securities (including form of
              Subordinate Debt Securities) (filed as Exhibit 4.12 to
              Kinder Morgan Energy Partners, L.P. Form 10-K for 2000).
 *4.11    --  Certificate of Vice President and Chief Financial Officer of
              Kinder Morgan Energy Partners, L.P. establishing the terms
              of the 6.75% Notes due March 15, 2011 and the 7.40% Notes
              due March 15, 2031 (filed as Exhibit 4.1 to Kinder Morgan
              Energy Partners, L.P. Form 8-K filed March 14, 2001).
 *4.12    --  Specimen of 6.75% Notes due March 15, 2011 in book-entry
              form (filed as Exhibit 4.2 to Kinder Morgan Energy Partners,
              L.P. Form 8-K filed March 14, 2001).
 *4.13    --  Specimen of 7.40% Notes due March 15, 2031 in book-entry
              form (filed as Exhibit 4.3 to Kinder Morgan Energy Partners,
              L.P. Form 8-K filed March 14, 2001).
  4.14    --  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. sec.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     --  Kinder Morgan Energy Partners, L.P. Common Unit Option Plan
              (filed as Exhibit 10.6 to the Partnership's 1997 Form 10-K).
*10.2     --  Employment Agreement with William V. Morgan (filed as
              Exhibit 10.1 to the Partnership's Form 10-Q for the quarter
              ended March 31, 1997).
*10.3     --  Kinder Morgan Energy Partners, L.P. Executive Compensation
              Plan (filed as Exhibit 10 to the Partnership's Form 10-Q for
              the quarter ended June 30, 1997).
*10.4     --  Employment Agreement dated April 20, 2000, by and among KMI,
              Kinder Morgan G.P., Inc. and David G Dehaemers, Jr. (filed
              as Exhibit 10(a) to KMI's Form 10-Q for the quarter ended
              March 31, 2000).
*10.5     --  Employment Agreement dated April 20, 2000, by and among KMI,
              Kinder Morgan G.P., Inc. and Michael C. Morgan (filed as
              Exhibit 10(b) to KMI's Form 10-Q for the quarter ended March
              31, 2000).
*10.6     --  Delegation of Control Agreement among Kinder Morgan
              Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan
              Energy Partners, L.P. and its operating partnerships (filed
              as Exhibit 10.1 to the June 30, 2001 Form 10-Q).
</Table>

                                        72
<PAGE>

<Table>
  <C>          <C>
*10.7       -- 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).
 10.8       -- Form of Credit Agreement dated as of October 25, 2000 among Kinder Morgan Energy Partners, L.P. and the
               lenders party thereto.
 10.9       -- Form of First Amendment to Credit Agreement dated as of January 31, 2001 among Kinder Morgan Energy
               Partners, L.P. and the lenders party thereto.
 10.10      -- Form of Second Amendment to Credit Agreement dated as of October 24, 2001 among Kinder Morgan Energy
               Partners, L.P. and the lenders party thereto.
 21.1       -- List of Subsidiaries
 23.1       -- Consent of PricewaterhouseCoopers LLP
</Table>

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

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

     (b) Reports on Form 8-K

     Current Report on Form 8-K was furnished on November 9, 2001, pursuant to
Item 9 of that form. We provided notice that we, along with KMI, 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 beginning on November 9, 2001
and continuing over a two-week period, to analysts and others to address various
strategic and financial issues relating to the business plans and objective of
ourselves, KMI 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 KMI's website at:
http://www.kindermorgan.com/investor_relations/
presentations/kmi_nov2001_presentation.pdf

     Current Report on Form 8-K was filed on December 24, 2001, pursuant to Item
5 of that form. We reported that on December 17, 2001 we had announced that we
had entered into a definitive agreement to purchase Tejas Gas, LLC, a wholly
owned subsidiary of InterGen (North America), Inc., for approximately
$750,000,000 in cash. Tejas Gas owns an approximately 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 transaction is expected to close in the first quarter
of 2002.

                                        73
<PAGE>

                         INDEX TO FINANCIAL STATEMENTS

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

                                        74
<PAGE>

                       REPORT OF INDEPENDENT ACCOUNTANTS

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

     In our opinion, the consolidated financial statements listed in the
accompanying index present fairly, in all material respects, the financial
position of Kinder Morgan Energy Partners, L.P. and its subsidiaries (the
Partnership) at December 31, 2001 and 2000, and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 2001 in conformity with accounting principles generally accepted in the
United States of America. In addition, in our opinion, the financial statement
schedule appearing under Item 14(a)(2) on page 71 presents fairly, in all
material respects, the information set forth therein when read in conjunction
with the related consolidated financial statements. These financial statements
and financial statement schedule are the responsibility of the Partnership's
management; our responsibility is to express an opinion on these financial
statements and financial statement schedule based on our audits. We conducted
our audits of these statements in accordance with auditing standards generally
accepted in the United States of America, which require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant estimates made by
management, and evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for our opinion.

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

/s/ PRICEWATERHOUSECOOPERS LLP

Houston, Texas
February 15, 2002

                                        75
<PAGE>

              KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

                       CONSOLIDATED STATEMENTS OF INCOME

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

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

                                        76
<PAGE>

              KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

                CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

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

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

                                        77
<PAGE>

              KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

                          CONSOLIDATED BALANCE SHEETS

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

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

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

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

                                        78
<PAGE>

              KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

                     CONSOLIDATED STATEMENTS OF CASH FLOWS

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

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

                                        79
<PAGE>

              KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

                  CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL

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

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

                                        80
<PAGE>

1.  ORGANIZATION

  GENERAL

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

     - transporting, storing and processing refined petroleum products;

     - transporting, storing and selling natural gas;

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

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

     We focus on providing fee-based services to customers, avoiding commodity
price risks and taking advantage of the low-cost capital available in a limited
partnership structure. We trade on the New York Stock Exchange under the symbol
"KMP" and presently conduct our business through four reportable business
segments:

     - Products Pipelines;

     - Natural Gas Pipelines;

     - CO(2) Pipelines; and

     - Terminals.

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

  MERGER OF KMI

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

  KINDER MORGAN MANAGEMENT, LLC

     Kinder Morgan Management, LLC, a Delaware limited liability company, was
formed on February 14, 2001. It is referred to as "KMR" in this report. Our
general partner owns all of KMR's voting securities.

                                        81
<PAGE>

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

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

  TWO-FOR-ONE COMMON UNIT SPLIT

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

2.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

  BASIS OF PRESENTATION

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

  CRITICAL ACCOUNTING POLICIES AND ESTIMATES

     Our consolidated financial statements were prepared in accordance with
accounting principles generally accepted in the United States. Certain amounts
included in or affecting our financial statements and related disclosures must
be estimated, requiring us to make certain assumptions with respect to values or
conditions which cannot be known with certainty at the time the financial
statements are prepared.

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

     - the amounts we report for assets and liabilities;

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

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

     Therefore, the reported amounts of our assets and liabilities, revenues and
expenses and associated disclosures with respect to contingent assets and
obligations are necessarily affected by these estimates. We evaluate these
estimates on an ongoing basis, utilizing historical experience, consultation
with experts and other methods we consider reasonable in the particular
circumstances. Nevertheless, actual results may differ significantly from our
estimates. Any effects on our business, financial position or results of
                                        82
<PAGE>

operations resulting from revisions to these estimates are recorded in the
period in which the facts that give rise to the revision become known.

     In preparing our financial statements and related disclosures, we must use
estimates in determining the economic useful lives of our assets, provisions for
uncollectible accounts receivable, exposures under contractual indemnifications
and various other recorded or disclosed amounts. However, we believe that
certain accounting policies are of more significance in our financial statement
preparation process than others. With respect to our environmental exposure, we
utilize both internal staff and external experts to assist us in identifying
environmental issues and in estimating the costs and timing of remediation
efforts. Often, as the remediation evaluation and effort progresses, additional
information is obtained, requiring revisions to estimated costs. These revisions
are reflected in our income in the period in which they are reasonably
determinable. Finally, we are subject to litigation as the result of our
business operations and transactions. We utilize both internal and external
counsel in evaluating our potential exposure to adverse outcomes from judgments
or settlements. To the extent that actual outcomes differ from our estimates, or
additional facts and circumstances cause us to revise our estimates, our
earnings will be affected.

 CASH EQUIVALENTS

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

  INVENTORIES

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

  PROPERTY, PLANT AND EQUIPMENT

     We state property, plant and equipment at its acquisition cost. We expense
costs for maintenance and repairs in the period incurred. The cost of property,
plant and equipment sold or retired and the related depreciation are removed
from our balance sheet in the period of sale or disposition. We compute
depreciation using the straight-line method based on estimated economic lives.
Generally, we apply composite depreciation rates to functional groups of
property having similar economic characteristics. The rates range from 2.0% to
12.5%, excluding certain short-lived assets such as vehicles. Depreciation,
depletion and amortization of the capitalized costs of producing carbon dioxide
properties, both tangible and intangible, are provided for on a
units-of-production basis. Proved developed reserves are used in computing
units-of-production rates for drilling and development costs, and total proved
reserves are used for depletion of leasehold costs. The basis for
units-of-production rate determination is by field. We charge the original cost
of property sold or retired to accumulated depreciation and amortization, net of
salvage and cost of removal. We do not include retirement gain or loss in income
except in the case of significant retirements or sales.

     We evaluate impairment of our long-lived assets in accordance with
Statement of Financial Accounting Standards No. 121 "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of." We
review for the impairment of long-lived assets whenever events or changes in
circumstances indicate that our carrying amount of an asset may not be
recoverable. We would recognize an impairment loss when estimated future cash
flows expected to result from our use of the asset and its eventual disposition
is less than its carrying amount.

     In practice, the composite life may not be determined with a high degree of
precision, and hence the composite life may not reflect the weighted average of
the expected useful lives of the asset's principal components. The Financial
Accounting Standards Board has issued a proposed Statement of Position entitled
"Accounting for Certain Costs and Activities Related to Property, Plant and
Equipment". For purposes of the SOP, a project stage or timeline frame works is
used and property, plant and equipment

                                        83
<PAGE>

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

     - preliminary;

     - preacquisition;

     - acquisition-or-construction; and

     - in-service.

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

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

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

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

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

  NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

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

  EQUITY METHOD OF ACCOUNTING

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

  EXCESS OF COST OVER FAIR VALUE

     As of December 31, 2001, we amortized the excess cost over our underlying
net asset book value in equity investments using the straight-line method over
the estimated remaining useful lives of the assets in accordance with Accounting
Principles Board Opinion No. 16. We amortized this excess for undervalued
depreciable assets over a period not to exceed 50 years and for intangible
assets over a period not to exceed 40 years. For our investments in consolidated
affiliates, we reported amortization of excess cost over fair value of net
assets (goodwill) as amortization expense in our accompanying consolidated
statements of income. For our investments accounted for under the equity method,
we reported amortization of excess cost on investments as amortization of excess
cost of equity investments in our accompanying consolidated statements of
income. Our total unamortized excess cost over fair value of net assets on
investments in consolidated affiliates was approximately $546.7 million as of
December 31, 2001 and $158.1 million as of December 31, 2000. These amounts are
included within intangibles on our accompanying consolidated

                                        84
<PAGE>

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

     We periodically reevaluate the amount at which we carry the excess of cost
over fair value of net assets of businesses we acquired, as well as the
amortization period for such assets, to determine whether current events or
circumstances warrant adjustments to our carrying value and/or revised estimates
of useful lives. At December 31, 2001, we believed no such impairment had
occurred and no reduction in estimated useful lives was warranted. On January 1,
2002, we adopted SFAS No. 141 "Business Combinations".

     SFAS No. 141 supercedes Accounting Principles Board Opinion No. 16 and
requires that all transactions fitting the description of a business combination
be accounted for using the purchase method and prohibits the use of the pooling
of interests for all business combinations initiated after June 30, 2001. The
Statement also modifies the accounting for the excess of fair value of net
assets acquired as well as intangible assets acquired in a business combination.
The provisions of this statement apply to all business combinations initiated
after June 30, 2001, and all business combinations accounted for by the purchase
method that are completed after July 1, 2001. This Statement requires disclosure
of the primary reasons for a business combination and the allocation of the
purchase price paid to the assets acquired and liabilities assumed by major
balance sheet caption. After July 1, 2001, we completed four acquisitions and
have initiated or announced four additional acquisitions. Refer to Note 3 for
more detail about our acquisitions.

     SFAS No. 142 "Goodwill and Other Intangible Assets" supercedes Accounting
Principles Board Opinion No. 17 and requires that goodwill no longer be
amortized but should be tested, at least on an annual basis, for impairment. A
benchmark assessment of potential impairment must also be completed within six
months of adopting SFAS No. 142. After the first six months, goodwill will be
tested for impairment annually. SFAS No. 142 applies to any goodwill acquired in
a business combination completed after June 30, 2001. Other intangible assets
are to be amortized over their useful life and reviewed for impairment in
accordance with the provisions of SFAS No. 121,"Accounting for the Impairment of
Long-Lived Assets and Long-Lived Assets to be Disposed Of". An intangible asset
with an indefinite useful life can no longer be amortized until its useful life
becomes determinable. This Statement requires disclosure of information about
goodwill and other intangible assets in the years subsequent to their
acquisition that was not previously required. Required disclosures include
information about the changes in the carrying amount of goodwill from period to
period and the carrying amount of intangible assets by major intangible asset
class. After June 30, 2001, we completed two acquisitions, our Boswell and
Stolt-Nielsen acquisitions, which resulted in the recognition of goodwill. We
adopted SFAS No. 142 on January 1, 2002, and we expect that SFAS No. 142 will
not have a material impact on our business, financial position or results of
operations. With the adoption of SFAS No. 142, goodwill of approximately $546.7
million is no longer subject to amortization over its estimated useful life. For
more information on our acquisitions, see Note 3.

  REVENUE RECOGNITION

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

                                        85
<PAGE>

  ENVIRONMENTAL MATTERS

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

  MINORITY INTEREST

     Minority interest consists of the following:

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

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

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

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

     - the approximate 32% interest in MidTex Gas Storage Company, L.L.P., a
       Texas limited liability partnership owned approximately 68% and
       controlled by Kinder Morgan Texas Pipeline L.P. and its consolidated
       subsidiaries.

  INCOME TAXES

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

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

  COMPREHENSIVE INCOME

     Statement of Financial Accounting Standards No. 130, "Accounting for
Comprehensive Income", requires that enterprises report a total for
comprehensive income. For the year ended December 31, 2001, the only difference
between net income and comprehensive income for us was the unrealized gain or
loss on derivatives utilized for hedging purposes. There was no difference
between net income and comprehensive income for each of the years ended December
31, 2000 and 1999. For more information on our hedging activities, see Note 14.

  NET INCOME PER UNIT

     We compute Basic Limited Partners' Net Income per Unit by dividing limited
partner's interest in net income by the weighted average number of units
outstanding during the period. Diluted Limited Partners' Net Income per Unit
reflects the potential dilution, by application of the treasury stock method,
that could occur if options to issue units were exercised, which would result in
the issuance of additional units that would then share in our net income.

                                        86
<PAGE>

  RISK MANAGEMENT ACTIVITIES

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

3.  ACQUISITIONS AND JOINT VENTURES

     During 1999, 2000 and 2001, we completed the following significant
acquisitions. Each of the acquisitions was accounted for under the purchase
method and the assets acquired and liabilities assumed were recorded at their
estimated fair market values as of the acquisition date. The preliminary amounts
assigned to assets and liabilities may be adjusted during a short period
following the acquisition. The results of operations from these acquisitions are
included in the consolidated financial statements from the date of acquisition.

  Plantation Pipe Line Company

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

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

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

  Transmix Operations

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

                                        87
<PAGE>

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

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

  Trailblazer Pipeline Company

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

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

  1999 Kinder Morgan, Inc. Asset Contributions

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

                                        88
<PAGE>

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

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

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

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

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

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

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

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

                                        89
<PAGE>

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

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

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

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

  Devon Energy

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

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

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

  Buckeye Refining Company, LLC

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

                                        90
<PAGE>

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

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

  Cochin Pipeline

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

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

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

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

  Delta Terminal Services LLC

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

                                        91
<PAGE>

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

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

  MKM Partners, L.P.

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

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

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

  2000 Kinder Morgan, Inc. Asset Contributions

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

                                        92
<PAGE>

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

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

  Colton Transmix Processing Facility

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

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

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

  GATX Domestic Pipelines and Terminals Businesses

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

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

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

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

     KMLT's assets includes 12 terminals, located across the United States,
which store approximately 35.6 million barrels of refined petroleum products and
chemicals. Five of the terminals are included in our Terminals business segment,
and the remaining assets are included in our Products Pipelines business
segment. Central Florida Pipeline LLC consists of a 195-mile pipeline
transporting refined petroleum

                                        93
<PAGE>

products from Tampa to the growing Orlando, Florida market. CALNEV Pipe Line LLC
consists of a 550-mile refined petroleum products pipeline originating in
Colton, California and extending into the growing Las Vegas, Nevada market. The
pipeline interconnects in Colton with our Pacific operations' West Line pipeline
segment. Our purchase price was approximately $1,231.6 million, consisting of
$975.4 million in cash, $134.8 million in assumed debt and $121.4 million in
assumed liabilities.

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

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

  Pinney Dock & Transport LLC

     Effective March 1, 2001, we acquired all of the shares of the capital stock
of Pinney Dock & Transport LLC, formerly Pinney Dock & Transport Company, for
approximately $52.5 million. The acquisition includes a bulk product terminal
located in Ashtabula, Ohio on Lake Erie. The facility handles iron ore, titanium
ore, magnetite and other aggregates. Our purchase price consisted of
approximately $41.7 million in cash and approximately $10.8 million in assumed
liabilities.

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

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

  Vopak

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

                                        94
<PAGE>

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

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

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

  Kinder Morgan Texas Pipeline

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

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

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

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

  The Boswell Oil Company

     Effective August 31, 2001, we acquired from The Boswell Oil Company three
terminals located in Cincinnati, Ohio, Pittsburgh, Pennsylvania and Vicksburg,
Mississippi. The Cincinnati and Pittsburgh terminals handle both liquids and
dry-bulk materials. The Vicksburg terminal is a break-bulk facility, primarily
handling paper and steel products. As a result of the acquisition, we continued
the expansion of our bulk terminal businesses and entered new markets. Our
purchase price was approximately $22.2 million, consisting of approximately
$18.1 million in cash, a $3.0 million one-year note payable and approximately
$1.1 million in assumed liabilities.

                                        95
<PAGE>

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

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

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

  Stolt-Nielsen

     In November 2001, we acquired certain liquids terminals in Chicago,
Illinois and Perth Amboy, New Jersey from Stolthaven Perth Amboy Inc.,
Stolthaven Chicago Inc. and Stolt-Nielsen Transportation Group, Ltd. As a result
of the acquisition, we expanded our liquids terminals businesses into strategic
markets. The Perth Amboy facility provides liquid chemical and petroleum storage
and handling, as well as dry-bulk handling of salt and aggregates, with liquid
capacity exceeding 2.3 million barrels annually. We closed on the Perth Amboy,
New Jersey portion of this transaction on November 8, 2001. The Chicago terminal
handles a wide variety of liquid chemicals with a working capacity in excess of
0.7 million barrels annually. We closed on the Chicago, Illinois portion of this
transaction on November 29, 2001. Our purchase price was approximately $69.8
million, consisting of approximately $44.8 million in cash and $25.0 million in
assumed debt.

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

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

     The $0.1 million of goodwill was assigned to our Terminals business segment
and the entire amount is expected to be deductible for tax purposes.

  Snyder and Diamond M Plants

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

                                        96
<PAGE>

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

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

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

  PRO FORMA INFORMATION

     The following summarized unaudited Pro Forma Consolidated Income Statement
information for the twelve months ended December 31, 2001 and 2000, assumes the
2001 and 2000 acquisitions and joint ventures had occurred as of January 1,
2000. We have prepared these unaudited Pro Forma financial results for
comparative purposes only. These unaudited Pro Forma financial results may not
be indicative of the results that would have occurred if we had completed the
2001 and 2000 acquisitions and joint ventures as of January 1, 2000 or the
results which will be attained in the future. Amounts presented below are in
thousands, except for the per unit amounts:

<Table>
<Caption>
                                                               PRO FORMA YEAR ENDED
                                                                   DECEMBER 31,
                                                              -----------------------
                                                                 2001         2000
                                                              ----------   ----------
                                                                    (UNAUDITED)
<S>                                                           <C>          <C>
Revenues....................................................  $3,028,543   $3,295,040
Operating Income............................................     592,668      537,561
Income before extraordinary charge..........................     501,153      469,609
Net Income..................................................     484,521      448,201
Basic and diluted Limited Partners' Income per unit before
  extraordinary charge......................................  $     1.56   $     1.38
Basic and diluted Limited Partners' Net Income per unit.....  $     1.56   $     1.38
</Table>

  ACQUISITIONS SUBSEQUENT TO DECEMBER 31, 2001

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

     On December 17, 2001, we announced that we had entered into a definitive
agreement to purchase Tejas Gas, LLC, a wholly owned subsidiary of InterGen
(North America), Inc., for approximately $750 million in cash. Tejas Gas, LLC is
a 3,400-mile natural gas intrastate pipeline system that extends from south
Texas along the Mexico border and the Texas Gulf Coast to near the Louisiana
border and

                                        97
<PAGE>

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

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

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

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

5.  INCOME TAXES

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

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

                                        98
<PAGE>

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

<Table>
<Caption>
                                                              YEAR ENDED DECEMBER 31,
                                                              ------------------------
                                                               2001     2000     1999
                                                              ------   ------   ------
<S>                                                           <C>      <C>      <C>
Federal income tax rate.....................................   35.0%    35.0%    35.0%
Increase (decrease) as a result of:
  Partnership earnings not subject to tax...................  (35.0)%  (35.0)%  (35.3)%
  Corporate subsidiary earnings subject to tax..............    1.3%     0.6%     1.0%
  Income tax expense attributable to corporate equity
     earnings...............................................    1.8%     4.1%     4.4%
  State taxes...............................................    0.4%     0.1%     0.1%
  Other.....................................................     --       --     (0.2)%
                                                              -----    -----    -----
Effective tax rate..........................................    3.5%     4.8%     5.0%
                                                              =====    =====    =====
</Table>

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

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

     We had available, at December 31, 2001, approximately $1.1 million of
alternative minimum tax credit carryforwards, which are available indefinitely,
and $1.9 million of net operating loss carryforwards, which will expire between
the years 2002 and 2018. We believe it is more likely than not that the net
operating loss carryforwards will be utilized prior to their expiration;
therefore, no valuation allowance is necessary.

                                        99
<PAGE>

6.  PROPERTY, PLANT AND EQUIPMENT

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

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

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

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

7.  INVESTMENTS

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

     - Plantation Pipe Line Company (51%);

     - Red Cedar Gathering Company (49%);

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

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

     - Cortez Pipeline Company (50%)

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

     - Heartland Pipeline Company (50%).

     On June 16, 1999, we acquired an additional approximate 27% interest in
Plantation Pipe Line Company. As a result, we now own approximately 51% of
Plantation Pipe Line Company, and an affiliate of ExxonMobil owns the remaining
approximate 49%. Each investor has an equal number of directors on Plantation's
board of directors, and board approval is required for certain corporate actions
that are considered participating rights. Therefore, we do not control
Plantation Pipe Line Company, and we account for our investment under the equity
method of accounting.

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

                                       100
<PAGE>

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

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

     Please refer to Notes 3 and 4 for more information.

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

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

                                       101
<PAGE>

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

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

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

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

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

8.  INTANGIBLES

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

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

                                       102
<PAGE>

     Intangible assets consisted of the following (in thousands):

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

     Amortization expense consists of the following (in thousands):

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

9.  DEBT

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

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

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

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

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

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

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

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

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

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

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

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

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

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

     - $35 million of 7.84% Senior Notes, with a final maturity of July 2008
       (our subsidiary, Central Florida Pipe Line LLC, is the obligor on the
       notes); and

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

                                       103
<PAGE>

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

     - $590.5 million of commercial paper borrowings;

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

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

     - $3.5 million in other borrowings.

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

  Credit Facilities

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

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

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

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

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

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

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

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

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

                                       104
<PAGE>

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

  Senior Notes

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

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

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

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

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

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

     - 8.0% senior notes due March 15, 2005;

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

     - 7.40% senior notes due March 15, 2031.

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

                                       105
<PAGE>

  Commercial Paper Program

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

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

  SFPP, L.P. Debt

     At December 31, 2001, the outstanding balance under SFPP, L.P.'s Series F
notes was $79.6 million. The annual interest rate on the Series F notes is
10.70%, the maturity is December 2004, and interest is payable semiannually in
June and December. We expect to repay the Series F notes prior to maturity as a
result of SFPP , L.P. taking advantage of certain optional prepayment provisions
without penalty in 1999 and 2000. Remaining annual installments are $42.6
million in 2002 and $37.0 million in 2003. Additionally, the Series F notes may
be prepaid in full or in part at a price equal to par plus, in certain
circumstances, a premium. We agreed as part of the acquisition of SFPP, L.P.'s
operations (which constitute a significant portion of our Pacific operations)
not to take actions with respect to $190 million of SFPP, L.P.'s debt that would
cause adverse tax consequences for the prior general partner of SFPP, L.P. The
Series F notes are secured by mortgages on substantially all of the properties
of SFPP, L.P. The Series F notes contain certain covenants limiting the amount
of additional debt or equity that may be issued by SFPP, L.P. and limiting the
amount of cash distributions, investments, and property dispositions by SFPP,
L.P. We do not believe that these restrictions will materially affect
distributions to our partners.

  Kinder Morgan Liquids Terminals LLC Debt

     Effective January 1, 2001, we acquired Kinder Morgan Liquids Terminals LLC
(see Note 3). As part of our purchase price, we assumed debt of $87.9 million,
consisting of five series of Industrial Revenue Bonds. The Bonds consist of the
following:

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

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

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

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

     - $3.6 million of 6.625% Texas Industrial Revenue Bonds due February 1,
       2024.

     In November 2001, we acquired a liquids terminal in Perth Amboy, New Jersey
from Stolthaven Perth Amboy Inc. and Stolt-Nielsen Transportation Group, Ltd. As
part of our purchase price, we assumed $25.0 million of Economic Development
Revenue Refunding Bonds issued by the New Jersey Economic Development Authority.
The bonds have a maturity date of January 15, 2018. Interest on these bonds is
computed on the basis of a year of 365 or 366 days, as applicable, for the
actual number of days elapsed during Commercial Paper, Daily or Weekly Rate
Periods and on the basis of a 360-day year
                                       106
<PAGE>

consisting of twelve 30-day months during a Term Rate Period. As of December 31,
2001, the interest rate was 1.391%. We have an outstanding letter of credit
issued by Citibank in the amount of $25.3 million that backs-up the $25.0
million principal amount of the bonds and $0.3 million of interest on the bonds
for up to 42 days computed at 12% on a per annum basis on the principal thereof.

  Central Florida Pipeline LLC Debt

     Effective January 1, 2001, we acquired Central Florida Pipeline LLC (see
Note 3). As part of our purchase price, we assumed an aggregate principal amount
of $40 million of Senior Notes originally issued to a syndicate of eight
insurance companies. The Senior Notes have a fixed annual interest rate of 7.84%
and will be repaid in annual installments of $5 million beginning July 23, 2001.
The final payment is due July 23, 2008. Interest is payable semiannually on
January 1 and July 23 of each year. At December 31, 2001, Central Florida's
outstanding balance under the Senior Notes was $35.0 million.

  CALNEV Pipe Line LLC Debt

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

  Trailblazer Pipeline Company Debt

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

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

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

                                       107
<PAGE>

limitation on the amount of additional money that Trailblazer Pipeline Company
could borrow and relieved Trailblazer Pipeline Company from its security deposit
obligation. On June 26, 2001, Trailblazer Pipeline Company prepaid the $15.2
million balance outstanding under the Senior Secured Notes, plus $0.8 million
for interest and a make-whole premium, using its new two-year unsecured
revolving credit facility.

  Kinder Morgan Operating L.P. "B" Debt

     The $23.7 million principal amount of tax-exempt bonds due 2024 were issued
by the Jackson-Union Counties Regional Port District. These bonds bear interest
at a weekly floating market rate. During 2001, the weighted-average interest
rate on these bonds was 2.71% per annum, and at December 31, 2001 the interest
rate was 1.70%. We have an outstanding letter of credit issued under our credit
facilities that backs-up our tax-exempt bonds. The letter of credit reduces the
amount available for borrowing under our credit facilities.

  Cortez Pipeline

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

     Due to our indirect ownership of Cortez through KMCO(2), we severally
guarantee 50% of the debt of Cortez Capital Corporation. Shell Oil Company
shares our guaranty obligations jointly and severally through December 31, 2006
for Cortez's debt programs in place as of April 1, 2000.

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

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

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

     - $136.4 million of Series D notes; and

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

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

  MATURITIES OF DEBT

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

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

                                       108
<PAGE>

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

  FAIR VALUE OF FINANCIAL INSTRUMENTS

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

     Fair value as used in SFAS No. 107 "Disclosures About Fair Value of
Financial Instruments" represents the amount at which an instrument could be
exchanged in a current transaction between willing parties.

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

10.  PENSIONS AND OTHER POST-RETIREMENT BENEFITS

     In connection with our acquisition of SFPP and Kinder Morgan Bulk Terminals
in 1998, we acquired certain liabilities for pension and post-retirement
benefits. We provide medical and life insurance benefits to current employees,
their covered dependents and beneficiaries of SFPP and Kinder Morgan Bulk
Terminals. We also provide the same benefits to former salaried employees of
SFPP. Additionally, we will continue to fund these costs for those employees
currently in the plan during their retirement years.

     The noncontributory defined benefit pension plan covering the former
employees of Kinder Morgan Bulk Terminals is the Employee Benefit Plan for
Employees of Hall-Buck Marine Services Company and the benefits under this plan
were based primarily upon years of service and final average pensionable
earnings. Benefit accruals were frozen as of December 31, 1998 for the Hall-Buck
plan. Effective December 31, 2000, the Hall-Buck plan, along with the K N
Energy, Inc. Retirement Plan for Bargaining Employees, was merged into the K N
Energy, Inc. Retirement Plan for Non-Bargaining employees, with the
Non-Bargaining Plan being the surviving plan. The merged plan was renamed the
Kinder Morgan, Inc. Retirement Plan.

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

                                       109
<PAGE>

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

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

                                       110
<PAGE>

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

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

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

     Assumed health care cost trend rates have a significant effect on the
amounts reported for the health care plans. A 1% change in assumed health care
cost trend rates would have the following effects:

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

     Multiemployer Plans and Other Benefits.  With our acquisition of Kinder
Morgan Bulk Terminals, effective July 1, 1998, we participate in multi-employer
pension plans for the benefit of its employees who are union members. We do not
administer these plans and contribute to them in accordance with the provisions
of negotiated labor contracts. Other benefits include a self-insured health and
welfare insurance plan and an employee health plan where employees may
contribute for their dependents' health care costs. Amounts charged to expense
for these plans were $0.6 million for the year ended 2001 and $0.2 million for
the year ended 2000. The amount charged from the period of acquisition through
December 31, 1998 was $0.5 million.

                                       111
<PAGE>

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

     Effective July 1, 1997, our general partner established the Kinder Morgan
Retirement Savings Plan, a defined contribution 401(k) plan. This plan was
subsequently amended and merged to form the Kinder Morgan Savings Plan. The plan
now permits all full-time employees of our general partner to contribute 1% to
50% of base compensation, on a pre-tax basis, into participant accounts. In
addition to a mandatory contribution equal to 4% of base compensation per year
for most plan participants, our general partner may make discretionary
contributions in years when specific performance objectives are met. Certain
employees' contributions are based on collective bargaining agreements. Our
mandatory contributions are made each pay period on behalf of each eligible
employee. Any discretionary contributions are made during the first quarter
following the performance year. All contributions, including discretionary
contributions, are in the form of KMI stock that is immediately convertible into
other available investment vehicles at the employee's discretion. In the first
quarter of 2002, no discretionary contributions were made to individual accounts
for 2001. The total amount charged to expense for our Retirement Savings Plan
was $4.6 million during 2001. All contributions, together with earnings thereon,
are immediately vested and not subject to forfeiture. Participants may direct
the investment of their contributions into a variety of investments. Plan assets
are held and distributed pursuant to a trust agreement.

     Effective January 1, 2001, employees of our general partner became eligible
to participate in a new Cash Balance Retirement Plan. Certain employees continue
to accrue benefits through a career-pay formula, "grandfathered" according to
age and years of service on December 31, 2000, or collective bargaining
arrangements. All other employees will accrue benefits through a personal
retirement account in the new Cash Balance Retirement Plan. Employees with prior
service and not grandfathered convert to the Cash Balance Retirement Plan and
will be credited with the current fair value of any benefits they have
previously accrued through the defined benefit plan. We will then begin
contributions on behalf of these employees equal to 3% of eligible compensation
every pay period. In addition, we may make discretionary contributions to the
plan based on our performance. In the first quarter of 2002, an additional 1%
discretionary contribution was made to individual accounts based on achieving
2001 financial targets to unitholders. Interest will be credited to the personal
retirement accounts at the 30-year U.S. Treasury bond rate in effect each year.
Employees will be fully vested in the plan after five years, and they may take a
lump sum distribution upon termination of employment or retirement.

11.  PARTNERS' CAPITAL

     At December 31, 2001, our Partners' capital consisted of 129,855,018 common
units, 5,313,400 Class B units and 30,636,363 i-units. Together, these
165,804,781 units represent the limited partners' interest and an effective 98%
economic interest in the Partnership, exclusive of our general partner's
incentive distribution. Our common unit total consisted of 110,071,392 units
held by third parties, 18,059,626 units held by KMI and its consolidated
affiliates (excluding our general partner) and 1,724,000 units held by our
general partner. Our Class B units were held entirely by KMI and our i-units
were held entirely by KMR. At December 31, 2000 and 1999, there were 129,716,218
and 118,274,274 common units outstanding, respectively. The Class B units were
issued in December 2000 and the i-units were issued in 2001. Our general partner
has an effective 2% interest in the Partnership, excluding the general partner's
incentive distribution.

                                       112
<PAGE>

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

     - 2,975,000 units to KMI; and

     - 26,775,000 units to the public.

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

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

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

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

     In all cases, KMR will vote its i-units in proportion to the affirmative
and negative votes, abstentions and non-votes of owners of KMR shares.
Furthermore, under the terms of our partnership agreement, we agree that we will
not, except in liquidation, make a distribution on an i-unit other than in
additional i-units or a security that has in all material respects the same
rights and privileges as our i-units. Typically, our general partner and owners
of common units and Class B units will receive distributions from us in cash,
while KMR as the owner of i-units will receive distributions in additional
i-units or fractions of i-units. For each outstanding i-unit, a fraction of an
i-unit will be issued. The fraction will be determined by dividing the amount of
cash being distributed per common unit by the average market price of a KMR
share over the ten consecutive trading days preceding the date on which the
shares begin to trade ex-dividend under the rules of the principal exchange on
which the shares are listed. The cash equivalent of distributions of i-units
will be treated as if it had actually been distributed for purposes of
determining the distributions to our general partner. We will not distribute the
related cash but will retain the cash and use the cash in our business. If
additional units are distributed to the holders of our common units, we will
issue an equivalent amount of i-units to KMR based on the number of i-units it
owns.

     For the purposes of maintaining partner capital accounts, our partnership
agreement specifies that items of income and loss shall be allocated among the
partners, other than owners of i-units, in accordance with their percentage
interests. Normal allocations according to percentage interests are made,
however, only after giving effect to any priority income allocations in an
amount equal to the incentive distributions that are allocated 100% to our
general partner.

     Incentive distributions allocated to our general partner are determined by
the amount quarterly distributions to unitholders exceed certain specified
target levels. For the years ended December 31, 2001, 2000 and 1999, we
distributed $2.15, $1.7125 and $1.425, respectively, per unit. Our distributions
to unitholders for 2001, 2000 and 1999 required incentive distributions to our
general partner in the amount of $199.7 million, $107.8 million and $55.0
million, respectively. The increased incentive distributions paid

                                       113
<PAGE>

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

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

     - $0.55, the cash amount distributed per common unit

by

     - $37.116, the average of KMR's limited liability shares' closing market
       prices from January 14-28, 2002, the ten consecutive trading days
       preceding the date on which the shares began to trade ex-dividend under
       the rules of the New York Stock Exchange.

     This distribution required an incentive distribution to our general partner
in the amount of $54.4 million. Since this distribution was declared after the
end of the quarter, no amount is shown in the December 31, 2001 balance sheet as
a Distribution Payable.

12.  RELATED PARTY TRANSACTIONS

  GENERAL AND ADMINISTRATIVE EXPENSES

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

     The named executive officers of our general partner and KMR and some other
employees that provide management or services to both Kinder Morgan, Inc. and
the Group are employed by Kinder Morgan, Inc. Additionally, other Kinder Morgan,
Inc. employees assist in the operation of Kinder Morgan Energy Partners' Natural
Gas Pipeline assets formerly owned by Kinder Morgan, Inc. These Kinder Morgan,
Inc. employees' expenses are allocated without a profit component between Kinder
Morgan, Inc. and the appropriate members of the Group.

  PARTNERSHIP DISTRIBUTIONS

  Kinder Morgan G.P., Inc.

     Kinder Morgan G.P., Inc. serves as our sole general partner. Pursuant to
our partnership agreements, our general partner's interests represent a 1%
ownership interest in the Partnership, and a direct 1.0101% ownership interest
in each of our five operating partnerships. Collectively, our general partner
owns an effective 2% interest in the operating partnerships, excluding incentive
distributions:

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<PAGE>

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

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

     At December 31, 2001, our general partner owned 1,724,000 common units,
representing approximately 1.04% of our outstanding limited partner units. Our
partnership agreement requires that we distribute 100% of "Available Cash" (as
defined in the partnership agreement) to our partners within 45 days following
the end of each calendar quarter in accordance with their respective percentage
interests. Available Cash consists generally of all of our cash receipts and net
reductions in reserves less cash disbursements and net additions to reserves
(including any reserves required under debt instruments for future principal and
interest payments) and amounts payable to the former general partner of SFPP,
L.P. in respect of its remaining 0.5% special limited partner interest in SFPP,
L.P.

     Our general partner is granted discretion by our partnership agreement,
which discretion has been delegated to KMR, subject to the approval of our
general partner in certain cases, to establish, maintain and adjust reserves for
future operating expenses, debt service, maintenance capital expenditures, rate
refunds and distributions for the next four quarters. These reserves are not
restricted by magnitude, but only by type of future cash requirements with which
they can be associated. When KMR determines our quarterly distributions, it
considers current and expected reserve needs along with current and expected
cash flows to identify the appropriate sustainable distribution level.

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

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

     Available Cash for each quarter is distributed as follows;

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

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

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

     - fourth, 50% of any Available Cash then remaining to the owners of all
       classes of units pro rata, to owners of common units and Class B units in
       cash and to KMR in the equivalent number of i-units, and 50% to our
       general partner in cash.

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

                                       115
<PAGE>

  Kinder Morgan, Inc.

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

  Kinder Morgan Management, LLC

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

  ASSET ACQUISITIONS

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

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

  OPERATIONS

     KMI or its subsidiaries operate and maintain for us the assets comprising
our Natural Gas Pipelines business segment. Natural Gas Pipeline Company of
America, a subsidiary of KMI, operates Trailblazer Pipeline Company's assets
under a long-term contract pursuant to which Trailblazer Pipeline Company incurs
the costs and expenses related to NGPL's operating and maintaining the assets.
Trailblazer Pipeline Company provides the funds for capital expenditures. NGPL
does not profit from or suffer loss related to its operation of Trailblazer
Pipeline Company's assets.

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

                                       116
<PAGE>

subsidiaries in performing such services. We also reimburse KMI and its
subsidiaries for operating and maintenance costs and capital expenditures
incurred with respect to these assets.

  OTHER

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

13.  LEASES AND COMMITMENTS

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

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

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

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

     We apply Accounting Principles Board Opinion No. 25, "Accounting for Stock
Issued to Employees," and related interpretations in accounting for common unit
options granted under our common unit option plan. Pro forma information
regarding changes in net income and per unit data, if the accounting prescribed
by Statement of Financial Accounting Standards No. 123 "Accounting for Stock
Based Compensation," had been applied, is not material. No compensation expense
has been recorded since the options were granted at exercise prices equal to the
market prices at the date of grant.

                                       117
<PAGE>

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

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

14.  RISK MANAGEMENT

  HEDGING ACTIVITIES

     Our normal business activities expose us to risks associated with changes
in the market price of natural gas and associated transportation, natural gas
liquids, crude oil and carbon dioxide. Through KMI, we use energy financial
instruments to reduce our risk of price changes in the spot and fixed price of
natural gas, natural gas liquids and crude oil markets as discussed below. We
are exposed to credit-related losses in the event of nonperformance by
counterparties to these financial instruments but, given their existing credit
ratings, we do not expect any counterparties to fail to meet their obligations.
The fair value of these risk management instruments reflects the estimated
amounts that we would receive or pay to terminate the contracts at the reporting
date, thereby taking into account the current unrealized gains or losses on open
contracts. We have available market quotes for substantially all of the
financial instruments that we use.

     The energy risk management products that we use include:

     - commodity futures and options contracts;

     - fixed-price swaps; and

     - basis swaps.

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

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

     - gas purchases; and

     - system use and storage.

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

                                       118
<PAGE>

     Effective January 1, 2001, we adopted Statement of Financial Accounting
Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities" as amended by Statement of Financial Accounting Standards No. 137,
"Accounting for Derivative Instruments and Hedging Activities -- Deferral of the
Effective Date of FASB Statement No. 133" and No. 138, "Accounting for Certain
Derivative Instruments and Certain Hedging Activities". SFAS No. 133 established
accounting and reporting standards requiring that every derivative financial
instrument (including certain derivative instruments embedded in other
contracts) be recorded in the balance sheet as either an asset or liability
measured at its fair value. SFAS No. 133 requires that changes in the
derivative's fair value be recognized currently in earnings unless specific
hedge accounting criteria are met. If the derivatives meet those criteria, SFAS
No. 133 allows a derivative's gains and losses to offset related results on the
hedged item in the income statement, and requires that a company formally
designate a derivative as a hedge and document and assess the effectiveness of
derivatives associated with transactions that receive hedge accounting. As a
result of our adoption of SFAS No. 133, we recorded a cumulative effect
adjustment in other comprehensive income of $22.8 million representing the fair
value of our derivative financial instruments utilized for hedging activities as
of January 1, 2001. During the year ended December 31, 2001, $16.6 million of
this initial adjustment was reclassified to earnings as a result of hedged sales
and purchases during the period.

     Purchases or sales of commodity contracts require a dollar amount to be
placed in margin accounts. In addition, through KMI, we are required to post
margins with certain over-the-counter swap partners. These margin requirements
are determined based upon credit limits and mark-to-market positions. Our margin
deposits associated with commodity contract positions were $20.0 million at
December 31, 2001 and $7.0 million on December 31, 2000. Our margin deposits
associated with over-the-counter swap partners were ($42.1) million on December
31, 2001 and $0.0 on December 31, 2000.

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

     We reclassify the gains and losses included in accumulated other
comprehensive income into earnings as the hedged sales and purchases take place.
We expect to reclassify approximately $45.4 million of the accumulated other
comprehensive income balance of $63.8 million representing unrecognized net
gains on derivative activities at December 31, 2001 into earnings during the
next twelve months. During 2001, we did not reclassify any gains or losses into
earnings as a result of the discontinuance of cash flow hedges due to a
determination that the forecasted transactions will no longer occur by the end
of the originally specified time period.

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

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<PAGE>

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

     As of December 31, 2001, our commodity contracts and over-the-counter swaps
and options (in thousands) consisted of the following:

<Table>
<Caption>
                                                                   OVER THE
                                                                   COUNTER
                                                                  SWAPS AND
                                                      COMMODITY    OPTIONS
                                                      CONTRACTS   CONTRACTS      TOTAL
                                                      ---------   ----------   ----------
                                                            (DOLLARS IN THOUSANDS)
<S>                                                   <C>         <C>          <C>
Deferred Net (Loss) Gain............................  $ 20,957    $   35,901   $   56,858
Contract Amounts -- Gross...........................  $339,456    $1,436,291   $1,775,747
Contract Amounts -- Net.............................  $(90,036)   $ (227,979)  $ (318,015)

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

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

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

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

     - ceased to account for those derivatives as hedges;

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

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

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<PAGE>

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

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

  INTEREST RATE SWAPS

     In order to maintain a cost effective capital structure, it is our policy
to borrow funds using a mix of fixed rate debt and variable rate debt. Since
August 1998, we have entered into interest rate swap agreements for the purpose
of hedging the interest rate risk associated with our variable rate debt
obligations. In the third quarter of 2001, we elected to adjust our mix to be
closer to our target ratio of 50% fixed rate debt and 50% variable rate debt.
Accordingly, in August 2001, we entered into interest rate swap agreements with
a notional principal amount of $750 million for the purpose of hedging the
interest rate risk associated with our fixed rate debt obligations. These
agreements effectively convert the interest expense associated with the
following series of our senior notes from fixed rates to variable rates based on
an interest rate of LIBOR plus a spread:

     - 8.0% senior notes due March 15, 2005;

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

     - 7.40% senior notes due March 15, 2031.

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

     These swaps have been designated as fair value hedges as defined by SFAS
No. 133. These swaps also meet the conditions required to assume no
ineffectiveness under SFAS No. 133 and, therefore, we have accounted for them
using the "shortcut" method prescribed for fair value hedges by SFAS No. 133.
Accordingly, we will adjust the carrying value of each swap to its fair value
each quarter, with an offsetting entry to adjust the carrying value of the debt
securities whose fair value is being hedged. We will record interest expense
equal to the variable rate payments, which will be accrued monthly and paid
semi-annually. At December 31, 2001, we recognized a liability of $5.4 million
for the net fair value of our swap agreements and we included this amount with
Other Long-Term Liabilities and Deferred Credits on the accompanying balance
sheet.

15.  REPORTABLE SEGMENTS

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

     - Products Pipelines;

     - Natural Gas Pipelines;

     - CO(2) Pipelines; and

     - Terminals.

     Each segment uses the same accounting policies as those described in the
summary of significant accounting policies (see Note 2). We evaluate performance
based on each segments' earnings, which exclude general and administrative
expenses, third-party debt costs, interest income and expense and minority
interest. Our reportable segments are strategic business units that offer
different products and services. Each segment is managed separately because each
segment involves different products and marketing strategies.

                                       121
<PAGE>

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

     Financial information by segment follows (in thousands):

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

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

                                       122
<PAGE>

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

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

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

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

                                       123
<PAGE>

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

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

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

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

16.  LITIGATION AND OTHER CONTINGENCIES

     The tariffs charged for interstate common carrier pipeline transportation
for our pipelines are subject to rate regulation by the Federal Energy
Regulatory Commission ("FERC") under the Interstate Commerce Act. The Interstate
Commerce Act requires, among other things, that petroleum products pipeline
rates be just and reasonable and non-discriminatory. Pursuant to FERC Order No.
561, effective January 1, 1995, petroleum products pipelines are able to change
their rates within prescribed ceiling levels that are tied to an inflation
index. FERC Order No. 561-A, affirming and clarifying Order No. 561, expands the
circumstances under which petroleum products pipelines may employ
cost-of-service ratemaking in lieu of the indexing methodology, effective
January 1, 1995. For each of the years ended December 31, 2001, 2000 and 1999,
the application of the indexing methodology did not significantly affect our
tariff rates.

                                       124
<PAGE>

  FEDERAL ENERGY REGULATORY COMMISSION PROCEEDINGS

  SFPP, L.P.

     SFPP, L.P. is the subsidiary limited partnership that owns our Pacific
operations, excluding the CALNEV pipeline and related terminals acquired from
GATX Corporation. Tariffs charged by SFPP are subject to certain proceedings
involving shippers' complaints regarding the interstate rates, as well as
practices and the jurisdictional nature of certain facilities and services, on
our Pacific operations' pipeline systems. In September 1992, El Paso Refinery,
L.P. filed a protest/complaint with the FERC:

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

     - challenging SFPP's proration policy; and

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

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

     - Chevron U.S.A. Products Company;

     - Navajo Refining Company;

     - ARCO Products Company;

     - Texaco Refining and Marketing Inc.;

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

     - Mobil Oil Corporation; and

     - Tosco Corporation.

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

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

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

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

     - the level of income tax allowance; and

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

                                       125
<PAGE>

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

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

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

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

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

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

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

                                       126
<PAGE>

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

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

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

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

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

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

     - elimination of civil litigation costs;

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

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

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

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

     - dismiss the Chevron, RHC and SFPP petitions; and

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

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

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

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

                                       127
<PAGE>

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

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

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

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

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

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

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

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

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

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

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

                                       128
<PAGE>

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

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

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

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

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

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

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

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

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

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

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

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

     - should have calculated the supplemental cost surcharge differently;

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

     - failed to estimate potential reparations for ARCO.

                                       129
<PAGE>

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

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

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

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

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

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

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

                                       130
<PAGE>

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

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

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

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

     The complainants have alleged a variety of grounds for finding
"substantially changed circumstances," including the acquisition of SFPP and
cost savings achieved subsequent to the acquisition. Applicable rules and
regulations in this field are vague, relevant factual issues are complex and
there is little precedent available regarding the factors to be considered or
the method of analysis to be employed in making a determination of
"substantially changed circumstances," which is the showing necessary to make
"grandfathered" rates subject to challenge. Given the newness of the
grandfathering standard under the Energy Policy Act and limited precedent, we
cannot predict how these allegations will be viewed by the FERC.

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

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

                                       131
<PAGE>

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

  CALNEV PIPE LINE LLC

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

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

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

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

  California Public Utilities Commission Proceeding

     ARCO, Mobil and Texaco filed a complaint against SFPP with the California
Public Utilities Commission on April 7, 1997. The complaint challenges rates
charged by SFPP for intrastate transportation of refined petroleum products
through its pipeline system in the State of California and requests prospective
rate adjustments. On October 1, 1997, the complainants filed testimony seeking
prospective rate reductions aggregating approximately $15 million per year.

     On August 6, 1998, the CPUC issued its decision dismissing the
complainants' challenge to SFPP's intrastate rates. On June 24, 1999, the CPUC
granted limited rehearing of its August 1998 decision for the purpose of
addressing the proper ratemaking treatment for partnership tax expenses, the
calculation of environmental costs and the public utility status of SFPP's
Sepulveda Line and its Watson Station gathering enhancement facilities. In
pursuing these rehearing issues, complainants seek prospective rate reductions
aggregating approximately $10 million per year.

                                       132
<PAGE>

     On March 16, 2000, SFPP filed an application with the CPUC seeking
authority to justify its rates for intrastate transportation of refined
petroleum products on competitive, market-based conditions rather than on
traditional, cost-of-service analysis.

     On April 10, 2000, ARCO and Mobil filed a new complaint with the CPUC
asserting that SFPP's California intrastate rates are not just and reasonable
based on a 1998 test year and requesting the CPUC to reduce SFPP's rates
prospectively. The amount of the reduction in SFPP rates sought by the
complainants is not discernible from the complaint.

     The rehearing complaint was heard by the CPUC in October 2000 and the April
2000 complaint and SFPP's market-based application were heard by the CPUC in
February 2001. All three matters stand submitted as of April 13, 2001, and a
decision addressing the submitted matters is expected at any time.

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

  SOUTHERN PACIFIC TRANSPORTATION COMPANY EASEMENTS

     SFPP and Southern Pacific Transportation Company are engaged in a judicial
reference proceeding to determine the extent, if any, to which the rent payable
by SFPP for the use of pipeline easements on rights-of-way held by SPTC should
be adjusted pursuant to existing contractual arrangements (Southern Pacific
Transportation Company vs. Santa Fe Pacific Corporation, SFP Properties, Inc.,
Santa Fe Pacific Pipelines, Inc., SFPP, L.P., et al., Superior Court of the
State of California for the County of San Francisco, filed August 31, 1994).
Although SFPP received a favorable ruling from the trial court in May 1997, in
September 1999, the California Court of Appeals remanded the case back to the
trial court for further proceeding. SFPP is accruing amounts for payment of the
rental for the subject rights-of-way consistent with our expectations of the
ultimate outcome of the proceeding. We expect this matter to go to trial during
the second quarter of 2002.

  FERC ORDER 637

  Kinder Morgan Interstate Gas Transmission LLC

     On June 15, 2000, Kinder Morgan Interstate Gas Transmission LLC made its
filing to comply with FERC's Orders 637 and 637-A. That filing contained KMIGT's
compliance plan to implement the changes required by FERC dealing with the way
business is conducted on interstate natural gas pipelines. All interstate
natural gas pipelines were required to make such compliance filings, according
to a schedule established by FERC. From October 2000 through June 2001, KMIGT
held a series of technical and phone conferences to identify issues, obtain
input, and modify its Order 637 compliance plan, based on comments received from
FERC Staff and other interested parties and shippers. On June 19, 2001, KMIGT
received a letter from FERC encouraging it to file revised pro-forma tariff
sheets, which reflected the latest discussions and input from parties into its
Order 637 compliance plan. KMIGT made such a revised Order 637 compliance filing
on July 13, 2001. The July 13, 2001 filing contained little substantive change
from the original pro-forma tariff sheets that KMIGT originally proposed on June
15, 2000. On October 19, 2001, KMIGT received an order from FERC, addressing its
July 13, 2001 Order 637 compliance plan. In this Order addressing the July 13,
2001 compliance plan, KMIGT's plan was accepted, but KMIGT was directed to make
several changes to its tariff, and in doing so, was directed that it could not
place the revised tariff into effect until further order of the Commission.
KMIGT filed its compliance filing with the October 19, 2001 Order on November
19, 2001 and also filed a request for rehearing/clarification of the FERC's
October 19, 2001 Order on November 19, 2001. The November 19, 2001 Compliance
filing has been protested by several parties. KMIGT filed responses to those
protests on December 14, 2001. At this time, it is unknown when this proceeding
will be finally resolved. KMIGT currently expects that it may not have a fully
compliant Order 637 tariff approved and in effect until sometime in the first or
second quarter of 2002. The full impact of implementation of Order 637 on the
KMIGT system is under evaluation. We believe that these matters will not have a
material adverse effect on our business, financial position or results of
operations.

                                       133
<PAGE>

     Separately, numerous petitioners, including KMIGT, have filed appeals of
Order 637 in the D.C. Circuit, potentially raising a wide array of issues
related to Order 637 compliance. Initial briefs were filed on April 6, 2001,
addressing issues contested by industry participants. Oral arguments on the
appeals were held before the courts in December 2001 and final action is
pending.

  Trailblazer Pipeline Company

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

     - segmentation;

     - scheduling for capacity release transactions;

     - receipt and delivery point rights;

     - treatment of system imbalances;

     - operational flow orders;

     - penalty revenue crediting; and

     - right of first refusal language.

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

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

  STANDARDS OF CONDUCT RULEMAKING

     On September 27, 2001, FERC issued a Notice of Proposed Rulemaking in
Docket No. RM01-10 in which it proposed new rules governing the interaction
between an interstate natural gas pipeline and its affiliates. If adopted as
proposed, the Notice of Proposed Rulemaking could be read to limit
communications between KMIGT, Trailblazer Pipeline Company and their respective
affiliates. In addition, the Notice could be read to require separate staffing
of KMIGT and its affiliates, and Trailblazer and its affiliates. Comments on the
Notice of Proposed Rulemaking were due December 20, 2001. We believe that these
matters, as finally adopted, will not have a material adverse effect on our
business, financial position or results of operations.

  CARBON DIOXIDE LITIGATION

     Kinder Morgan CO(2) Company, L.P. directly or indirectly through its
ownership interest in the Cortez Pipeline Company, along with other entities, is
a defendant in several actions in which the plaintiffs allege that the
defendants undervalued carbon dioxide produced from the McElmo Dome field and
overcharged for transportation costs, thereby allegedly underpaying royalties
and severance tax payments. The plaintiffs, who are seeking monetary damages and
injunctive relief, are comprised of royalty, overriding royalty and small share
working interest owners who claim that they were underpaid by the defendants.
These cases are: CO(2) Claims Coalition, LLC v. Shell Oil Co., et al., No.
96-Z-2451 (U.S.D.C. Colo. filed 8/22/96); Rutter & Wilbanks et al. v. Shell Oil
Co., et al., No. 00-Z-1854 (U.S.D.C. Colo. filed 9/22/00);

                                       134
<PAGE>

Watson v. Shell Oil Co., et al., No. 00-Z-1855 (U.S.D.C. Colo. filed 9/22/00);
Ainsworth et al. v. Shell Oil Co., et al., No. 00-Z-1856 (U.S.D.C. Colo. file
9/22/00); United States ex rel. Crowley v. Shell Oil Company, et al., No.
00-Z-1220 (U.S.D.C. Colo. filed 6/13/00); Ptasynski et al. v. Shell Western E&P
Inc., et al., No. 99-11049 (U.S. Ct. App. 5th Cir. filed 5/21/97 ); Shell
Western E&P Inc. v. Bailey, et al., No. 98-28630 (215th Dist. Ct. Harris County,
Tex. filed 6/17/98); Shores, et al. v. Mobil Oil Corporation, et al., No.
GC-99-01184 (Texas Probate Court, Denton County filed 12/22/99); First State
Bank of Denton v. Mobil Oil Corporation, et al., No. PR-8552-01 (Texas Probate
Court, Denton County filed 3/29/01); and Celeste C. Grynberg v. Shell Oil
Company, et al., No. 98-CV-43 (Colo. Dist. Ct. Montezuma County filed 3/21/98).

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

     Cause No. 4519, in the District Court, Zapata County Texas, 49th Judicial
District. On October 15, 2001, Kinder Morgan Energy Partners, L.P. was served
with the First Supplemental Petition filed by RSM Production Corporation on
behalf of the County of Zapata, State of Texas and Zapata County Independent
School District as plaintiffs. Kinder Morgan Energy Partners, L.P. was sued in
addition to 15 other defendants, including two other Kinder Morgan affiliates.
The Petition alleges that these taxing units relied on the reported volume and
analyzed heating content of natural gas produced from the wells located within
the appropriate taxing jurisdiction in order to properly assess the value of
mineral interests in place. The suit further alleges that the defendants
undermeasured the volume and heating content of that natural gas produced from
privately owned wells in Zapata County, Texas. The Petition further alleges that
the County and School District were deprived of ad valorem tax revenues as a
result of the alleged undermeasurement of the natural gas by the defendants.
Defendants have sought an extension of time to answer, and have not yet
responded to the Petition. There are no further pretrial proceedings at this
time.

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

     Cause No. 99-1390-CM, United States District Court for the District of
Kansas. This action was originally filed in Kansas state court in Stevens
County, Kansas as a class action against approximately 245 pipeline companies
and their affiliates, including certain Kinder Morgan entities. The plaintiffs
in the case seek to have the Court certify the case as a class action. The
plaintiffs are natural gas producers and fee royalty owners who allege that they
have been subject to systematic mismeasurement of natural gas by the defendants
for more than 25 years. Among other things, the plaintiffs allege a conspiracy
among the pipeline industry to under-measure natural gas and have asserted joint
and several liability against the defendants. Subsequently, one of the
defendants removed the action to Kansas Federal District Court. Thereafter, we
filed a motion with the Judicial Panel for Multidistrict Litigation to
consolidate this action for pretrial purposes with the Grynberg False Claim Act,
styled as United States of America, ex rel., Jack J. Grynberg v. K N Energy,
Civil Action No. 97-D-1233, filed in the United States District Court, District
of Colorado, because of common factual questions. On April 10, 2000, the
Multidistrict Litigation Panel ordered that this case be consolidated with the
Grynberg federal False Claims Act cases. On January 12, 2001, the Federal
District Court of Wyoming issued an oral ruling remanding the case back to the
State Court in Stevens County, Kansas. A case management conference recently
occurred in State Court in Stevens County, and a briefing schedule was
established for preliminary matters. Personal jurisdiction discovery has
commenced. Merits discovery has not commenced.

     Although no assurances can be given, we believe that we have meritorious
defenses to all of these actions, that we have established an adequate reserve
to cover potential liability, and that these matters will not have a material
adverse effect on our business, financial position or results of operations.

  ENVIRONMENTAL MATTERS

     We are subject to environmental cleanup and enforcement actions from time
to time. In particular, the federal Comprehensive Environmental Response,
Compensation and Liability Act (CERCLA) generally imposes joint and several
liability for cleanup and enforcement costs on current or predecessor owners and
operators of a site, without regard to fault or the legality of the original
conduct. Our

                                       135
<PAGE>

operations are also subject to federal, state and local laws and regulations
relating to protection of the environment. Although we believe our operations
are in substantial compliance with applicable environmental regulations, risks
of additional costs and liabilities are inherent in pipeline and terminal
operations, and there can be no assurance that we will not incur significant
costs and liabilities. Moreover, it is possible that other developments, such as
increasingly stringent environmental laws, regulations and enforcement policies
thereunder, and claims for damages to property or persons resulting from our
operations, could result in substantial costs and liabilities to us.

     We are currently involved in the following governmental proceedings related
to compliance with environmental regulations associated with our assets:

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

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

     - groundwater and soil remediation efforts under administrative orders
       issued by various regulatory agencies on those assets purchased from GATX
       Corporation, comprising Kinder Morgan Liquids Terminals LLC, CALNEV Pipe
       Line LLC and Central Florida Pipeline LLC.

     In addition, we are from time to time involved in civil proceedings
relating to damages alleged to have occurred as a result of accidental leaks or
spills of refined petroleum products, natural gas liquids, natural gas and
carbon dioxide.

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

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

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

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

     - $1.5 million compensatory damages to Clay Chandler; and

     - $37 million punitive damages.

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

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

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

                                       136
<PAGE>

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

  OTHER

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

17.  QUARTERLY FINANCIAL DATA (UNAUDITED)

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

                                       137
<PAGE>

                                   SIGNATURES

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

                                          KINDER MORGAN ENERGY PARTNERS, L.P.
                                          (A Delaware Limited Partnership)

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

                                          By: KINDER MORGAN MANAGEMENT, LLC,
                                              its Delegate

                                              By:  /s/ JOSEPH LISTENGART
                                              ----------------------------------
                                                      Joseph Listengart,
                                               Vice President, General Counsel
                                                          and Secretary

Date: February 18, 2002

     Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons in the capacities and on
the dates indicated.

<Table>
<Caption>
                    SIGNATURE                                     TITLE                       DATE
                    ---------                                     -----                       ----
<S>     <C>                                          <C>                                <C>

              /s/ RICHARD D. KINDER                  Chairman of the Board and Chief    February 18, 2002
 ------------------------------------------------      Executive Officer of Kinder
                Richard D. Kinder                    Morgan Management, LLC, Delegate
                                                       of Kinder Morgan G.P., Inc.


              /s/ WILLIAM V. MORGAN                   Director and Vice Chairman of     February 18, 2002
 ------------------------------------------------     Kinder Morgan Management, LLC,
                William V. Morgan                              Delegate of
                                                         Kinder Morgan G.P., Inc.


              /s/ EDWARD O. GAYLORD                     Director of Kinder Morgan       February 18, 2002
 ------------------------------------------------      Management, LLC, Delegate of
                Edward O. Gaylord                        Kinder Morgan G.P., Inc.


              /s/ GARY L. HULTQUIST                     Director of Kinder Morgan       February 18, 2002
 ------------------------------------------------      Management, LLC, Delegate of
                Gary L. Hultquist                        Kinder Morgan G.P., Inc.
</Table>

                                       138
<PAGE>

<Table>
<Caption>
                    SIGNATURE                                     TITLE                       DATE
                    ---------                                     -----                       ----

<S>     <C>                                          <C>                                <C>

              /s/ PERRY M. WAUGHTAL                     Director of Kinder Morgan       February 18, 2002
 ------------------------------------------------      Management, LLC, Delegate of
                Perry M. Waughtal                        Kinder Morgan G.P., Inc.


                /s/ C. PARK SHAPER                    Vice President, Treasurer and     February 18, 2002
 ------------------------------------------------       Chief Financial Officer of
                  C. Park Shaper                      Kinder Morgan Management, LLC,
                                                     Delegate of Kinder Morgan G.P.,
                                                        Inc. (principal financial
                                                     officer and principal accounting
                                                                 officer)
</Table>

                                       139
<PAGE>

                               INDEX TO EXHIBITS

<Table>
<S>     <C>   <C>
 *3.1     --  Third Amended and Restated Agreement of Limited Partnership
              of Kinder Morgan Energy Partners, L.P. (filed as Exhibit 3.1
              to Kinder Morgan Energy Partners, L.P. Form 10-Q for the
              quarter ended June 30, 2001, filed on August 9, 2001).
 *4.1     --  Specimen Certificate evidencing Common Units representing
              Limited Partner Interests (filed as Exhibit 4.1 to Amendment
              No. 1 to Kinder Morgan Energy Partners, L.P. Registration
              Statement on Form S-4, file No. 333-44519, filed on February
              4, 1998).
 *4.2     --  Indenture dated as of January 29, 1999 among Kinder Morgan
              Energy Partners, L.P. the guarantors listed on the signature
              page thereto and U.S. Trust Company of Texas, N.A., as
              trustee, relating to Senior Debt Securities (filed as
              Exhibit 4.1 to the Partnership's Current Report on Form 8-K
              filed February 16, 1999 (the "February 16, 1999 Form 8-K")).
 *4.3     --  First Supplemental Indenture dated as of January 29, 1999
              among Kinder Morgan Energy Partners, L.P., the subsidiary
              guarantors listed on the signature page thereto and U.S.
              Trust Company of Texas, N.A., as trustee, relating to
              $250,000,000 of 6.30% Senior Notes due February 1, 2009
              (filed as Exhibit 4.2 to the February 16, 1999 Form 8-K).
 *4.4     --  Second Supplemental Indenture dated as of September 30, 1999
              among Kinder Morgan Energy Partners, L.P. and U.S. Trust
              Company of Texas, N.A., as trustee, relating to release of
              subsidiary guarantors under the $250,000,000 of 6.30% Senior
              Notes due February 1, 2009 (filed as Exhibit 4.4 to the
              Partnership's Form 10-Q for the quarter ended September 30,
              1999 (the "1999 Third Quarter Form 10-Q")).
 *4.5     --  Indenture dated March 22, 2000 between Kinder Morgan Energy
              Partners and First Union National Bank, as Trustee (filed as
              Exhibit 4.1 to Kinder Morgan Energy Partners, L.P.
              Registration Statement on Form S-4 (file no. 333-35112)
              filed on April 19, 2000 (the "April 2000 Form S-4")).
 *4.6     --  Form of Floating Rate Note and Form of 8% Note (contained in
              the Indenture filed as Exhibit 4.1 to the April 2000 Form
              S-4).
 *4.7     --  Indenture dated November 8, 2000 between Kinder Morgan
              Energy Partners and First Union National Bank, as Trustee.
 *4.8     --  Form of 7.50% Note (contained in the Indenture filed as
              Exhibit 4.8).
 *4.9     --  Indenture dated January 2, 2001 between Kinder Morgan Energy
              Partners and First Union National Bank, as trustee, relating
              to Senior Debt Securities (including form of Senior Debt
              Securities) (filed as Exhibit 4.11 to Kinder Morgan Energy
              Partners, L.P. Form 10-K for 2000).
 *4.10    --  Indenture dated January 2, 2001 between Kinder Morgan Energy
              Partners and First Union National Bank, as trustee, relating
              to Subordinate Debt Securities (including form of
              Subordinate Debt Securities) (filed as Exhibit 4.12 to
              Kinder Morgan Energy Partners, L.P. Form 10-K for 2000).
 *4.11    --  Certificate of Vice President and Chief Financial Officer of
              Kinder Morgan Energy Partners, L.P. establishing the terms
              of the 6.75% Notes due March 15, 2011 and the 7.40% Notes
              due March 15, 2031 (filed as Exhibit 4.1 to Kinder Morgan
              Energy Partners, L.P. Form 8-K filed March 14, 2001).
 *4.12    --  Specimen of 6.75% Notes due March 15, 2011 in book-entry
              form (filed as Exhibit 4.2 to Kinder Morgan Energy Partners,
              L.P. Form 8-K filed March 14, 2001).
 *4.13    --  Specimen of 7.40% Notes due March 15, 2031 in book-entry
              form (filed as Exhibit 4.3 to Kinder Morgan Energy Partners,
              L.P. Form 8-K filed March 14, 2001).
  4.14    --  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. sec.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     --  Kinder Morgan Energy Partners, L.P. Common Unit Option Plan
              (filed as Exhibit 10.6 to the Partnership's 1997 Form 10-K).
*10.2     --  Employment Agreement with William V. Morgan (filed as
              Exhibit 10.1 to the Partnership's Form 10-Q for the quarter
              ended March 31, 1997).
</Table>
<PAGE>

<Table>
  <C>          <C>
*10.3       -- Kinder Morgan Energy Partners, L.P. Executive Compensation Plan (filed as Exhibit 10 to the
               Partnership's Form 10-Q for the quarter ended June 30, 1997).
*10.4       -- Employment Agreement dated April 20, 2000, by and among Kinder Morgan, Inc., Kinder Morgan G.P., Inc.
               and David G Dehaemers, Jr. (filed as Exhibit 10(a) to Kinder Morgan, Inc.'s Form 10-Q for the quarter
               ended March 31, 2000).
*10.5       -- Employment Agreement dated April 20, 2000, by and among Kinder Morgan, Inc., Kinder Morgan G.P., Inc.
               and Michael C. Morgan (filed as Exhibit 10(b) to Kinder Morgan, Inc.'s Form 10-Q for the quarter ended
               March 31, 2000).
*10.6       -- Delegation of Control Agreement among Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder
               Morgan Energy Partners, L.P. and its operating partnerships (filed as Exhibit 10.1 to the June 30, 2001
               Form 10-Q).
*10.7       -- Retention Agreement dated January 17, 2002, by and between Kinder Morgan, Inc. and C. Park Shaper (filed
               as Exhibit 10(l) to Kinder Morgan, Inc.'s 2001 Annual Report on Form 10-K).
 10.8       -- Form of Credit Agreement dated as of October 25, 2000 among Kinder Morgan Energy Partners, L.P. and the
               lenders party thereto.
 10.9       -- Form of First Amendment to Credit Agreement dated as of January 31, 2001 among Kinder Morgan Energy
               Partners, L.P. and the lenders party thereto.
 10.10      -- Form of Second Amendment to Credit Agreement dated as of October 24, 2001 among Kinder Morgan Energy
               Partners, L.P. and the lenders party thereto.
 21.1       -- List of Subsidiaries
 23.1       -- Consent of PricewaterhouseCoopers LLP
</Table>

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

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