<PAGE>   1
                       SECURITIES AND EXCHANGE COMMISSION
                             WASHINGTON, D.C. 20549


                                   ----------

                                   FORM 10-K/A
                                 AMENDMENT NO. 2

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


                                   ----------

                  For the fiscal year ended DECEMBER 31, 2000
                        Commission file number: 1-11234


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


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


               500 DALLAS STREET, SUITE 1000, HOUSTON, TEXAS 77002
               (Address of principal executive offices)(zip code)
        Registrant's telephone number, including area code: 713-369-9000

                                   ----------

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


Title of each class                   Name of each exchange on which registered
-------------------                   -----------------------------------------
Common Units of Kinder Morgan                   New York Stock Exchange
Energy Partners, L.P.


           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 February 28, 2001 was approximately
$3,100,957,450. This figure assumes that only the general partner of the
registrant, Kinder Morgan, Inc. and officers and directors of the general
partner of the registrant and of Kinder Morgan, Inc. were affiliates. As of
February 28, 2001, the registrant had 64,861,509 Common Units outstanding.

<PAGE>   2



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

<TABLE>
<CAPTION>
                                                                                     PAGE NO.
<S>               <C>                                                                <C>

                                     PART I

Items 1 and 2.    Business and Properties                                                 3

Item 3.           Legal Proceedings                                                      47

Item 4.           Submission of Matters to a Vote of Security Holders                    47

                                     PART II

Item 5.           Market for the Registrant's Units and Related Security Holder
                   Matters                                                               48

Item 6.           Selected Financial Data                                                49

Item 7.           Management's Discussion and Analysis of Financial Condition
                   and Results of Operation                                              50

Item 7a.          Quantitative and Qualitative Disclosures About Market Risk             63

Item 8.           Financial Statements and Supplementary Data                            64

Item 9.           Changes in and Disagreements on Accounting and Financial
                   Disclosure                                                            64

                                   PART III

Item 10.          Directors and Executive Officers of the Registrant                     65

Item 11.          Executive Compensation                                                 68

Item 12.          Security Ownership of Certain Beneficial Owners and Management         72

Item 13.          Certain Relationships and Related Transactions                         73


                                   PART IV

Item 14.          Exhibits, Financial Statement Schedules, and Reports on Form 8-K       75

Financial Statements                                                                    F-1

Signatures                                                                              S-1
</TABLE>





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                                     PART I

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

GENERAL

     Kinder Morgan Energy Partners, L.P., a Delaware limited partnership, is a
publicly traded master limited partnership formed in August 1992. We are the
largest pipeline master limited partnership in terms of market capitalization
and the second largest 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 manage a diversified portfolio of midstream energy assets that provide
fee-based services to customers. Our assets primarily include:

     o    more than 10,000 miles of product pipelines and over 20 associated
          terminals serving customers across the United States;

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

     o    Kinder Morgan CO2 Company, L.P., the largest transporter and
          marketer of carbon dioxide in the country; and

     o    over 25 bulk terminal facilities which transload coal, liquid and
          other 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 generating 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 is name to Kinder Morgan, Inc. In
connection with the acquisition, Richard Kinder, Chairman and Chief Executive
Officer of our general partner, 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 midstream energy companies in America, operating more than
30,000 miles of natural gas and product pipelines. KMI also has significant
natural gas retail distribution and electric generation. In addition, KMI,
through its general partner interest, operates our portfolio of businesses and
holds a significant limited partner interest in us.

     The address of our principal executive offices is 500 Dallas Street, Suite
1000, Houston, Texas 77002 and our telephone number at this address is (713)
369-9000. We trade under the New York Stock Exchange symbol "KMP". Our
operations are grouped into four reportable business segments. These segments
and their major assets are as follows:

     o    Product Pipelines, consisting of refined petroleum product pipelines
          and joint venture projects including:

          o    our Pacific operations, which are comprised of approximately
               3,300 miles of pipeline that transport 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 and
               Tucson and Phoenix, Arizona, and 13 truck-loading terminals with
               an aggregate usable tankage capacity of approximately 8.2 million
               barrels;

          o    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;

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

          o    our 32.5% interest in the Cochin Pipeline System, a 1,900 mile
               multiproduct pipeline transversing Canada and the United States
               from Fort Saskatchewan, Alberta to Sarnia, Ontario;

          o    our Cypress Pipeline, which transports natural gas liquids from
               Mont Belvieu, Texas to a major petrochemical producer in Lake
               Charles, Louisiana;



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

          o    our 50% interest in the Heartland Pipeline Company, which ships
               refined petroleum products in the Midwest; and

          o    our Painter Gas Processing Plant, a natural gas processing plant,
               fractionator and natural gas liquids terminal with truck and rail
               loading facilities, which is leased to BP Amoco under a long-term
               arrangement.

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

          o    Kinder Morgan Interstate Gas Transmission LLC, which owns a 6,700
               mile natural gas pipeline, including the Pony Express pipeline
               facilities, that extends from northwestern Wyoming east into
               Nebraska and Missouri and south through Colorado and Kansas;

          o    Kinder Morgan Texas Pipeline L.P, which owns a 2,700 mile
               intrastate pipeline along the Texas Gulf Coast;

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

          o    our Casper and Douglas Gathering Systems, which is 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;

          o    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;

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

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

     o    CO2 Pipelines, consisting of Kinder Morgan CO2 Company, L.P.,
          which transports, markets and produces carbon dioxide for use in
          enhanced oil recovery operations in the continental United States,
          through the following:

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

          o    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;

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

          o    interests in oil-producing fields, including an approximate 71%
               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.

     o    Bulk Terminals, consisting of over 25 owned or operated bulk terminal
          facilities including:

          o    coal terminals located in Cora, Illinois; Paducah, Kentucky;
               Newport News, Virginia; Mount Vernon, Indiana; and Los Angeles,
               California;

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

          o    liquids chemical terminals located in New Orleans, Louisiana and
               Cincinnati, Ohio; and

          o    other bulk terminals 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:

     o    focusing on stable, fee-based assets which are core to the energy
          infrastructure of growing markets;

     o    increasing utilization of assets while containing costs;


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     o    leveraging economies of scale from incremental acquisitions; and

     o    maximizing the benefits of our financial structure.

     Since February 1997, we have announced 20 acquisitions valued at over $4.7
billion. These acquisitions and associated cost reductions have assisted us in
growing from $17.7 million of net income in 1997 to $278.3 million of net income
in 2000. 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 purchase and sale of commodity products. As a result, we do
not face significant risks relating directly to shifts in commodity prices.

     Product 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 our Pacific and
Plantation pipelines and through acquisitions that 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. We recently
assumed operation of Plantation Pipe Line Company. Our acquisition of our
transmix operations in September 1999, October 2000 and December 2000
strengthened our existing transmix processing business and added fee-based
services related to our core refined products pipeline business.

     Natural Gas Pipelines. Kinder Morgan Interstate Gas Transmission also
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 L.P. 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 pursuing an expansion
of its system supported by 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.

     CO2 Pipelines. KMCO2'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.

     Bulk Terminals. We are dedicated to growing our bulk terminals business
through selective acquisitions, expansions, and development of new terminals.
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.

RECENT DEVELOPMENTS

     During 2000, our assets increased 43% and our net income increased 53% from
1999 levels. In addition, distributions per unit increased 31% from $0.725 for
the fourth quarter of 1999 to $0.95 for the fourth quarter of 2000.

     The following is a brief listing of activity since the end of the third
quarter of 2000. Additional information regarding these items is contained in
the rest of this report.

     o    On October 25, 2000, we acquired Kinder Morgan Transmix Company, LLC,
          formerly known as Buckeye Refining Company, LLC, for approximately $37
          million plus net working capital. The acquisition included two
          transmix processing plants located in Indianola, Pennsylvania and Wood
          River, Illinois and other transmix assets. The two facilities are
          projected to process over 4.3 million barrels of transmix in 2001.



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<PAGE>   6
     o    On October 25, 2000, we entered into a new $600 million 364-day bank
          revolving facility that replaced and expanded our then existing $300
          million facility and contains substantially the same covenants. In
          August 2000, we refinanced a fully drawn $175 million revolving credit
          facility at our subsidiary, SFPP, L.P., with an intercompany
          obligation to us.

     o    On November 8, 2000, we closed on a private placement of $250 million
          of 10-year notes bearing a coupon of 7.5%. On February 27, 2001, we
          announced an offer to exchange these notes for substantially identical
          notes that are registered under the Securities Act of 1933. The
          exchange offer expires on March 27, 2001, unless extended by us at our
          sole discretion.

     o    On November 30, 2000, we announced that we had signed a definitive
          agreement with GATX Corporation to purchase its United States pipeline
          and terminal businesses for approximately $1.15 billion, consisting of
          cash, assumed debt and other obligations. Primary assets included in
          the transaction are the CALNEV Pipe Line Company and the Central
          Florida Pipeline Company, along with 12 terminals that store refined
          petroleum products and chemicals. CALNEV is a 550 mile refined
          petroleum products pipeline system originating in Colton, California
          and extending to the Las Vegas, Nevada market. The Central Florida
          pipeline is a 195 mile refined petroleum products pipeline system
          consisting of a 16-inch gasoline pipeline and a 10-inch jet fuel and
          diesel pipeline, transporting product from Tampa to the Orlando,
          Florida market. The 12 terminals we are acquiring from GATX have a
          storage capacity of 35.6 million barrels, and the largest of these
          terminals are located in Houston, New York, Los Angeles and Chicago,
          with a total capacity of approximately 31.2 million barrels. The other
          terminals are located in Philadelphia, Portland, Oregon, San Francisco
          and Seattle. In addition, we are acquiring six other terminals from
          GATX with a capacity of 3.6 million barrels that are part of the
          CALNEV and Central Florida pipeline systems. On March 1, 2001, we
          announced that all of the assets in the transaction have closed,
          except for CALNEV, which closed on March 30, 2001.

     o    On December 1, 2000, we purchased Delta Terminal Services, Inc. for
          approximately $114 million in cash. The acquisition included two
          liquid bulk storage terminals in New Orleans, Louisiana and
          Cincinnati, Ohio. The facilities provide services to producers of
          petroleum, chemicals and other products. The New Orleans terminal has
          a storage capacity of 2.8 million barrels. It is located at the 98.5
          mile point on the Mississippi River close to the Harvey Canal and the
          Greater New Orleans Bridge. The terminal serves the New Orleans/Baton
          Rouge corridor and is situated on approximately 100 acres of land. The
          Cincinnati terminal has a storage capacity of 500,000 barrels. It is
          located at the 465.7 mile point on the Ohio River and is situated on
          approximately 60 acres of land.

     o    On December 21, 2000, we reached agreement with the other owner of
          Plantation Pipe Line Company to become the operator of Plantation, a
          3,100-mile refined petroleum products pipeline system throughout the
          southeastern United States.

     o    On December 21, 2000, we completed a transaction whereby KMI
          contributed approximately $300 million of its assets to us. As
          consideration for these assets, we paid KMI approximately 50% of the
          fair value of the assets in cash and the remaining 50% of the fair
          value of the assets in units. The largest asset contributed was Kinder
          Morgan Texas Pipeline L.P., a 2,700 mile natural gas pipeline system
          that extends from south Texas to Houston along the Texas gulf coast.
          Other assets contributed included the Casper and Douglas Natural Gas
          Gathering and Processing Systems, KMI's 50% interest in Coyote Gas
          Treating, LLC and KMI's 25% interest in Thunder Creek Gas Services,
          LLC.

     o    On December 28, 2000, we completed the purchase of a 32.5% interest in
          the Cochin Pipeline System from NOVA Chemicals Corporation. The
          effective date of the acquisition was November 3, 2000. The Cochin
          pipeline consists of approximately 1,900 miles of 12-inch pipeline
          transversing Canada and the United States from Fort Saskatchewan,
          Alberta to Sarnia, Ontario. It transports high vapor pressure ethane,
          ethylene, propane, butane and natural gas liquids to the midwestern
          United States and eastern Canadian petrochemical and fuel markets, and
          is a joint venture of our subsidiary and subsidiaries of BP Amoco,
          Conoco, Shell and NOVA Chemicals.

     o    On December 28, 2000, we 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 was formed on January 1, 2001 and is
          owned 85% by Marathon Oil Company and 15% by KMCO2. The joint
          venture consists of a nearly 13% interest in the SACROC Unit and a
          49.9% interest in the Yates oil field, the largest single interest in
          that Unit. In connection with the formation of the joint venture, we
          entered into a 10 year contract to supply Marathon with an aggregate
          of 30 billion cubic feet of carbon dioxide expected to be used to
          enhance oil recovery in the area.


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<PAGE>   7

     o    On December 31, 2000, we increased our ownership in the Colton,
          California transmix processing facility by purchasing Duke Energy
          Merchants' 50% interest in the facility. SFPP, L.P., our subsidiary
          that owns our Pacific operations, owns the remaining 50% ownership
          interest. The facility's transmix processing agreements with third
          parties were transferred to Duke, and in turn, we entered into a ten
          year fee-based processing agreement to process transmix for Duke at
          the facility. Duke will market all of the transmix we process for it
          at the Colton facility.

     Kinder Morgan Management, LLC, a wholly-owned subsidiary of our general
partner, has filed a registration statement to issue and sell shares. Upon
completion of that proposed offering, Kinder Morgan Management, LLC would become
a partner in us and manage and control our business and affairs. The net
proceeds from that offering would be used to buy i-units from us. The i-units
would be a new class of our limited partner interests and would be issued only
to Kinder Morgan Management, LLC. We would use the cash received from the sale
of i-units to reduce short-term debt incurred to finance the GATX acquisition.
No assurance can be given that the proposed issuance of shares and related
financing will occur, or that they will not be modified from the foregoing
description if ultimately completed.

PRODUCT 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 non
rate-regulated terminal operations.

     Our Pacific operations are split into a South Region and a North Region.
Combined, the two regions consist of five pipeline segments that serve six
western states with approximately 3,300 miles of refined petroleum products
pipeline and related terminal facilities.

     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, three commercial airports and 12 military bases. For
2000, the three main product types transported were gasoline (61%), diesel fuel
(21%) and jet fuel (18%). Our Pacific operations also include 13 truck-loading
terminals.

     Our Pacific operations provide refined petroleum products to some of the
fastest growing populations 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 positive demographics associated with
the markets served by our Pacific operations will continue in the foreseeable
future.

     South Region. Our Pacific operations' South Region consists of three
pipeline segments: the West Line, East Line and San Diego Line.

     The West Line consists of approximately 570 miles of primary pipeline and
currently transports products for approximately 50 shippers from seven
refineries and three pipeline terminals in the Los Angeles Basin to Phoenix and
Tucson, Arizona and various intermediate commercial and military delivery
points. Also, a significant portion of West Line volumes are transported to
Colton, California for local distribution and for delivery to the CALNEV
pipeline, which carries refined petroleum products to Las Vegas, Nevada and
intermediate points. The West Line serves our terminals located in Colton and
Imperial, California as well as in Tucson and Phoenix. In the fall of 2000, we
completed a $9 million expansion of the West Line from Colton to Phoenix.



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     The East Line is comprised of two parallel lines 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 west Texas and Artesia, New Mexico. The East Line serves our terminals
located in Tucson and Phoenix.

     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. On June 1, 2000, we completed an expansion of the San Diego Line. The
expansion involved construction of 23 miles of 16-inch diameter pipe, and other
appurtenant facilities, across the Camp Pendleton Marine Base just north of
Oceanside, California. The expansion project cost approximately $18 million and
coupled with the completion of supplementary pumping stations in the summer of
2000, the capacity of the San Diego Line has increased from 116,000 barrels per
day to 144,000 barrels per day, an increase of almost 25%. The new facilities
will increase the Pacific operations' capability to transport gasoline, diesel
and jet fuel to customers in the rapidly growing Orange County and San Diego,
California markets.

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

     The North Line consists of approximately 1,075 miles of pipeline in six
segments originating in Richmond, Concord and Bakersfield, California. This line
serves our terminals located in Brisbane, Bradshaw, Chico, Fresno and San Jose,
California, and Sparks, Nevada. The products delivered through the North Line
come from refineries in the San Francisco Bay and Bakersfield areas. The North
Line also receives product transported from various pipeline and marine
terminals that deliver products from foreign and domestic ports. A refinery
located in Bakersfield supplies substantially all of the products shipped
through the Bakersfield-Fresno segment of the North Line.

     The Oregon Line is a 114-mile pipeline serving approximately ten shippers.
Our Oregon Line receives products from marine terminals in Portland, Oregon and
from Olympic Pipeline. Olympic Pipeline is a non-affiliated carrier 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.

     Truck Loading Terminals. Our Pacific operations include 13 truck-loading
terminals with an aggregate usable tankage capacity of approximately 8.2 million
barrels. 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:

     o    short-term product storage;

     o    truck loading;

     o    vapor recovery;

     o    deposit control additive injection;

     o    dye injection;

     o    oxygenate blending; and

     o    quality control.

     The capacity of terminaling facilities varies throughout our Pacific
operations 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. At our terminals, we provide
truck loading and other terminal services. We charge a separate fee (in addition
to pipeline tariffs) for these additional non rate-regulated services.

     Markets. Currently our Pacific operations serve in excess of 100
shippers in the refined products market, with the largest customers consisting
of:

     o    major petroleum companies;

     o    independent refineries;

     o    the United States military; and



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<PAGE>   9

     o    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 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 945,000 barrels per day. The
Arizona gasoline market is served primarily by us at a market demand of 135,000
barrels per day. Nevada's gasoline market is approximately 55,000 barrels per
day and Oregon's is approximately 95,000 barrels per day. The distillate (diesel
and jet fuel) market is approximately 490,000 barrels per day in California,
75,000 barrels per day in Arizona, 50,000 barrels per day in Nevada and 62,000
barrels per day in Oregon. We transport over 1 million barrels of petroleum
products per day in these states.

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

     Supply. The majority of refined products supplied to our Pacific operations
come from the major refining centers around Los Angeles, San Francisco and Puget
Sound, as well as waterborne terminals located near these refining centers.
Transmix is primarily supplied by petroleum pipeline and terminal operations,
including our own pipelines in California and other western states.

     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 the 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. Trucks may competitively deliver products in certain
markets, particularly to shorter-haul destinations in the Los Angeles and San
Francisco Bay areas.

     Longhorn Partners Pipeline is a proposed joint venture project that would
begin transporting refined products from refineries on the Gulf Coast to El Paso
and other destinations in Texas. 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.

     NORTH SYSTEM

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

     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:


                                       9
<PAGE>   10

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

     o    a third pipeline, which extends from Bushton to the Kansas City,
          Missouri area; and

     o    a fourth pipeline that transports product 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 Company
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.

     In 1999, we entered into a long-term agreement with Aux Sable Liquid
Products to transport a significant volume of natural gas liquids in and around
the Chicago area for Aux Sable. We have made modifications to our pipeline
system and our Morris and Lemont, Illinois facilities in order to accommodate
the transportation of natural gas liquids for Aux Sable. The shipments are
expected to begin in late first quarter or early second quarter of 2001. In
2000, we entered into a propane terminaling agreement with Aux Sable and began
service in late fourth quarter.

     The following table sets forth volumes, in thousands of barrels, of natural
gas liquids transported on our North System (excluding Heartland Pipeline
Company) for delivery to the various markets for the periods indicated:

<TABLE>
<CAPTION>
                                         YEAR ENDED DECEMBER 31,
                                2000     1999     1998     1997     1996
                               ------   ------   ------   ------   ------
<S>                            <C>      <C>      <C>      <C>     <C>
Petrochemicals                  1,276    1,059    1,040    1,200      684
Refineries and line reversal   12,020   10,517   10,489   10,600    9,536
Fuels                           7,221    6,172    6,150    7,976   10,500
Other(1)                        8,154    8,379    5,532    7,399    8,126
                               ------   ------   ------   ------   ------
Total                          28,671   26,127   23,211   27,175   28,846
                               ======   ======   ======   ======   ======
</TABLE>

(1) Natural gas liquid gathering systems and Chicago originations other than
long-haul volumes of refinery butanes.

     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, isobutane 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 four 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. KMI has
transferred to ONEOK, Inc. the Bushton plant along with other assets previously
owned by KMI. ONEOK has assumed contracts with us to continue shipping natural
gas liquids through our North System in volumes substantially equal to those
shipped through our North System when KMI owned the Bushton plant.


                                       10
<PAGE>   11

     Competition. Our North System competes with other 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. In the Chicago area, our North System
competes with other natural gas liquid 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 51% of Plantation Pipe Line Company, which owns a 3,100 mile
pipeline system throughout the southeastern Unites States. On December 21, 2000,
we took over the day-to-day operations of Plantation. 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.

     Markets. Plantation ships products for approximately 50 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. In addition, Plantation services the
Atlanta, Georgia; Charlotte, North Carolina; and Washington, D.C. airports
(Ronald Reagan/National and Dulles), at which it delivers jet fuel to major
airlines.

     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 can transport over
600,000 barrels of refined petroleum products per day. In December 1999,
Plantation announced an expansion of its mainline system. The $40 million
development will increase the system's capacity by 70,000 barrels per day. The
first phase of the expansion was completed in the fourth quarter of 2000 and the
entire expansion project should be completed in the second quarter of 2001.

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

     COCHIN PIPELINE SYSTEM

     We own 32.5% of the Cochin Pipeline System, a 1,938 mile 12-inch
multiproduct pipeline operating between Fort Saskatchewan, Alberta and Sarnia,
Ontario.

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

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

     o    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 and an integral part
of the Alberta petrochemical project, the pipeline transverses 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



                                       11
<PAGE>   12

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:

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

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

     o    the Williams Mapco West Junction, in Minnesota.

     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, a major petrochemical
producer 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 for five years. 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 that could 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 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.

     TRANSMIX OPERATIONS

     Our transmix operations consist of:

     o    transmix processing facilities located in Richmond, Virginia and
          Dorsey Junction, Maryland acquired in September 1999 from Primary
          Corporation;

     o    transmix processing facilities located in Indianola, Pennsylvania and
          Wood River, Illinois acquired in October 2000 as part of our
          acquisition of Kinder Morgan Transmix Company, LLC, formerly known as
          Buckeye Refining Company, LLC; and

     o    the Colton Processing Facility located in 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. Employing atmospheric distillation units, we process pipeline
transmix generated in the eastern United States to produce pipeline quality
gasoline and light distillate products. The processing is provided on a "for
fee" basis or on a "purchase, process and sell" basis. The processed material is
returned to the generator of the transmix or is sold into the local market
depending on the type of agreement in place with the generator.

     Our Richmond operating facility resides on an 11-acre site located near
Interstate 95 and adjacent to Virginia's James River. The 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 production capacity of approximately
8,000 barrels per day. The facility is able to segregate feedstock for specialty
fuel production. The processing facility employs state-of-the-art computer based
process control equipment and is supported by comprehensive in-house quality
control laboratory capabilities. The facility is served by both Colonial and
Plantation pipelines, by deep-water barge (25 feet draft) and by transport truck
and 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 operating 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 on a
"for fee" basis.



                                       12
<PAGE>   13

     Our Indianola operating facility is located on a 30-acre site near
Pittsburgh 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 via the Buckeye pipeline as well as by truck.

     Our Wood River operating facility was constructed in 1993 on property owned
by Conoco and is accessible by truck, barge and pipeline, primarily processing
transmix from 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 operating facility, completed in the spring of 1998, and located
adjacent to our products terminal in Colton, California, processes proprietary
transmix on a fee basis for a subsidiary of Duke Energy. The facility produces
refined petroleum products, which are injected into our Pacific operations'
pipelines for delivery to markets in Southern California and Arizona. The
facility processed approximately 4,100 barrels per day during 2000, which is
near the capacity of the facility.

     Markets. The Gulf and East Coast petroleum 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 by long-term contracts. Individual shippers and terminal
operators provide additional supply.

     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 Brothers, who will compete with our expansion efforts into that
market. A number of smaller organizations operate 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 competes with major
oil company refineries and other transmix processing facilities in California
and Arizona.

     HEARTLAND PIPELINE COMPANY

     The Heartland pipeline was completed in the fall of 1990 and is owned by
Heartland Pipeline Company. We and Conoco each own 50% of Heartland. We operate
the pipeline and Conoco operates Heartland's Des Moines terminal and serves as
the managing partner of Heartland. In 2000, Heartland leased Conoco 100% of the
Heartland terminal capacity at Des Moines, Iowa for $1.0 million.

     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 product carriers in
the geographic market served. Heartland's principal competitor is Williams
Pipeline Company.



                                       13
<PAGE>   14

     PAINTER GAS PROCESSING PLANT

     Our Painter Plant is located near Evanston, Wyoming and consists of:

     o    a natural gas processing plant;

     o    a nitrogen rejection unit;

     o    a fractionator;

     o    a natural gas liquids terminal; and

     o    interconnecting pipelines with truck and rail loading facilities.

     The fractionation facility has a capacity of approximately 6,000 barrels
per day, depending on the feedstock composition. We lease the Painter Plant to
Amoco Oil Company, a unit of BP Amoco, which operates the fractionator and the
associated Millis terminal and storage facilities for its own account. BP Amoco
also owns and operates the nearby BP Amoco Painter Complex gas plant.

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 operate 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 and the Midwest, as well as major
consumer markets.

     KINDER MORGAN INTERSTATE GAS TRANSMISSION LLC.

     Through Kinder Morgan Interstate Gas Transmission LLC, we own approximately
6,500 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, including no-notice services.
Under KMIGT's tariffs, firm transportation and storage customers pay reservation
charges each month plus a commodity charge based on actual volumes transported
or stored. Interruptible transportation and storage customers pay a commodity
charge based upon actual volumes transported or stored. Reservation and
commodity charges are both based upon geographical location (KMIGT does not have
seasonal rates) and distance of the transportation service provided. Under
no-notice service, customers pay a fee for the right to use a combination of
firm storage and firm transportation to make deliveries of natural gas up to a
specified volume. No-notice customers are able to meet their peak day
requirements without making specific nominations.

     The system includes 41 transmission, field and storage compressor stations
having an aggregate of approximately 158,981 installed horsepower. The pipeline
system provides storage services to its customers from its Huntsman Storage
Field in Cheyenne County, Nebraska. The facility has 39.4 billion cubic feet of
total storage capacity, 7.9 billion cubic feet of working gas capacity and up to
101 million cubic feet per day of peak withdrawal capacity.

     Markets. Markets served by KMIGT consist of a stable customer base with
expansion opportunities due to the system's access to the growing Rocky Mountain
supply sources. Markets served by KMIGT are comprised mainly of local
distribution companies and interconnecting interstate pipelines in the
mid-continent area. Markets for the local distribution companies can include
residential, commercial, industrial and agricultural customers. KMIGT also
delivers into interconnecting interstate pipelines in the mid-continent area,
which can in turn deliver gas into multiple markets throughout the United
States. Due to the demand for natural gas to run irrigation systems in the
summer, summer loads often equal the levels for the winter heating season.

     Contracts. On a volumetric basis, approximately 23% of KMIGT's firm
contracts expire within one year, 10% expire within one to five years and 67%
expire in more than five years. Out of the 23% of the firm volumes that expire
within one year, 89% of those volumes are with affiliated entities. 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 current



                                       14
<PAGE>   15

cost of service 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 L.P.

     KMTP, acquired in conjunction with the December 31, 2000 transfer of assets
from KMI, operates an intrastate natural gas pipeline system, which is leased
from Occidental Petroleum Corporation under a 30 year lease that commenced on
December 31, 1996. The pipeline system is principally located in the Texas Gulf
Coast area. The system includes approximately 2,700 miles of pipelines, supply
and gathering lines, sales 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/Contracts. 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, on
average, three pipelines connected to their plants. Large local distribution
companies and electric utilities have multiple pipeline connections. Multiple
pipeline connections provide the consumer of natural gas 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
2000, KMTP delivered an average of 1.8 billion cubic feet per day of natural gas
to this area, of which 62% of the deliveries were for sales contracts and 38%
were for transportation contracts.

     During 2000, approximately 58% of KMTP's gross margin was attributable to
sales and transportation services provided to Reliant Energy and its affiliates.
On March 17, 2000, KMTP renewed its natural gas sales and transportation
contract with Reliant Energy HL&P through March 1, 2004. Additionally, KMTP has
entered into a new transportation services agreement with Reliant Energy HL&P
beginning in 2002 and extending through 2012. Reliant HL&P provides electric
service to approximately 1.6 million customers in the Houston area. The contract
terms for Reliant Energy utilities will expire between 2002 and 2004. Also, on
October 21, 2000, KMTP entered into a 10-year firm natural gas transportation
and storage agreement with Calpine beginning July 1, 2001. Other industrial end
users' contracts vary in length from month-to-month to five or more years.

     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. KMPT 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, an Illinois general
partnership. Enron Trailblazer Pipeline Company, a subsidiary of Enron
Corporation, owns the remaining 33 1/3%. A committee consisting of management
representatives for each of the partners manages Trailblazer. NGPL, a subsidiary
of KMI, manages, maintains and


                                       15
<PAGE>   16

operates Trailblazer and provides the personnel to operate Trailblazer for which
NGPL is reimbursed at cost. Trailblazer is a "natural gas company" within the
meaning of the Natural Gas Act. 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 has been
a fully "open access" pipeline under Order Nos. 436/500 since June 1, 1991.
Trailblazer owns and operates a 436 mile 36-inch diameter pipeline system which
originates at an interconnection with Wyoming Interstate Company Ltd.'s pipeline
system near Rockport, Weld County, Colorado and runs through southeastern
Wyoming to a terminus near Beatrice, Gage County, Nebraska where Trailblazer's
pipeline system interconnects with NGPL'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 324,000 dekatherms per day. The
expansion project would 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 filed its expansion plan with the FERC on January 10, 2001, and
pending FERC approval, the project is scheduled for completion in the third
quarter of 2002.

     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 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.

     Douglas Gathering is comprised of approximately 1,500 miles of 4-inch to
16-inch diameter pipe that gathers approximately 58 million cubic feet per day
of casinghead gas from 650 active receipt points. Douglas Gathering has an
aggregate 24,495 horsepower of compression with central dehydration at each
field booster compressor station. 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.

     Casper Gathering is comprised of approximately 60 miles of 4-inch to 8-inch
diameter pipeline that transports 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.

     Our Casper Plant, located in Casper, Wyoming, is a lean oil absorption
facility with full fractionation and capacity to process 50 to 80 million cubic
feet per day of natural gas depending on raw gas quality. As a result of
utilizing a lean oil absorption process the facility does not recover ethane
from the raw gas stream. The inlet composition of gas entering our Casper plant
averages approximately 1.2 gallons per thousand cubic feet of propane and
heavier natural gas liquids, reflecting the relatively lean gas gathered by
Casper Gathering. Our Casper Plant recoveries averaged approximately 60% of
propane, 89% of isobutene, 90% of normal butane, and 98% of natural gasoline and
C6+. The facility is a straddle plant on KMIGT and utilizes 5,000 horsepower of
compression.



                                       16
<PAGE>   17

     Competition. There are a number of other natural gas gathering and
processing alternatives for producers in the 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;
the Sage Creek (50 million cubic feet per day) plant owned and operated by
Devon; and Lost Creek Gathering which is a partnership between Burlington
Resources and Northern Border Partners.

     RED CEDAR GATHERING COMPANY

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

     Red Cedar's gas gathering system currently consists of over 450 miles of
gathering pipeline connecting more than 600 producing wells, 17 field compressor
stations and a carbon dioxide processing plant. A majority of the 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 600
million cubic feet per day of natural gas.

     COYOTE GAS TREATING, LLC

     We own a 50% equity interest in Coyote Gas Treating, LLC, a joint venture
organized in December 1996. Coyote Gas Treating, LLC, known as Coyote Gulch, is
a 250 million cubic feet per day natural gas treating facility located in La
Plata County, Colorado. El Paso Field Services Company owns the remaining 50%
interest. We took over the operations of Coyote Gulch on February 1, 1999. Prior
to that time, El Paso was the operator of the plant.

     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 pipeline gas
quality specifications. Coyote's residue gas is delivered into the TransColorado
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, a joint
venture organized in September 1998. Thunder Creek provides gathering,
compression and treating services to a number of producers in the Powder River
Basin. Throughput volumes include both coalseam and conventional plant residue
gas. Devon Energy, an independent energy company, operates the facilities and
owns the remaining 75% interest.

     Thunder Creek's operations include a 450 million cubic feet per day,
126-mile, 24-inch trunk-line, a 225 million cubic feet per day amine-type carbon
dioxide treating plant, 340 miles of gathering lines and one major trunkline
compressor station with a total 11,275 horsepower.

     Thunder Creek was established to construct, equip, operate and maintain
natural gas gathering, compression, and treating facilities within a large area
of mutual interest in the Powder River Basin of eastern Wyoming. The Powder
River Basin encompasses approximately 26,000 square miles of eastern Wyoming and
southeastern Montana and contains an estimated 1 trillion tons of coal. With gas
content of the coal in the basin ranging from 30 to 75 standard cubic feet per
ton, industry estimates place potential recoverable coalbed methane reserves
within the Powder River Basin somewhere between 10 trillion cubic feet and 15
trillion cubic feet.


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<PAGE>   18

CO2 PIPELINES

     On March 5, 1998, we and affiliates of Shell Exploration & Production
Company combined our carbon dioxide activities and assets into a partnership
(Shell CO2 Company, Ltd.). Shell CO2 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
CO2 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:

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

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

     o    an indirect 50% interest in the Cortez Pipeline;

     o    a 13% interest in the Bravo Pipeline; and

     o    certain other related assets.

     These assets facilitated our marketing of carbon dioxide by bringing 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 CO2
Company, Ltd. from Shell for $212.1 million. After the closing, we renamed Shell
CO2 Company, Ltd., Kinder Morgan CO2 Company, L.P. We own a 98.9899% limited
partner interest in KMCO2 and our general partner owns a direct 1.0101%
general partner interest.

     On June 1, 2000, we announced an agreement to acquire 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 December 28, 2000, we announced that KMCO2 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. It is
owned 85% by Marathon Oil Company and 15% by KMCO2.

     McElmo and Bravo Domes. We operate and own approximately 45% of 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 850 million cubic feet per day, additional
wells are planned to increase deliverability by approximately 1 billion cubic
feet per day. McElmo Dome produces from the Leadville formation at 8,000 feet
with 44 wells that produce at individual rates of up to 100 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 333 million cubic feet per day, with production coming from more
than 350 wells in the Tubb Sandstone at 2,300 feet.

     Pipelines. 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 600
million cubic feet per day. At its origination point in Denver City, our Central
Basin Pipeline interconnects with all three major carbon dioxide supply
pipelines from Colorado and New Mexico, namely the Cortez Pipeline (operated by
KMCO2) and the Bravo and Sheep Mountain Pipelines (operated by BP Amoco).
Central Basin Pipeline's mainline terminates near McCamey where it interconnects
with the Canyon Reef Carriers Pipeline.

     We operate and own a 50% interest in the 502-mile, 30-inch Cortez Pipeline.
Prior to January 1, 2001, Cortez Pipeline was operated by a Shell affiliate.
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




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<PAGE>   19

per day, including approximately 90% of the carbon dioxide transported on our
Central Basin 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 240 million cubic feet per day and makes
deliveries to the SACROC, Sharon Ridge and Reinecke units.

     SACROC Unit. The SACROC unit, in which we have a 71% working interest, 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. The current production rate is approximately
9,000 barrels of oil per day from 250 producing wells.

     Markets. Our principal market for carbon dioxide is for injection into
mature oil fields in the Permian Basin, where industry demand is expected to be
comparable to historical demand for the next several years. We have negotiated
making deliveries to two new projects, the Cogdell field, operated by Occidental
Petroleum and the HT Boyd field, operated by Anadarko Petroleum. Deliveries are
expected to begin by mid 2001. 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 Sheep Mountain pipeline and
Petrosource Carbon Company's carbon dioxide pipeline. 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.

BULK TERMINALS

     Our Bulk Terminals segment consists of over 25 bulk terminals, which handle
approximately 40 million tons of dry and liquid bulk products annually.

     COAL 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.



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<PAGE>   20

     In addition, we operate the LAXT Coal Terminal in Los Angeles, California
and a smaller coal terminal in Mt. Vernon, Indiana. We are also in the process
of developing 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 low sulfur and would be used by local
utilities to comply with the Clean Air Act. When modifications are complete,
Shipyard River Terminal will have 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 low-sulfur coal from the western
United States. 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. Substantial portions
of the coal transloaded at these facilities are covered by long-term contracts.
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. Historically, our Cora and Grand Rivers terminals have moved coal
that originated in the mines of southern Illinois and western Kentucky. Many
shippers, however, particularly in the East, are now using western coal loaded
at the terminals or a mixture of western coal and other coals as a means of
meeting environmental restrictions. We believe that Illinois and Kentucky coal
producers and shippers will continue to be important customers, but 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 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. No significant
new coal terminals have been constructed near our Cora Terminal or our Grand
Rivers Terminal in the last ten years. 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. 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.

     PETROLEUM COKE AND OTHER BULK TERMINALS

     We own or operate 8 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 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,


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<PAGE>   21

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 segment. 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.

     LIQUID TERMINALS

     On December 1, 2000, we purchased the stock of Delta Terminal Services,
Inc. for $114.1 million. Delta operates a large liquids terminal in New Orleans,
with 2.8 million barrels of storage, four docks and seven drumming buildings, as
well as a smaller liquids terminal in Cincinnati, Ohio. These terminals handle a
variety of chemicals, vegetable oils and other liquid petroleum products and
compete with several large independent terminal operators.

MAJOR CUSTOMERS

     Our total operating revenues are derived from a wide customer base. During
2000 and 1999, no revenues from transactions with a single external customer
amounted to 10% or more of our consolidated revenues. For the year ended
December 31, 1998, the following customers accounted for more than 10% of our
consolidated revenues:

     o    Equilon Enterprises(1) 13.2%

     o    Tosco Group            12.3%

     o    Chevron                11.0%

     o    ARCO                   10.9%

(1) Equilon is the name of the joint venture, formed in January 1998, that
combined major elements of Texaco's and Shell's mid-western and western U.S.
refining and marketing businesses and nationwide trading, transportation and
lubricants businesses.

EMPLOYEES

     We do not have any employees. Our general partner and/or our subsidiary
entities employ all persons necessary for the operation of our business. We
reimburse our general partner for the services of its employees. As of February
1, 2001, our general partner and/or our subsidiary entities had approximately
1,600 employees. Approximately 100 hourly personnel at certain terminals are
represented by five labor unions. No other employees of our general partner or
our subsidiaries are members of a union or have a collective bargaining
agreement. Our general partner and our subsidiaries consider their relations
with their employees to be good.

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



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<PAGE>   22

circumstances. In 2000, 1999 and 1998, 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. Legislative and regulatory
changes began in 1978 with the passage of the Natural Gas Policy Act, pursuant
to which the process of deregulation of natural gas sold at the wellhead was
commenced. The restructuring of the natural gas industry continued with the
adoption of:

     o    Order 380 in 1984, which eliminated purchasers' minimum bill
          obligations to pipelines, thus making natural gas purchased from third
          parties, particularly on the spot market, more economically attractive
          relative to natural gas purchased from pipelines; and

     o    Order 436 in 1985, which provided that interstate transportation of
          natural gas under blanket or self-implementing authority must be
          provided on an open-access, non-discriminatory basis.

     After Order 436 was partially overturned in federal court, the FERC issued
Order 500 in August 1987 as an interim rule intended to readopt the basic thrust
of the regulations promulgated by Order 436. Order 500 was amended by Orders 500
A through L. The FERC's stated purpose in issuing Orders 436 and 500, as
amended, was to create a more competitive environment in the natural gas
marketplace. This purpose continued with Order 497, issued in June 1988, which
set forth new standards and guidelines imposing certain constraints on the
interaction of interstate pipelines and their marketing affiliates and imposing
certain disclosure requirements regarding that interaction. Order 636, issued in
April 1992, as amended, was a continuation of the FERC's efforts to improve the
competitive structure of the pipeline industry and maximize the consumer
benefits of a competitive structure of the pipeline industry and a competitive
wellhead gas market. 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. Pipelines must now
separately state the applicable rates for each unbundled service they provide
(i.e., for the natural gas commodity, transportation and storage).

     Specifically, Order 636 contains the following procedures to increase
competition in the industry:

     o    requiring the unbundling of sales services from other services,
          meaning that only a separately identified merchant affiliate of the
          pipeline could sell natural gas at points of entry into the pipeline
          system;

     o    permitting holders of firm capacity to release all or a part of their
          capacity for resale by the pipeline either to the highest bidder or,
          under short-term or maximum rate releases, to shippers in a
          prepackaged release, with revenues in both instances credited to the
          releasing shipper;


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<PAGE>   23


     o    allowing shippers to use as secondary points other receipt points and
          delivery points on the system, subject to the rights of other shippers
          to use those points as their primary receipt and delivery points;

     o    the issuance of blanket sales certificates to interstate pipelines for
          unbundled services;

     o    the continuation of pre-granted abandonment of previously committed
          pipeline sales and transportation services, subject to certain rights
          of first refusal, which should make unused pipeline capacity available
          to other shippers and clear the way for excess transportation services
          to be reallocated to the marketplace;

     o    requiring that firm and interruptible transportation services be
          provided by pipelines to all parties on a comparable basis; and

     o    generally requiring that pipelines derive transportation rates using a
          straight-fixed-variable rate method which places all fixed costs in a
          fixed reservation fee that is payable without regard to usage, as
          opposed to the previously used modified fixed-variable method that
          allocated a part of the pipelines' fixed costs to the usage fee. The
          FERC's stated position is that the straight-fixed-variable method
          promotes the goal of a competitive national gas market by increasing
          the cost of unnecessarily holding firm capacity rather than releasing
          it, and is consistent with its directive to unbundle pipelines'
          traditional merchant sales 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.

     Our acquisition of the KMIGT interstate natural gas pipeline system has
resulted in a significant increase in the percentage of our assets subject to
regulation by the FERC. To the extent any of our interstate 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 pipeline of its marketing
affiliates and govern in particular the provision of information by an
interstate pipeline to its marketing affiliates.

     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 intrastate portion of our 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:

     o    marketing;

     o    production;

     o    pricing;

     o    pollution;

     o    protection of the environment; and

     o    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 bulk 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.



                                       23
<PAGE>   24

     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
relating to protection of the environment. We believe that our operations and
facilities are in substantial compliance with applicable environmental
regulations. 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 bulk materials and the other activities conducted by us.
There can be no assurance that we will not incur significant costs and
liabilities, including those relating to claims for damages to property and
persons resulting from 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.

     SOLID WASTE

     We own several 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 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 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 and addressed. We have
maintained 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, imposes 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



                                       24
<PAGE>   25

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.

     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.

     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 bulk 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 the pipelines, storage
facilities and bulk 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.

     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.

RISK FACTORS

     RISKS RELATED TO OUR BUSINESS

     PENDING FEDERAL ENERGY REGULATORY COMMISSION AND CALIFORNIA PUBLIC
UTILITIES COMMISSION PROCEEDINGS SEEK SUBSTANTIAL REFUNDS AND REDUCTIONS IN
TARIFF RATES ON SOME OF OUR PACIFIC OPERATIONS' PIPELINES. Some shippers on our
Pacific operations' pipelines have filed complaints with the Federal Energy
Regulatory Commission and California Public Utilities Commission that seek
substantial refunds and reductions in the tariff rates on such pipelines.
Adverse 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.

     In the first set of complaints filed between 1992 and 1995 before the
Federal Energy Regulatory Commission, some shippers alleged that pipeline tariff
rates:



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<PAGE>   26

     o    for the West Line, serving southern California and Arizona, were not
          entitled to "grandfathered" status under the Energy Policy Act because
          "substantially changed circumstances" had occurred pursuant to the
          Energy Policy Act; and

     o    for the East Line, serving New Mexico and Arizona, were unjust and
          unreasonable.

     An initial decision by the FERC administrative law judge was issued on
September 25, 1997. The initial decision determined that our Pacific operations'
West Line rates were grandfathered under the Energy Policy Act. The initial
decision also included rulings that were generally adverse to our Pacific
operations' East Line regarding certain cost of service issues.

     On January 13, 1999, the FERC issued an opinion that affirmed, in major
respects, the initial decision, but also modified parts of the decision that
were adverse to us. In May 2000, the FERC issued a new opinion affirming in part
and modifying and clarifying in part the January 13, 1999 opinion. Some of the
complainants have appealed the FERC's decision to the United States Court of
Appeals for the District of Columbia Circuit.

     During the pendency of the above-referenced complaint proceeding, some
shippers filed complaints that predominantly attacked the pipeline tariff rates
of our Pacific operations' pipelines, contending that the rates were not just
and reasonable under the ICA and should not be entitled to "grandfathered"
status under the Energy Policy Act. These complaints covered rates for service
on the East Line, the West Line, the North Line serving the area between San
Francisco, California and Reno, Nevada, and the Oregon Line serving the area
from Portland, Oregon to Eugene, Oregon. The complaints seek substantial
reparations for alleged overcharges during the years in question and request
prospective rate reduction on each of the challenged facilities. These
complaints are expected to proceed to hearing in August 2001, with an initial
decision by the administrative law judge expected in the first half of 2002. In
January 2000, several of the shippers amended and restated their complaints
challenging the tariff rates of our Pacific operations' pipelines and filed
additional complaints in July and August 2000. We are vigorously defending
against all of these complaints.

     The complaints filed before the CPUC challenge the rates charged for
intrastate transportation of refined petroleum products through our Pacific
operations' pipeline system in California. On August 6, 1998, the CPUC issued
its decision dismissing the complainants' challenge to SFPP, L.P.'s intrastate
rates. On June 24, 1999, the CPUC granted limited rehearing of its August 1998
decision for the purpose of:

     o    addressing the proper ratemaking treatment for partnership tax
          expenses;

     o    the calculation of environmental costs; and

     o    the public utility status of SFPP, L.P.'s Sepulveda Line and its
          Watson Station gathering enhancement facilities.

     In pursuing these rehearing issues, the complainants seek prospective rate
reductions aggregating approximately $10 million per year.

     On April 10, 2000, the complainants filed a new complaint with the CPUC
asserting SFPP, L.P.'s intrastate rates were not just and reasonable. See Note
16 of the Notes to our Consolidated Financial Statements for additional
information.

     OUR ACQUISITION STRATEGY MAY REQUIRE ACCESS TO NEW CAPITAL, AND TIGHTENED
CREDIT MARKETS OR MORE EXPENSIVE CAPITAL WILL IMPAIR OUR ABILITY TO EXECUTE OUR
STRATEGY. 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, 2000, we made several acquisitions that
increased our asset base over 14 times and increased our net income over 23
times. We regularly consider and enter into discussions regarding potential
acquisitions and are currently contemplating potential acquisitions. While there
are currently no unannounced purchase agreements pending for the acquisition of
any 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. We may
need new capital to finance these acquisitions. Limitations on our access to
capital will impair our ability to execute our strategy. Expensive capital will
limit our ability to make acquisitions accretive. Our ability to maintain our
capital structure may impact the market value of our common units and our debt
securities.



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<PAGE>   27

     ENVIRONMENTAL REGULATION SIGNIFICANTLY AFFECTS OUR BUSINESS. 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 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. Although we cannot predict the impact of EPA standards or future
environmental measures, our costs could increase 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. Propane competes with electricity, fuel, oil and natural gas in the
residential and commercial heating market. In the engine fuel market, propane
competes with gasoline and diesel fuel. Butanes and natural gasoline used in
motor gasoline blending and isobutane used in premium fuel production compete
with alternative products. Natural gas liquids used as feed stocks for
refineries and petrochemical plants compete with alternative feed stocks. The
availability and prices of alternative energy sources and feed stocks
significantly affect demand for natural gas liquids.

     Refined product pipelines are generally the lowest cost method for
intermediate and long-haul overland refined product movement. Accordingly, the
most significant competitors to our product pipelines are:

     o    proprietary pipelines owned and operated by major oil companies in the
          areas where our pipelines deliver products;

     o    refineries within the market areas served by our product pipelines;
          and

     o    trucks.

     Additional product pipelines may be constructed in the future to serve
specific markets now served by our pipelines. Trucks competitively deliver
products in certain markets. Recently, major oil companies have increased the
usage of trucks, resulting in minor but notable reductions in product volumes
delivered to certain shorter-haul destinations, primarily Orange County and
Colton, California served by the South and West lines of our Pacific operations.

     We cannot predict with certainty whether this trend towards increased
short-haul trucking will continue in the future. Demand for terminaling services
varies widely throughout the product pipeline system. Certain major petroleum
companies and independent terminal operators directly compete with us at several
terminal locations. At those locations, pricing, service capabilities and
available tank capacity control market share.

     Our natural gas and carbon dioxide pipelines compete against other existing
natural gas and carbon dioxide pipelines originating from the same sources or
serving the same markets as our natural gas and carbon dioxide pipelines. In
addition, we also may face competition from natural gas pipelines that may be
built in the future.

     Our coal terminals compete with other coal terminals located in the same
general geographic areas. 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.

     Our ability to compete also depends upon general market conditions, which
may change. We conduct our operations without the benefit of exclusive
franchises from government entities. We provide common carrier transportation
services through our pipelines at posted tariffs and, with respect to our
Pacific operations, almost always without long-term contracts for transportation
service with customers. Demand for transportation services on our pipelines is
primarily a function of:

     o    total and per capita consumption;

     o    prevailing economic and demographic conditions;

     o    alternate modes of transportation;

     o    alternate sources; and



                                       27
<PAGE>   28

     o    price.

     WE GENERALLY DO NOT OWN THE LAND ON WHICH OUR PIPELINES ARE CONSTRUCTED AND
WE ARE SUBJECT TO THE POSSIBILITY OF INCREASED COSTS FOR THE LOSS OF LAND USE.
We generally do not own the land on which our pipelines are constructed.
Instead, we obtain the right to construct and operate the pipelines on other
people's land for a period of time. If we were to lose these rights, our
business could be affected negatively.

     Southern Pacific Transportation Company has allowed us to construct and
operate a significant portion of our Pacific operations' pipeline 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 land owners in order
to continue to maintain the pipelines. No assurance can be given that we could
obtain that permission over time at a cost that would not negatively affect us.

     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.

     OUR RAPID GROWTH MAY CAUSE DIFFICULTIES INTEGRATING NEW OPERATIONS. 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, 2000, we made several acquisitions that increased our asset
base over 14 times and increased our net income over 23 times. We believe that
we can profitably combine the operations of acquired businesses with our
existing operations. However, 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 DEBT INSTRUMENTS MAY LIMIT OUR FINANCIAL FLEXIBILITY. The instruments
governing our debt contain restrictive covenants that may prevent us from
engaging in certain transactions we deem beneficial. The agreements governing
our debt generally require us to comply with various affirmative and negative
covenants, including the maintenance of certain financial ratios and
restrictions on:

     o    incurring additional debt;

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

     o    granting liens.

     The instruments governing any future debt may contain similar restrictions.

     RESTRICTIONS ON OUR ABILITY TO PREPAY THE DEBT OF SFPP, L.P. MAY LIMIT
OUR FINANCIAL FLEXIBILITY. SFPP, L.P. is subject to restrictions with respect to
its debt that may limit our flexibility in structuring or refinancing existing
or future debt. These restrictions include the following:

     o    before December 15, 2002, we may prepay SFPP, L.P.'s first mortgage
          notes with a make-whole prepayment premium; and

     o    we agreed as part of the acquisition 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.


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<PAGE>   29

    RISK RELATED TO OWNERSHIP OF OUR DEBT SECURITIES IF WE DEFAULT

    DEBT SECURITIES ARE STRUCTURALLY SUBORDINATED TO DEBT OF OUR OPERATING
PARTNERSHIPS AND SUBSIDIARIES. Since we do not anticipate that any of our
operating partnerships or subsidiaries will guarantee our debt securities, our
existing and future debt securities will be effectively subordinated to all debt
of our operating partnerships and subsidiaries. As of December 31, 2000, our
operating partnerships and subsidiaries had $165.4 million of debt (excluding
intercompany debt). If any of our operating partnerships or subsidiaries
defaults on its debt, the holders of our debt securities would not receive any
money from the defaulting operating partnership or subsidiary until it had
repaid all of its debts in full.

     RISKS RELATED TO OWNERSHIP OF OUR UNITS IF WE DEFAULT

     UNITHOLDERS MAY HAVE NEGATIVE TAX CONSEQUENCES IF WE DEFAULT ON OUR DEBT OR
SELL ASSETS. If we default on any of our debt, the lenders will have the right
to sue us for non-payment. Such an action could cause an investment loss and
cause negative tax consequences for unitholders through the realization of
taxable income by unitholders without a corresponding cash distribution.
Likewise, if we were to dispose of assets and realize a taxable gain while there
is substantial debt outstanding and proceeds of the sale were applied to the
debt, unitholders could have increased taxable income without a corresponding
cash distribution.

     THERE IS THE POTENTIAL FOR A CHANGE OF CONTROL IF KINDER MORGAN, INC.
DEFAULTS ON DEBT. Kinder Morgan, Inc. indirectly owns all of the outstanding
capital stock of the general partner. KMI has significant operations which
provide cash independent of dividends that KMI receives from the general
partner. Nevertheless, if KMI defaults on its debt, its lenders could acquire
control of our general partner.

     LIMITATIONS IN OUR PARTNERSHIP AGREEMENT AND STATE PARTNERSHIP LAW

     OUR UNITHOLDERS HAVE LIMITED VOTING RIGHTS AND CONTROL OF MANAGEMENT. Our
unitholders have only limited voting rights on matters affecting the
Partnership. Our general partner, through a wholly owned subsidiary, manages our
activities. Our unitholders have no right to elect our general partner on an
annual or other ongoing basis. If our general partner withdraws, however, the
holders of a majority of the outstanding units, excluding units owned by our
departing general partner and its affiliates, may elect its successor.

     Our limited partners may remove our general partner only if:

     o    the holders of at least 66 2/3% of our outstanding units, excluding
          units owned by our departing general partner and its affiliates, vote
          to remove our general partner;

     o    a successor general partner is approved by at least 66 2/3% of our
          outstanding units, excluding units owned by our departing general
          partner and its affiliates; and

     o    we receive an opinion of counsel opining that the removal would not
          result in the loss of the limited liability to any of our limited
          partners or the limited partners of any of our operating partnerships
          or cause us or our operating partnerships to be taxed other than as a
          partnership for federal income tax purposes.

     A PERSON OR GROUP OWNING 20% OR MORE OF OUR UNITS CANNOT VOTE. Any units
held by a person or group that owns 20% or more of the common units cannot be
voted. This limitation does not apply to our general partner and its affiliates.
This provision may:

     o    discourage a person or group from attempting to remove our general
          partner or otherwise change management; and

     o    reduce the price at which the common units will trade under certain
          circumstances. For example, a third party will probably not attempt to
          remove our general partner and take over our management by making a
          tender offer for our outstanding units at a price above their trading
          market price without removing our general partner and substituting an
          affiliate.

     OUR GENERAL PARTNER'S LIABILITY TO US AND OUR UNITHOLDERS MAY BE LIMITED.
Our partnership agreement contains language limiting the liability of our
general partner to us or our unitholders. For example, our partnership agreement
provides that:



                                       29
<PAGE>   30

     o    our general partner does not breach any duty to us or our unitholders
          by borrowing funds or approving any borrowing. Our general partner is
          protected even if the purpose or effect of the borrowing is to
          increase incentive distributions to our general partner;

     o    our general partner does not breach any duty to us or our unitholders
          by taking any actions consistent with the standards of reasonable
          discretion outlined in the definitions of "available cash" and "cash
          from operations" contained in our partnership agreement; and

     o    our general partner does not breach any standard of care or duty by
          resolving conflicts of interest unless our general partner acts in bad
          faith.

     OUR PARTNERSHIP AGREEMENT MODIFIES THE FIDUCIARY DUTIES OF OUR GENERAL
PARTNER UNDER DELAWARE LAW. Such modifications of state law standards of
fiduciary duty may significantly limit the ability of unitholders to
successfully challenge the actions of our general partner as being a breach of
what would otherwise have been a fiduciary duty. These standards include the
highest duties of good faith, fairness and loyalty to our limited partners. Such
a duty of loyalty would generally prohibit a general partner of a Delaware
limited partnership from taking any action or engaging in any transaction for
which it has a conflict of interest. Under our partnership agreement, our
general partner may exercise its broad discretion and authority in the
management of us and the conduct of our operations as long as our general
partner's actions are in our best interest.

     UNITHOLDERS MAY HAVE LIABILITY TO REPAY DISTRIBUTIONS. Unitholders will not
be liable for assessments in addition to their initial capital investment in our
units. Under certain circumstances, however, unitholders may have to repay
amounts wrongfully returned or distributed to them. Under Delaware law, we may
not make a distribution to you if the distribution causes our liabilities to
exceed the fair value of our assets. Liabilities to partners on account of their
partnership interests and non-recourse liabilities are not counted for purposes
of determining whether a distribution is permitted. Delaware law provides that
for a period of three years from the date of such a distribution, a limited
partner who receives the distribution and knew at the time of the distribution
that the distribution violated Delaware law will be liable to the limited
partnership for the distribution amount. Under Delaware law, an assignee who
becomes a substituted limited partner of a limited partnership is liable for the
obligations of the assignor to make contributions to the partnership. However,
such an assignee is not obligated for liabilities unknown to the assignee at the
time the assignee became a limited partner if the liabilities could not be
determined from the partnership agreement.

     UNITHOLDERS MAY BE LIABLE IF WE HAVE NOT COMPLIED WITH STATE PARTNERSHIP
LAW. We conduct our business in a number of states. In some of those states the
limitations on the liability of limited partners for the obligations of a
limited partnership have not been clearly established. Our unitholders might be
held liable for our obligations as if they were a general partner if:

     o    a court or government agency determined that we were conducting
          business in the state but had not complied with the state's
          partnership statute; or

     o    our unitholders' rights to act together to remove or replace the
          general partner or take other actions under our partnership agreement
          constitute "control" of our business.

     OUR GENERAL PARTNER MAY BUY OUT MINORITY UNITHOLDERS IF IT OWNS 80% OF THE
UNITS. If at any time our general partner and its affiliates own 80% or more of
our issued and outstanding units, our general partner will have the right to
purchase all of the remaining units. Because of this right, a unitholder may
have to sell his units against his will or for a less than desirable price. Our
general partner may only purchase all of the units. The purchase price for such
a purchase will be the greater of:

     o    the most recent 20-day average trading price ending on the date five
          days prior to the date the notice of purchase is mailed; or

     o    the highest purchase price paid by our general partner or its
          affiliates to acquire units during the prior 90 days.

     Our general partner can assign this right to its affiliates or to us.

     WE MAY SELL ADDITIONAL LIMITED PARTNER INTERESTS, DILUTING EXISTING
INTERESTS OF UNITHOLDERS. Our partnership agreement allows our general partner
to cause us to issue additional common units and other equity securities.



                                       30
<PAGE>   31

When we issue additional equity securities, your proportionate partnership
interest will decrease. Such an issuance could negatively affect the amount of
cash distributed to unitholders and the market price of our units. Issuance of
additional units will also diminish the relative voting strength of the
previously outstanding units. There is no limit on the total number of units we
may issue.

     OUR GENERAL PARTNER CAN PROTECT ITSELF AGAINST DILUTION. Whenever we issue
equity securities to any person other than our general partner and its
affiliates, our general partner has the right to purchase additional limited
partnership interests on the same terms. This allows our general partner to
maintain its partnership interest in the Partnership. No other unitholder has a
similar right. Therefore, only our general partner may protect itself against
dilution caused by issuance of additional equity securities.

     THERE ARE POTENTIAL CONFLICTS OF INTEREST RELATED TO THE OPERATION OF THE
PARTNERSHIP. Certain conflicts of interest could arise among our general
partner, its ultimate corporate parent, Kinder Morgan, Inc., and us. Such
conflicts may include, among others, the following situations:

     Some of our general partner's officers and directors may have conflicting
fiduciary duties to KMI. Some of KMI's directors and officers are also directors
and officers of our general partner. Conflicts of interest may result due to the
fiduciary duties such directors and officers may have to manage KMI's business
in a manner beneficial to KMI and its shareholders. The resolution of these
conflicts may not always be resolved in the best interests of our unitholders.

     Our general partner may not be fully reimbursed for KMI's use of its
officers and employees and/or it may over-compensate KMI for our use of KMI's
officers and employees. KMI shares administrative personnel with our general
partner to operate both KMI's business and our business. As a result, our
general partner's officers, who in some cases may also be KMI officers, must
allocate, in their reasonable and sole discretion, the time our general
partner's employees and KMI's employees spend on behalf of us and on behalf of
KMI. These allocations are not the result of arms-length negotiations between
our general partner and KMI. Although our general partner intends for the net
payments to reflect the relative value received by us and KMI for the use of
each others employees, due to the nature of the allocations, this reimbursement
may not exactly match the actual time and overhead spent. Since we reimburse our
general partner for its general and administrative expenses, the under
allocation of the time and overhead spent by our general partners' employees on
KMI's activities or the over allocation of the time and overhead spent by KMI's
employees on our behalf could negatively affect the amount of cash available for
distribution to our unitholders. See Item 13. "Certain Relationships and Related
Transactions -- General and Administrative Expenses" in this Report.

     Our general partner's decisions may affect cash distributions to
unitholders. Our general partner determines the amount and timing of asset
purchases and sales, capital expenditures, borrowings and reserves. All of these
decisions can impact the amount of cash distributed by us to our unitholders,
which, in turn, affects the amount of the cash incentive distribution to our
general partner.

     Our general partner generally tries to avoid being personally liable for
our obligations. Our general partner is permitted to protect its assets in this
manner pursuant to our partnership agreement. Under our partnership agreement,
our general partner does not breach its fiduciary duty even if we could have
obtained more favorable terms without limitations on our general partner's
liability.

     Our general partner's decision to exercise or assign its call right to
purchase all of the limited partnership interests may conflict with our
unitholder's interests. If our general partner exercises this right, a
unitholder may have to sell its interest against its will or for a less than
desirable price.

TAX TREATMENT OF PUBLICLY TRADED PARTNERSHIPS UNDER THE INTERNAL REVENUE CODE

     The Internal Revenue Code of 1986, as amended, imposes certain limitations
on the current deductibility of losses attributable to investments in publicly
traded partnerships and treats certain publicly traded partnerships as
corporations for federal income tax purposes. The following discussion briefly
describes certain aspects of the Code that apply to individuals who are citizens
or residents of the United States without commenting on all of the federal
income tax matters affecting us or our unitholders, and is qualified in its
entirety by reference to the Code. OUR





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<PAGE>   32

UNITHOLDERS ARE URGED TO CONSULT THEIR OWN TAX ADVISOR ABOUT THE FEDERAL, STATE,
LOCAL AND FOREIGN TAX CONSEQUENCES TO THEM OF AN INVESTMENT IN US.

     TAX CHARACTERIZATION OF THE PARTNERSHIP

     The availability of the federal income tax benefits of a unitholder's
investment in us depends, in large part, on our classification as a partnership
for federal income tax purposes. The Code generally treats a publicly traded
partnership formed after 1987 as a corporation unless, for each taxable year of
its existence, 90% or more of its gross income consists of qualifying income.

     If we were to fail to meet the 90% qualified income test for any year, we
would be treated as a corporation unless we met the inadvertent failure
exception. Qualifying income includes interest, dividends, real property rents,
gains from the sale or disposition of real property, income and gains derived
from the exploration, development, mining or production, processing, refining,
transportation (including pipelines transporting gas, oil or products thereof),
or the marketing of any mineral or natural resource (including fertilizer,
geothermal energy and timber), and gain from the sale or disposition of capital
assets that produced such income. Our general partner believes that more than
90% of our gross income is, and has been, qualifying income, because we are
engaged primarily in the transportation of natural gas liquids, refined
petroleum products, natural gas and carbon dioxide through pipelines and the
handling and storage of coal.

     If we were classified as an association taxable as a corporation for
federal income tax purposes, we would be required to pay tax on our income at
corporate rates, distributions to our unitholders would generally be taxed as
corporate distributions, and no income, gain, loss, deduction or credit would
flow through to our unitholders. Because tax would be imposed upon us as an
entity, the cash available for distribution to our unitholders would be
substantially reduced. Our being treated as an association taxable as a
corporation or otherwise as a taxable entity would result in a material
reduction in the anticipated cash flow and after-tax return to our unitholders.

     There can be no assurance that the law will not be changed so as to cause
us to be treated as an association taxable as a corporation for federal income
tax purposes or otherwise to be subject to entity-level taxation. Our
partnership agreement provides that, if a law is enacted that subjects us to
taxation as a corporation or otherwise subjects us to entity-level taxation for
federal income tax purposes, certain provisions of our partnership agreement
relating to our general partner's incentive distributions will be subject to
change, including a decrease in the amount of the target distribution levels to
reflect the impact of entity level taxation on us. See "Description of the
Partnership Agreement -- Cash Distribution Policy -- Adjustment of Target
Distribution Levels" in this Report.

     PASSIVE ACTIVITY LOSS LIMITATIONS

     Under the passive loss limitations, losses generated by us, if any, will
only be available to offset future income generated by us and cannot be used to
offset income which an individual, estate, trust or personal service corporation
realizes from other activities, including passive activities or investments.
Income which may not be offset by passive activity losses, includes not only
salary and active business income, but also portfolio income such as interest,
dividends or royalties or gain from the sale of property that produces portfolio
income. Credits from passive activities are also limited to the tax attributable
to any income from passive activities. The passive activity loss rules are
applied after other applicable limitations on deductions, such as the at-risk
rules and the basis limitation. Certain closely held corporations are subject to
slightly different rules, which can also limit their ability to offset passive
losses against certain types of income. A unitholder's proportionate share of
unused losses may be deducted when the unitholder disposes of all of such
holder's units in a fully taxable transaction with an unrelated party. Net
passive income from us may be offset by a unitholder's unused losses from us
carried over from prior years, but not by losses from other passive activities,
including losses from other publicly traded partnerships. In addition, a
unitholder's proportionate share of our portfolio income, including portfolio
income arising from the investment of our working capital, is not treated as
income from a passive activity and may not be offset by such unitholder's share
of net losses from us.

     SECTION 754 ELECTION

     We and our operating partnerships have made, will make for each taxable
year, as necessary, and will maintain the election provided for by Section 754
of the Code, which will generally permit a unitholder to calculate cost




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<PAGE>   33

recovery and depreciation deductions by reference to the portion of the
unitholder's purchase price attributable to each of our assets. For tax
purposes, transfers of more than 50% of unitholders' interests in capital and
profits during any 12-month period will result in a constructive termination of
us. A constructive termination of the partnership could result in penalties and
a loss of basis adjustments under Section 754, if we were unable to determine
that a termination had occurred during any year and, therefore, did not make a
Section 754 election for the new partnership's initial tax year.

     NO AMORTIZATION OF BOOK-UP ATTRIBUTABLE TO INTANGIBLES

     Our acquisition of our Pacific operations resulted in a restatement of the
capital accounts of both the former Santa Fe common unitholders and our
pre-acquisition unitholders to fair market value. An allocation of such
increased capital account value among our assets was based on values indicated
by an independent appraisal obtained by our general partner. The independent
appraisal indicated that all of such value was attributable to tangible assets.
However, if such allocations are challenged by the Internal Revenue Service and
such challenge is successful, a portion of such allocations could be
re-allocated to intangible assets that would not be amortizable either for tax
or capital account purposes, and therefore, would not support a curative
allocation of income. This could result in a disproportionate allocation of
taxable income to either a pre-acquisition unitholder or a former Santa Fe
common unitholder.

      DEDUCTIBILITY OF INTEREST EXPENSE

      The Code generally provides that investment interest expense is deductible
only to the extent of a non-corporate taxpayer's net investment income. In
general, net investment income for purposes of this limitation includes gross
income from property held for investment (except for net capital gains taxed at
the long-term capital gains rate) and portfolio income (determined pursuant to
the passive loss rules) reduced by certain expenses (other than interest) which
are directly connected with the production of such income. Property subject to
the passive loss rules is not treated as property held for investment. However,
the IRS has issued a notice which provides that net income from a publicly
traded partnership (not otherwise treated as a corporation) may be included in
net investment income for the purposes of the limitation on the deductibility of
investment interest. A unitholder's investment income attributable to its
interest in us will include both its allocable share of our portfolio income and
trade or business income. A unitholder's investment interest expense will
include its allocable share of our interest expense attributable to portfolio
investments.

     TAX LIABILITY EXCEEDING CASH DISTRIBUTIONS OR PROCEEDS FROM DISPOSITIONS
OF UNITS

     A unitholder will be required to pay federal income tax and, in certain
cases, state and local income taxes on such unitholder's allocable share of our
income, whether or not such unitholder receives cash distributions from us. No
assurance is given that unitholders will receive cash distributions equal to
their allocable share of taxable income from the Partnership. Further, a
unitholder may incur tax liability in excess of the amount of cash received.

     TAX SHELTER REGISTRATION; POTENTIAL IRS AUDIT

     We are registered with the IRS as a tax shelter. No assurance can be given
that the IRS will not audit us or that tax adjustments will not be made. The
rights of a unitholder owning less than a 1% profits interest in us to
participate in the income tax audit process have been substantially reduced by
our partnership agreement. Further, any adjustments in our returns will lead to
adjustments in a unitholder's returns and may lead to audits of such
unitholder's returns and adjustments of items unrelated to us. Each unitholder
would bear the cost of any expenses incurred in connection with an examination
of the personal tax return of such unitholder.

     UNRELATED BUSINESS TAXABLE INCOME

     Certain entities otherwise exempt from federal income taxes (such as
individual retirement accounts, pension plans and charitable organizations) are
nevertheless subject to federal income tax on net unrelated business taxable
income and each such entity must file a tax return for each year in which it has
more than $1,000 of gross income from unrelated business activities. Our general
partner believes that substantially all of our gross income will be treated as
derived from an unrelated trade or business and taxable to such entities. The
tax-exempt entity's share of our deductions directly connected with carrying on
such unrelated trade or business is allowed in computing the


                                       33
<PAGE>   34

entity's taxable unrelated business income. ACCORDINGLY, INVESTMENT IN US BY
TAX-EXEMPT ENTITIES SUCH AS INDIVIDUAL RETIREMENT ACCOUNTS, PENSION PLANS AND
CHARITABLE TRUSTS MAY NOT BE ADVISABLE.

     STATE AND LOCAL TAX TREATMENT

     Each unitholder may be subject to income, estate or inheritance taxes in
states and localities in which we own property or do business, as well as in
such unitholder's own state or locality. For purposes of state and local tax
reporting, as of December 31, 2000, partners may have to report income in 25
states: Arizona, California, Colorado, Illinois, Indiana, Iowa, Kansas,
Kentucky, Louisiana, Maryland, Michigan, Minnesota, Missouri, Nebraska, Nevada,
New Mexico, North Carolina, Ohio, Oklahoma, Oregon, Pennsylvania, South
Carolina, Texas, Virginia and Wyoming. A unitholder will likely be required to
file state income tax returns and to pay applicable state income taxes in many
of these states and may be subject to penalties for failure to comply with such
requirements. Some of the states have proposed that we withhold a percentage of
income attributable to our operations within the state for unitholders who are
non-residents of the state. In the event that such states require that we
withhold amounts (which may be greater or less than a particular unitholder's
income tax liability to the state), such withholding would generally not relieve
the non-resident unitholder from the obligation to file a state income tax
return.

DESCRIPTION OF THE PARTNERSHIP AGREEMENT

     The following paragraphs summarize provisions of our partnership agreement.
A copy of our partnership agreement is filed as an exhibit to this report.
Unless otherwise specifically described, references herein to our partnership
agreement constitute references herein to our partnership agreement and those of
our operating partnerships, collectively. The following discussion is qualified
in its entirety by reference to our partnership agreement. With regard to
allocations of taxable income and taxable loss, See "Tax Treatment of Publicly
Traded Partnerships Under the Internal Revenue Code."

     ORGANIZATION AND DURATION

     Except for Kinder Morgan CO2 Company, L.P., which is a Texas limited
partnership, we and each of our operating partnerships are Delaware limited
partnerships. Unless liquidated or dissolved at an earlier time, under the terms
of our partnership agreement, we and each of our operating partnerships will
dissolve on December 31, 2082.

     PURPOSE

     Our purpose under our partnership agreement is to serve as the limited
partner in our operating partnerships and to conduct any other business that may
be lawfully conducted by a Delaware limited partnership.

     LIMITED PARTNER UNITS

     We currently have two classes of limited partner interests: common units
and Class B units. Our common units are publicly traded on the New York Stock
Exchange. Our Class B units are similar to our common units except that our
Class B units are not eligible for trading on the New York Stock Exchange. The
holders of our Class B units have the same rights as our common unitholders with
respect to, without limitation, distributions from us, voting rights and
allocations of income, gain, loss or deductions. All of the outstanding Class B
units were issued to KMI in connection with KMI's transfer to us of certain
Natural Gas Pipeline assets effective December 31, 2000.

     The Class B units are convertible into common units after such time as the
New York Stock Exchange has advised us that the common units issuable upon such
conversion are eligible for listing on the NYSE. At any time after December 21,
2001, the holders of a majority of our Class B units may notify us of their
desire to convert their Class B units into our common units. If at such time the
common units issuable upon conversion of the Class B units would not be eligible
for listing on the NYSE, we must use our reasonable efforts to meet any
unfulfilled requirements for such listing within 120 days after receipt of such
notice. If we are unable to satisfy all of the requirements of the NYSE for
listing of such common units within the 120 days, then our Class B unitholders
may at any time thereafter require that we redeem their Class B units for cash
by delivering a notice of redemption to us. KMI has represented that it will not
demand cash redemption for the Class B units.
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<PAGE>   35

     POWER OF ATTORNEY

     Each limited partner, and each person who acquires a unit from a prior
unitholder and executes and delivers a transfer application with respect to such
unit, grants to our general partner and, if a liquidator has been appointed, the
liquidator, a power of attorney to, among other things:

     o    execute and file certain documents required in connection with our
          qualification, continuance or dissolution or the amendment of our
          partnership agreement in accordance with its terms; and

     o    make consents and waivers contained in our partnership agreement.

     RESTRICTIONS ON AUTHORITY OF OUR GENERAL PARTNER

     Our general partner's authority is limited in certain respects under our
partnership agreement. Our general partner is prohibited, without the prior
approval of holders of record of a majority of the outstanding units from, among
other things, selling or exchanging all or substantially all of our assets in a
single transaction or a series of related transactions (including by way of
merger, consolidation or other combination) or approving on our behalf the sale,
exchange or other disposition of all or substantially all of our assets.
However, our general partner may mortgage, pledge, hypothecate or grant a
security interest in all or substantially all of our assets without such
approval. Our general partner may also sell all or substantially all of our
assets pursuant to a foreclosure or other realization upon the foregoing
encumbrances without such approval. Except as provided in our partnership
agreement and generally described under "--Amendment of Partnership Agreement
and Other Agreements," any amendment to a provision of our partnership agreement
generally will require the approval of the holders of at least 66 2/3% of our
outstanding units. Our general partner's ability to sell or otherwise dispose of
a significant portion of our assets is restricted by the terms of our credit
facilities.

     In general, our general partner may not take any action, or refuse to take
any reasonable action, the effect of which would be to cause us to be treated as
an association taxable as a corporation or otherwise taxed as an entity for
federal income tax purposes, unless it has obtained the consent of holders of
record of a majority of our outstanding units (other than units owned by our
general partner and its affiliates).

     WITHDRAWAL OR REMOVAL OF OUR GENERAL PARTNER

     Our general partner has agreed not to voluntarily withdraw as our general
partner prior to January 1, 2003 (with limited exceptions described below)
without obtaining the approval of at least a majority of our outstanding units
(excluding for purposes of such determination units held by the general partner
and its affiliates) and furnishing an opinion of counsel that such withdrawal
will not cause us to be treated as an association taxable as a corporation or
otherwise taxed as an entity for federal income tax purposes or result in the
loss of the limited liability of any limited partner. On or after January 1,
2003, our general partner may withdraw as our general partner by giving 90 days'
written notice (without first obtaining approval from the unitholders), and such
withdrawal will not constitute a breach of our partnership agreement. If an
opinion of counsel cannot be obtained to the effect that (following the
selection of a successor) our general partner's withdrawal would not result in
the loss of limited liability of the holders of units or cause us to be treated
as an association taxable as a corporation or otherwise taxed as an entity for
federal income tax purposes, we will be dissolved after such withdrawal.
Notwithstanding the foregoing, our general partner may withdraw prior to January
1, 2003 without approval of the unitholders upon 90 days' notice to our limited
partners if more than 50% of our outstanding units (other than those held by the
withdrawing general partner and its affiliates) are held or controlled by one
person and its affiliates. In addition, our partnership agreement does not
restrict KMI's ability to sell directly or indirectly, all or any portion of the
capital stock of our general partner to a third party without the approval of
the holders of units.

     Our general partner may not be removed unless such removal is approved by
the vote of the holders of not less than 66 2/3% of our outstanding units
(excluding units held by our general partner and its affiliates) provided that
certain other conditions are satisfied. Any such removal is subject to the
approval of our successor general partner by the same vote and receipt of an
opinion of counsel that such removal and the approval of a successor will not
result in the loss of limited liability of any limited partner or cause us to be
treated as an association taxable as a corporation or otherwise taxed as an
entity for federal income tax purposes.



                                       35
<PAGE>   36

     In the event our general partner withdraws and such withdrawal violates our
partnership agreement or our limited partners remove the general partner for
cause, a successor general partner will have the option to acquire the general
partner interest of the departing general partner for a cash payment equal to
the fair market value of such interest. Under all other circumstances where our
general partner withdraws or is removed by our limited partners, the departing
general partner will have the option to require the successor general partner to
acquire such departing general partner's interest for such amount. In each case
such fair market value will be determined by agreement between the departing
general partner and the successor general partner, or if no agreement is
reached, by an independent investment banking firm or other independent expert
selected by the departing general partner and the successor general partner (or
if no expert can be agreed upon, by the expert chosen by agreement of the expert
selected by each of them). In addition, we would also be required to reimburse
the departing general partner for all amounts due to the departing general
partner, including without limitation all employee related liabilities,
including severance liabilities, incurred in connection with the termination of
the employees employed by the departing general partner for our benefit.

     If the above-described option is not exercised by either the departing
general partner or the successor general partner, as applicable, the departing
general partner's interest in us will be converted into common units equal to
the fair market value of such departing general partner's interest as determined
by an investment banking firm or other independent expert selected in the manner
described in the preceding paragraph.

     Our general partner may transfer all, but not less than all, of its general
partner interest in us, without the approval of our limited partners, to one of
its affiliates, or upon its merger or consolidation into another entity or the
transfer of all or substantially all of its assets to another entity, provided
in either case that such entity assumes the rights and duties of our general
partner, agrees to be bound by the provisions of our partnership agreement and
furnishes an opinion of counsel that such transfer would not result in the loss
of the limited liability of any limited partner or cause us to be treated as an
association taxable as a corporation or otherwise cause us to be subject to
entity level taxation for federal income tax purposes. In the case of any other
transfer of our general partner's interest in us, in addition to the foregoing
requirements, the approval of at least a majority of the units is required,
excluding for such purposes those units held by our general partner and its
affiliates.

     Upon the withdrawal or removal of our general partner, we will be
dissolved, wound up and liquidated, unless such withdrawal or removal takes
place following the approval of a successor general partner or unless within 180
days after such withdrawal or removal a majority of the holders of units agrees
in writing to continue our business and appoint a successor general partner.
See "-Termination and Dissolution."

     ANTI-TAKEOVER AND RESTRICTED VOTING RIGHT PROVISIONS

     Our partnership agreement contains certain provisions that are intended to
discourage a person or group from attempting to remove our general partner or
otherwise change our management. If any person or group other than our general
partner and its affiliates acquires beneficial ownership of 20% or more of the
units, such person or group loses any and all voting rights with respect to all
of the units beneficially owned or held by such person.

     TRANSFER OF UNITS; STATUS AS LIMITED PARTNER OR ASSIGNEE

     Until a unit has been transferred on our books, we and our transfer agent,
notwithstanding any notice to the contrary, may treat the record holder thereof
as the absolute owner for all purposes, except as otherwise required by law or
stock exchange regulation. Any transfers of a unit will not be recorded by our
transfer agent or recognized by us unless the transferee executes and delivers a
transfer application (set forth on the reverse side of the certificate
representing units). By executing and delivering the transfer application, the
transferee of units:

     o    becomes the record holder of such units and shall constitute an
          assignee until admitted to us as a substituted limited partner;

     o    automatically requests admission as a substituted limited partner;


     o    agrees to be bound by the terms and conditions of and is deemed to
          have executed our partnership agreement;

     o    represents that such transferee has the capacity, power and authority
          to enter into our partnership agreement;


                                       36
<PAGE>   37

     o    grants powers of attorney to our general partner and any liquidator of
          ours as specified in our partnership agreement; and

     o    makes the consents and waivers contained in our partnership agreement.

     An assignee, pending its admission as a substituted limited partner, is
entitled to an interest in us equivalent to that of a limited partner with
respect to the right to share in allocations and distributions from us,
including liquidating distributions. Our general partner will vote, and exercise
other powers attributable to, units owned by an assignee that has not become a
substituted limited partner at the written direction of such assignee. See
"-Meetings; Voting."

     An assignee will become a substituted limited partner in respect of the
transferred units upon our general partner's consent and the recordation of the
name of the assignee in our books and records. Our general partner's consent may
be withheld in its sole discretion. Units are securities and are transferable
according to the laws governing transfers of securities. In addition to other
rights acquired upon transfer, a transferor gives a transferee the right to
request admission as a substituted limited partner in respect of the transferred
units. A purchaser or transferee of a unit who does not execute and deliver a
transfer application obtains only:

     o    the right to transfer the units to a purchaser or other transferee;
          and

     o    the right to transfer the right to seek admission as a substituted
          limited partner with respect to the transferred units.

     Thus, a purchaser or transferee of units who does not execute and deliver a
transfer application will not receive cash distributions unless the units are
held in a nominee or street name account and the nominee or broker has executed
and delivered a transfer application with respect to such units and may not
receive certain federal income tax information or reports furnished to record
holders of units. The transferor of units will have a duty to provide such
transferee with all information that may be necessary to obtain registration of
the transfer of the units, but the transferee agrees, by acceptance of the
certificate representing units, that the transferor will not have a duty to see
to the execution of the transfer application by the transferee and will have no
liability or responsibility if such transferee neglects or chooses not to
execute and forward the transfer application.

     Unitholders may hold their units in nominee accounts, provided that the
broker (or other nominee) executes and delivers a transfer application. We will
be entitled to treat the nominee holder of a unit as the absolute owner thereof,
and the beneficial owner's rights will be limited solely to those that it has
against the nominee holder as a result of or by reason of any understanding or
agreement between such beneficial owner and nominee holder.

     NON-CITIZEN ASSIGNEES; REDEMPTION

     If we are or become subject to federal, state or local laws or regulations
that, in the reasonable determination of our general partner, provide for the
cancellation or forfeiture of any property in which we have an interest because
of the nationality, citizenship or other related status of any limited partner
or assignee, we may redeem the units held by such limited partner or assignee at
their average fair market price. In order to avoid any such cancellation or
forfeiture, our general partner may require each record holder or assignee to
furnish information about such unitholder's nationality, citizenship, residency
or related status. If the record holder fails to furnish such information within
30 days after a request for such information, or if our general partner
determines on the basis of the information furnished by such holder in response
to the request that the cancellation or forfeiture of any property in which we
have an interest may occur, our general partner may be substituted as the
limited partner for such record holder, who will then be treated as a
non-citizen assignee, and our general partner will have the right to redeem the
units held by such record holder as described above. Our partnership agreement
sets forth the rights of such record holder or assignee upon redemption. Pending
such redemption or in lieu thereof, our general partner may change the status of
any such limited partner or assignee to that of a non-citizen assignee. Further,
a non-citizen assignee (unlike an assignee who is not a substituted limited
partner) does not have the right to direct the vote regarding such non-citizen
assignee's units and may not receive distributions in kind upon our liquidation.
See "-Transfer of Units; Status as Limited Partner or Assignee."


                                       37
<PAGE>   38


     As used in this Report:

     o    "average fair market price" means, with respect to a limited partner
          interest as of any date, the average of the daily end of day price (as
          hereinafter defined) for the 20 consecutive unit transaction days (as
          hereinafter defined) immediately prior to such date;

     o    "end of day price" means for any day the last sale price on such day,
          regular way, or in case no such sale takes place on such day, the
          average of the closing bid and asked prices on such day, regular way,
          in either case as reported in the principal consolidated transaction
          reporting system with respect to securities listed or admitted to
          trading on the principal national securities exchange on which our
          limited partner interests of such class are listed or admitted to
          trading or, if our limited partner interests of such class are not
          listed or admitted to trading on any national securities exchange, the
          last quoted sale price on such day, or, if not so quoted, the average
          of the high bid and low asked prices on such day in the
          over-the-counter market, as reported by the NASDAQ or such other
          system then in use, or if on any such day our limited partner
          interests of such class are not quoted by any such organization, the
          average of the closing bid and asked prices on such day as furnished
          by a professional market maker making a market in our limited partner
          interests of such class selected by the board of directors of our
          general partner, or if on any such day no market maker is making a
          market in such limited partner interests, the fair value of such
          limited partner interests on such day as determined reasonably and in
          good faith by the board of directors of our general partner; and

     o    "unit transaction day" means a day on which the principal national
          securities exchange on which such limited partner interests are listed
          or admitted to trading is open for the transaction of business or, if
          our limited partner interests of such class are not listed or admitted
          to trading on any national securities exchange, a day on which banking
          institutions in New York City generally are open.

     ISSUANCE OF ADDITIONAL SECURITIES

     The Partnership's Issuance of Securities. Our partnership agreement does
not restrict the ability of our general partner to issue additional limited or
general partner interests and authorizes our general partner to cause us to
issue additional securities for such consideration and on such terms and
conditions as shall be established by our general partner in its sole discretion
without the approval of any limited partners. In accordance with Delaware law
and the provisions of our partnership agreement, our general partner may issue
additional partnership interests, which, in its sole discretion, may have
special voting rights to which the units are not entitled.

     Limited Pre-emptive Right of Our General Partner. Our general partner has
the right, which it may from time to time assign in whole or in part to any of
its affiliates, to purchase from us units or other of our equity securities
whenever, and on the same terms that, we issue such securities to persons other
than our general partner and its affiliates, to the extent necessary to maintain
the percentage interest of our general partner and its affiliates in the
Partnership to that which existed immediately prior to each such issuance.

     LIMITED CALL RIGHT

     If at any time our general partner and its affiliates hold 80% or more of
any class of our units, our general partner will have the right, which it may
assign and transfer to any of its affiliates or to us, to purchase all of our
remaining units of that class as of a record date to be selected by the general
partner, on at least 10 but not more than 60 days' notice. The purchase price in
the event of such purchase shall be the greater of:

     o    the average fair market price of limited partner interests of such
          class as of the date five days prior to the mailing of written notice
          of our general partner's election to purchase limited partner
          interests of such class; and

     o    the highest cash price paid by our general partner or any of its
          affiliates for any units of that class purchased within the 90 days
          preceding the date our general partner mails notice of its election to
          purchase such units.

     AMENDMENT OF OUR PARTNERSHIP AGREEMENT AND OTHER AGREEMENTS

     Amendments to our partnership agreement may be proposed only by or with the
consent of our general partner. In order to adopt a proposed amendment, our
general partner is required to seek written approval of the holders of the
number of units required to approve such amendment or call a meeting of our
limited partners to consider and




                                       38
<PAGE>   39
vote upon the proposed amendment, except as described below. Proposed amendments
(other than those described below) must be approved by holders of at least
66 2/3% of the outstanding units, except that no amendment may be made which
would:

     o    enlarge the obligations of any limited partner, without its consent;

     o    enlarge the obligations of our general partner, without its consent,
          which may be given or withheld in its sole discretion;

     o    restrict in any way any action by or rights of our general partner as
          set forth in our partnership agreement;

     o    modify the amounts distributable, reimbursable or otherwise payable by
          us to our general partner;

     o    change the term of the Partnership; or

     o    give any person the right to dissolve us other than our general
          partner's right to dissolve us with the approval of a majority of the
          outstanding units or change such right of our general partner in any
          way.

     Our general partner may make amendments to our partnership agreement
without the approval of any limited partner or assignee to reflect:

     o    a change in our name, the location of our principal place of business,
          our registered agent or our registered office;

     o    admission, substitution, withdrawal or removal of partners in
          accordance with our partnership agreement;

     o    a change that, in our general partner's sole discretion, is reasonable
          and necessary or appropriate to qualify or continue our qualification
          as a partnership in which our limited partners have limited liability
          or that is necessary or advisable in our general partner's opinion to
          ensure that we will not be treated as an association taxable as a
          corporation or otherwise subject to taxation as an entity for federal
          income tax purposes;

     o    an amendment that is necessary, in the opinion of counsel, to prevent
          us or our general partner or our or their respective directors or
          officers from in any manner being subjected to the provisions of the
          Investment Company Act of 1940, the Investment Advisors Act of 1940,
          or "plan asset" regulations adopted under the Employee Retirement
          Income Security Act of 1974, whether or not substantially similar to
          plan asset regulations currently applied or proposed by the United
          States Department of Labor;

     o    an amendment that in our general partner's sole discretion is
          necessary or desirable in connection with the authorization of
          additional limited or general partner interests;

     o    any amendment expressly permitted in our partnership agreement to be
          made by our general partner acting alone;

     o    an amendment effected, necessitated or contemplated by a merger
          agreement that has been approved pursuant to the terms of our
          partnership agreement; and

     o    any other amendments substantially similar to the foregoing.

     In addition, our general partner may make amendments to our partnership
agreement without such consent if the amendments:

     o    do not adversely affect our limited partners in any material respect;

     o    are necessary or desirable to satisfy any requirements, conditions or
          guidelines contained in any opinion, directive, ruling or regulation
          of any federal or state agency or judicial authority or contained in
          any federal or state statute;

     o    are necessary or desirable to facilitate the trading of our units or
          to comply with any rule, regulation, guideline or requirement of any
          securities exchange on which our units are or will be listed for
          trading, compliance with any of which our general partner deems to be
          in our best interests and the holders of our units; or

     o    are required to effect the intent of, or as contemplated by, our
          partnership agreement.

     Our general partner will not be required to obtain an opinion of counsel as
to the tax consequences or the possible effect on limited liability of
amendments described in the two immediately preceding paragraphs. No other
amendments to our partnership agreement will become effective without the
approval of at least 95% of the units unless we obtain an opinion of counsel to
the effect that such amendment:


                                       39
<PAGE>   40

     o    will not cause us to be treated as an association taxable as a
          corporation or otherwise cause us to be subject to entity level
          taxation for federal income tax purposes; and

     o    will not affect the limited liability of any of our limited partners
          or the limited partner of our operating partnerships.

     Any amendment that materially and adversely affects the rights or
preferences of any type or class of limited partner interests in relation to
other types or classes of limited partner interests or our general partner's
interests will require the approval of at least 66 2/3% of the type or class of
limited partner interests so affected.

     MANAGEMENT

     Our general partner will manage and operate our activities, and our general
partner's activities will be limited to such management and operation. Holders
of units will not direct or participate in our or any of our operating
partnerships, management or operations. See "--Limited Liability." Our general
partner owes a fiduciary duty to our unitholders. Notwithstanding any limitation
on obligations or duties, our general partner will be liable, as our general
partner, for all of our debts (to the extent we do not pay them), except to the
extent that indebtedness we incur is made specifically non-recourse to our
general partner.

     We do not currently have any directors, officers or employees. As is
commonly the case with publicly traded limited partnerships, we do not currently
contemplate that we will directly employ any of the persons responsible for
managing or operating our business or for providing it with services, but will
instead reimburse our general partner or its affiliates for the services of such
persons. See "-Reimbursement of Expenses."

     Reimbursement of Expenses. Our general partner will receive no management
fee or similar compensation in conjunction with its management of us (other than
cash distributions). See "--Cash Distribution Policy." However, our general
partner is entitled pursuant to our partnership agreement to reimbursement on a
monthly basis, or such other basis as our general partner may determine in its
sole discretion, for all direct and indirect expenses it incurs or payments it
makes on our behalf and all other necessary or appropriate expenses allocable to
us or otherwise reasonably incurred by our general partner in connection with
operating our business. Our partnership agreement provides that our general
partner shall determine the fees and expenses that are allocable to us in any
reasonable manner determined by our general partner in its sole discretion. The
reimbursement for such costs and expenses will be in addition to any
reimbursement to our general partner and its affiliates as a result of the
indemnification provisions of our partnership agreement. See "-Indemnification."

     Indemnification. Our partnership agreement provides that we will indemnify
our general partner, any departing general partner and any person who is or was
an officer or director of our general partner or any departing general partner,
to the fullest extent permitted by law, and may indemnify, to the extent deemed
advisable by our general partner, to the fullest extent permitted by law, any
person who is or was an affiliate of our general partner or any departing
general partner, any person who is or was an officer, director, employee,
partner, agent or trustee of our general partner, any departing general partner
or any such affiliate, or any person who is or was serving at the request of our
general partner or any affiliate of our general partner or any departing general
partner as an officer, director, employee, partner, agent, or trustee of another
person from and against any and all losses, claims, damages, liabilities (joint
or several), expenses (including, without limitation, legal fees and expenses),
judgments, fines, penalties, interest, settlement and other amounts arising from
any and all claims, demands, actions, suits or proceedings, whether civil,
criminal, administrative or investigative, in which any indemnified person may
be involved, or is threatened to be involved, as a party or otherwise, by reason
of its status as:

     o    our general partner, a departing general partner or affiliate of
          either;

     o    an officer, director, employee, partner, agent or trustee of the
          general partner, any departing general partner or affiliate of either;
          or

     o    a person serving at our request in another entity in a similar
          capacity.

     In each case the indemnified persons must have acted in good faith and in a
manner which such indemnified persons believed to be in or not opposed to our
best interests and, with respect to any criminal proceeding, had no reasonable
cause to believe its conduct was unlawful. Any indemnification under our
partnership agreement will only be paid out of our assets, and our general
partner will not be personally liable for, or have any obligation to contribute
or loan funds or assets to us to enable us to effectuate, such indemnification.
We are authorized to




                                       40
<PAGE>   41

purchase (or to reimburse our general partner or its affiliates for the cost of)
insurance, purchased on behalf of our general partner and such other persons as
our general partner determines, against liabilities asserted against and
expenses incurred by such persons in connection with our activities, whether or
not we would have the power to indemnify such person against such liabilities
under the provisions described above.

     Conflicts and Audit Committee. One or more of our general partner's
directors who are neither officers nor employees of our general partner or any
of its affiliates will serve as a committee of our general partner's board of
directors and will, at the request of our general partner, review specific
matters as to which our general partner believes there may be a conflict of
interest in order to determine if the resolution of such conflict proposed by
our general partner is fair and reasonable to us. This conflicts and audit
committee will only review matters at the request of our general partner, which
has sole discretion to determine which matters to submit to such committee. Any
matters approved by this conflicts and audit committee will be conclusively
deemed to be fair and reasonable to us, approved by all of our partners and not
a breach by our general partner of our partnership agreement or any duties it
may owe to us. Additionally, it is possible that such procedure in itself may
constitute a conflict of interest.

     MEETINGS; VOTING

     Holders of units or assignees who are record holders of units on the record
date set pursuant to our partnership agreement will be entitled to notice of,
and to vote at, meetings of our limited partners and to act with respect to
matters as to which approvals may be solicited. With respect to voting rights
attributable to units that are owned by assignees who have not yet been admitted
as limited partners, our general partner will be deemed to be the limited
partner with respect thereto and will, in exercising the voting rights in
respect of such units on any matter, vote such units at the written direction of
the record holders thereof. If a proxy is not returned on behalf of the unit
record holder, such record holder's units will not be voted (except that, in the
case of units held by our general partner on behalf of non-citizen assignees,
our general partner will vote the votes in respect of such units in the same
ratios as the votes of limited partners in respect of other units are cast).
When a proxy is returned properly executed, the units represented thereby will
be voted in accordance with the indicated instructions. If no instructions have
been specified on the properly executed and returned proxy, the units
represented thereby will be voted "FOR" the approval of the matters to be
presented. Units held by our general partner on behalf of non-citizen assignees
shall be voted by our general partner in the same ratios as the votes of our
limited partners with respect to the matter presented to the holders of units.

     Any action that our limited partners are required or permitted to be taken
may be taken either at a meeting of our limited partners or without a meeting if
consents in writing setting forth the action so taken are signed by holders of
such number of limited partner interests as would be necessary to authorize or
take such action at a meeting of our limited partners. Meetings of our limited
partners may be called by our general partner or by limited partners owning at
least 20% of the outstanding units of the class for which a meeting is proposed.
Our limited partners may vote either in person or by proxy at meetings.
Two-thirds (or a majority, if that is the vote required to take action at the
meeting in question) of the outstanding limited partner interests of the class
for which a meeting is to be held (excluding, if such are excluded from such
vote, limited partner interests held by the general partner and its affiliates)
represented in person or by proxy will constitute a quorum at a meeting of our
limited partners. Except for any proposal for removal of our general partner or
certain amendments to our partnership agreement described above, substantially
all matters submitted for a vote are determined by the affirmative vote, in
person or by proxy, of holders of a majority of our outstanding limited partner
interests.

     Each record holder of a unit has a vote according to such record holder's
percentage interest in us, although our general partner could issue additional
limited partner interests having special voting rights. See "--Issuance of
Additional Securities." However, units owned beneficially by any person or group
(other than our general partner and its affiliates) that own beneficially 20% or
more of all units may not be voted on any matter and will not be considered to
be outstanding when sending notices of a meeting of limited partners,
calculating required votes, determining the presence of a quorum or for other
similar partnership purposes. Our partnership agreement provides that the broker
(or other nominee) will vote units held in nominee or street name accounts
pursuant to the instruction of the beneficial owner thereof, unless the
arrangement between the beneficial owner and such holder's nominee provides
otherwise.



                                       41
<PAGE>   42

     Any notice, demand, request, report or proxy materials required or
permitted to be given or made to record holders of units (whether or not such
record holder has been admitted as a limited partner) under the terms of our
partnership agreement will be delivered to the record holder by us or, at our
request, by the transfer agent.

     LIMITED LIABILITY

     Except as described below, units are fully paid, and holders of units will
not be required to make additional contributions to us.

     Assuming that a limited partner does not participate in the control of our
business, within the meaning of the Delaware limited partnership act, and that
such partner otherwise acts in conformity with the provisions of our partnership
agreement, such partner's liability under Delaware law will be limited, subject
to certain possible exceptions, generally to the amount of capital such partner
is obligated to contribute to us in respect of such holder's units plus such
holder's share of any of our undistributed profits and assets. However, if it
were determined that the right or exercise of the right by our limited partners
as a group to remove or replace our general partner, to approve certain
amendments to our partnership agreement or to take other action pursuant to our
partnership agreement constituted "participation in the control" of our business
for the purposes of the Delaware limited partnership act, then our limited
partners could be held personally liable for our obligations under the laws of
the State of Delaware to the same extent as our general partner.

     Under Delaware law, a limited partnership may not make a distribution to a
partner to the extent that at the time of the distribution, after giving effect
to the distribution, all liabilities of the partnership, other than liabilities
to partners on account of their partnership interests and nonrecourse
liabilities, exceed the fair value of the assets of the limited partnership. For
the purpose of determining the fair value of the assets of a limited
partnership, Delaware law provides that the fair value of property subject to
nonrecourse liability shall be included in the assets of the limited partnership
only to the extent that the fair value of that property exceeds that nonrecourse
liability. Delaware law provides that a limited partner who receives such a
distribution and knew at the time of the distribution that the distribution was
in violation of Delaware law shall be liable to the limited partnership for the
amount of the distribution for three years from the date of the distribution.

     Under Delaware law, an assignee who becomes a substituted limited partner
of a limited partnership is liable for the obligations of the assignor to make
contributions to us, except the assignee is not obligated for liabilities
unknown to such assignee at the time the assignee became a limited partner and
which could not be ascertained from our partnership agreement.

     We are organized under the laws of Delaware and currently conduct business
in a number of states. Maintaining limited liability will require that we comply
with legal requirements in all of the jurisdictions in which we conduct
business, including qualifying the operating partnerships to do business
therein. Limitations on the liability of limited partners for the obligations of
a limited partnership have not been clearly established in many jurisdictions.
If it were determined that we were, by virtue of our limited partner interest in
our operating partnerships or otherwise, conducting business in any state
without complying with the applicable limited partnership statute, or that the
right or exercise of the right by our limited partners as a group to remove or
replace our general partner, to approve certain amendments to our partnership
agreement, or to take other action pursuant to our partnership agreement
constituted "participation in the control" of our business for the purposes of
the statues of any relevant jurisdiction, then our limited partners could be
held personally liable for our obligations under the law of such jurisdiction to
the same extent as our general partner. We will operate in such manner as our
general partner deems reasonable and necessary or appropriate to preserve the
limited liability of holders of units.

     BOOKS AND REPORTS

     Our general partner is required to keep appropriate books of the business
at our principal offices. Our books will be maintained for both tax and
financial reporting purposes on an accrual basis. Our fiscal is the calendar
year.

     As soon as practicable, but in no event later than 120 days after the close
of each fiscal year, our general partner will furnish each record holder of a
unit (as of a record date selected by our general partner) with an annual report
containing audited financial statements for the past fiscal year, prepared in
accordance with generally accepted accounting principles. As soon as
practicable, but in no event later than 90 days after the close of each calendar




                                       42
<PAGE>   43

quarter (except the fourth quarter), our general partner will furnish each
record holder of a unit upon request a report containing our unaudited financial
statements and such other information as may be required by law.

     Our general partner will use all reasonable efforts to furnish each record
holder of a unit information reasonably required for tax reporting purposes
within 90 days after the close of each taxable year. Such information is
expected to be furnished in a summary form so that certain complex calculations
normally required of partners can be avoided. Our general partner's ability to
furnish such summary information to holders of units will depend on the
cooperation of such holders of units in supplying certain information to our
general partner. Every holder of a unit (without regard to whether such holder
supplies such information to our general partner) will receive information to
assist in determining such holder's federal and state tax liability and filing
such holder's federal and state income tax returns.

     RIGHT TO INSPECT PARTNERSHIP BOOKS AND RECORDS

     Our partnership agreement provides that a limited partner can, for a
purpose reasonably related to such limited partner's interest as a limited
partner, upon reasonable demand and at such partner's own expense, have
furnished to him:

     o    a current list of the name and last known address of each partner;

     o    a copy of our tax returns;

     o    information as to the amount of cash, and a description and statement
          of the agreed value of any other property or services contributed or
          to be contributed by each partner and the date on which each became a
          partner;

     o    copies of our partnership agreement, our certificate of limited
          partnership, amendments thereto and powers of attorney pursuant to
          which the same have been executed;

     o    information regarding the status of our business and financial
          condition; and

     o    such other information regarding our affairs as is just and
          reasonable.

     Our general partner may, and intends to, keep confidential from our limited
partners trade secrets or other information the disclosure of which our general
partner believes in good faith is not in our best interests or which we are
required by law or by agreements with third parties to keep confidential.

     TERMINATION AND DISSOLUTION

     We will continue until December 31, 2082, unless sooner terminated pursuant
to our partnership agreement. We will be dissolved upon:

     1.   our general partner's election to dissolve us, if approved by a
          majority of the units;

     2.   our sale of all or substantially all of our assets and properties and
          our operating partnerships;

     3.   the bankruptcy or dissolution of our general partner; or

     4.   the withdrawal or removal of our general partner or any other event
          that results in its ceasing to be our general partner (other than by
          reason of a transfer in accordance with the partnership agreement or
          withdrawal or removal following approval of a successor).

     However, we will not be dissolved upon an event described in clause 4 if
within 90 days after such event our partners agree in writing to continue our
business and to the appointment, effective as of the date of such event, of a
successor general partner. Upon a dissolution pursuant to clause 3 or 4, at
least a majority of the units may also elect, within certain time limitations,
to reconstitute us and continue our business on the same terms and conditions
set forth in our partnership agreement by forming a new limited partnership on
terms identical to those set forth in our partnership agreement and having as a
general partner an entity approved by at least a majority of the units, subject
to our receipt of an opinion of counsel that the exercise of such right will not
result in our unitholders' loss of limited liability or cause us or the
reconstituted limited partnership to be treated as an association taxable as a
corporation or otherwise subject to taxation as an entity for federal income tax
purposes.


                                       43
<PAGE>   44

     REGISTRATION RIGHTS

     Pursuant to the terms of our partnership agreement and subject to certain
limitations described therein, we have agreed to register for resale under the
Securities Act of 1933 and applicable state securities laws any units (or other
securities of the Partnership) proposed to be sold by our general partner (or
its affiliates) if an exemption from such registration requirements is not
otherwise available for such proposed transaction. We are obligated to pay all
expenses incidental to such registration, excluding underwriting discounts and
commissions.

     CASH DISTRIBUTION POLICY

     One of our principal objectives is to generate cash from our operations and
to distribute available cash to our partners in the manner described herein.
"Available cash" generally means, with respect to any calendar quarter, all cash
received by us from all sources, less all of our cash disbursements and net
additions to reserves. For purposes of cash distributions to our unitholders,
the term available cash excludes the amount paid in respect of the 0.5% special
limited partner interest in SFPP, L.P. owned by the former general partner of
SFPP, which amount will equal 0.5% of the total cash distributions made each
quarter by SFPP to its partners.

     Our general partner's decisions regarding amounts to be placed in or
released from reserves may have a direct impact on the amount of available cash.
This is because increases and decreases in reserves are taken into account in
computing available cash. Our general partner may, in its reasonable discretion
(subject to certain limits), determine the amounts to be placed in or released
from reserves each quarter.

     Cash distributions will be characterized as either distributions of cash
from operations or cash from interim capital transactions. This distinction
affects the amounts distributed to unitholders relative to our general partner.
See "--Quarterly Distributions of Available Cash-Distributions of Cash from
Operations" and "-Quarterly Distributions of Available Cash-Distributions of
Cash from Interim Capital Transactions."

     "Cash from operations" generally refers to our cash balance on the date we
commenced operations, plus all cash generated by the operations of our business,
after deducting related cash expenditures, reserves, debt service and certain
other items.

     "Cash from interim capital transactions" will generally be generated only
by borrowings, sales of debt and equity securities and sales or other
dispositions of assets for cash (other than inventory, accounts receivable and
other current assets and assets disposed of in the ordinary course of business).

     To avoid the difficulty of trying to determine whether available cash
distributed by us is cash from operations or cash from interim capital
transactions, all available cash distributed by us from any source will be
treated as cash from operations until the sum of all available cash distributed
as cash from operations equals the cumulative amount of cash from operations
actually generated from the date we commenced operations through the end of the
calendar quarter prior to such distribution. Any excess available cash
(irrespective of its source) will be deemed to be cash from interim capital
transactions and distributed accordingly.

     If cash from interim capital transactions is distributed in respect of each
unit in an aggregate amount per unit equal to $11.00 per unit (the initial
public offering price of the units adjusted to give effect to the 2-for-1 split
of units effective October 1, 1997) the distinction between cash from operations
and cash from interim capital transactions will cease, and both types of
available cash will be treated as cash from operations. Our general partner does
not anticipate that we will distribute significant amounts of cash from interim
capital transactions.

     The discussion below indicates the percentages of cash distributions
required to be made to our general partner and our unitholders. In the following
general discussion of how available cash is distributed, references to available
cash, unless otherwise stated, mean available cash that constitutes cash from
operations.

     Quarterly Distributions of Available Cash. We will make distributions to
our partners with respect to each calendar quarter prior to liquidation in an
amount equal to 100% of our available cash for such quarter.

     Distributions of Cash from Operations. Our distributions of available cash
constituting cash from operations with respect to any quarter will be made in
the following manner:



                                       44
<PAGE>   45
     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 $0.3025 per unit in cash for that 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 $0.3575 per
         unit in cash for that quarter (the "Second Target Distribution");

     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 $0.4675 per
         unit in cash for that quarter; and

     fourth, 50% of any available cash then remaining to the owners of all
         classes of units pro rata, paid in cash to owners of common units and
         Class B units, and 50% in cash to our general partner.

     In addition, if the first, second and third target distribution levels are
reduced to zero, as described below under "--Quarterly Distributions of
Available Cash-Adjustment of Target Distribution Levels," all remaining
available cash will be distributed as cash from operations, 50% our unitholders
pro rata and 50% to our general partner. These provisions are inapplicable upon
our dissolution and liquidation.

     Distributions of Cash from Interim Capital Transactions. Distributions on
any date by us of available cash that constitutes cash from interim capital
transactions will be distributed 98% to our unitholders pro rata and 2% to our
general partner until we shall have distributed in respect of each unit
available cash constituting cash from interim capital transactions in an
aggregate amount per unit equal to the adjusted initial unit price of $11.00.

     As cash from interim capital transaction is distributed, it is treated as
if it were a repayment of the initial public offering price. To reflect such
repayment, the first, second and third target distribution levels will be
adjusted downward by multiplying each amount by a fraction, the numerator of
which is the unrecovered initial unit price immediately after giving effect to
such repayment and the denominator of which is the unrecovered initial unit
price, immediately prior to giving effect to such repayment. "Unrecovered
initial unit price" includes the amount by which the initial unit price exceeds
the aggregate distribution of cash from interim capital transactions per unit.

     When "payback of initial unit price" is achieved, i.e., when the
unrecovered initial unit price is zero, then in effect the first, second and
third target distribution levels each will have been reduced to zero. Thereafter
all distributions of available cash from all sources will be treated as if they
were cash from operations and available cash will be distributed 50% to our
unitholders pro rata and 50% to our general partner.

     Adjustment of Target Distribution Levels. The first, second and third
target distribution levels will be proportionately adjusted upward or downward,
as appropriate, in the event of any combination or subdivision of units (whether
effected by a distribution payable in units or otherwise) but not by reason of
the issuance of additional units for cash or property. For example, in
connection with our two-for-one split of the units on October 1, 1997, the
first, second and third target distribution levels were each reduced to 50% of
their initial levels. See "--Quarterly Distributions of Available
Cash-Distributions of Cash from Operations."

     In addition, if a distribution is made of available cash constituting cash
from interim capital transactions, the first, second and third target
distribution levels will be adjusted downward proportionately, by multiplying
each such amount, as the same may have been previously adjusted, by a fraction,
the numerator of which is the unrecovered initial unit price immediately after
giving effect to such distribution and the denominator of which is the
unrecovered initial unit price immediately prior to such distribution. For
example, assuming the unrecovered initial unit price is $11.00 per unit and if
cash from interim capital transactions of $5.50 per unit is distributed to our
unitholders (assuming no prior adjustments), then the amount of the first,
second and third target distribution levels would each be reduced to 50% of
their initial levels. If and when the unrecovered initial unit price is zero,
the first, second and third target distribution levels each will have been
reduced to zero, and our general partner's share of distributions of available
cash will increase, in general, to 50% of all distributions of available cash.

     The first, second and third target distribution levels may also be adjusted
if legislation is enacted which causes us to become taxable as a corporation or
otherwise subjects us to taxation as an entity for federal income tax



                                       45
<PAGE>   46

purposes. In such event, the first, second, and third target distribution levels
for each quarter thereafter would be reduced to an amount equal to the product
of:

     o    each of the first, second and third target distribution levels
          multiplied by;

     o    one minus the sum of:

          o    the maximum marginal federal income tax rate to which we are
               subject as an entity; plus

          o    any increase that results from such legislation in the effective
               overall state and local income tax rate to which we are subject
               as an entity for the taxable year in which such quarter occurs
               (after taking into account the benefit of any deduction allowable
               for federal income tax purposes with respect to the payment of
               state and local income taxes).

     For example, assuming we are not previously subject to state and local
income tax, if we were to become taxable as an entity for federal income tax
purposes and we became subject to a maximum marginal federal, and effective
state and local, income tax rate of 38%, then each of the target distribution
levels, would be reduced to 62% of the amount thereof immediately prior to such
adjustment.

     LIQUIDATION AND DISTRIBUTION OF PROCEEDS

     Upon our dissolution, unless we are reconstituted and continued as a new
limited partnership, the liquidator authorized to wind up our affairs will,
acting with all of the powers of our general partner that such liquidator deems
necessary or desirable in its good faith judgment in connection therewith,
liquidate our assets and apply the proceeds of the liquidation as follows:

     o    first towards the payment of all our creditors and the creation of a
          reserve for contingent liabilities; and

     o    then to all partners in accordance with the positive balances in their
          respective capital accounts.

     Under certain circumstances and subject to certain limitations, the
liquidator may defer liquidation or distribution of our assets for a reasonable
period of time and/or distribute assets to partners in kind if it determines
that a sale would be impractical or would cause undue loss to our partners.

     Generally, any gain will be allocated between our unitholders and our
general partner in a manner that approximates their sharing ratios in the
various target distribution levels. Our unitholders and our general partner will
share in the remainder of our assets in proportion to their respective
partnership capital account balances.

     Any loss or unrealized loss will be allocated to our general partner and
our unitholders: first, in proportion to the positive balances in such partners'
capital accounts until all such balances are reduced to zero; and thereafter, to
our general partner.

TRANSFER AGENT AND REGISTRAR

     DUTIES

     First Chicago Trust Company of New York is the registrar and transfer agent
for our units and receives a fee from us for serving in such capacities. We will
pay fees charged by our transfer agent for transfers of units except:

     o    fees similar to those customarily paid by holders of securities for
          surety bond premiums to replace lost or stolen certificates;

     o    taxes or other governmental charges;

     o    special charges for services requested by a holder of a unit; and

     o    other similar fees or charges.

We will not charge unitholders for disbursements of cash distributions. We will
indemnify our transfer agent, its agents and each of their respective
shareholders, directors, officers and employees against all claims and losses
that may arise out of acts performed or omitted in respect of its activities as
such, except for any liability due to any negligence, gross negligence, bad
faith or intentional misconduct of the indemnified person or entity.



                                       46
<PAGE>   47

     RESIGNATION OR REMOVAL

     Our transfer agent may at any time resign, by notice to us, or be removed
by us, such resignation or removal to become effective upon our general
partner's appointment of a successor transfer agent and registrar and such
successor's acceptance of such appointment. If no successor has been appointed
and accepted such appointment within 30 days after notice of such resignation or
removal, our general partner is authorized to act as the transfer agent and
registrar until a successor is appointed.

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 2000.




                                       47
<PAGE>   48


                                     PART II

ITEM 5.  MARKET FOR THE REGISTRANT'S UNITS 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 cash
distributions declared per common unit.

<TABLE>
<CAPTION>
                                     PRICE RANGE
                              -----------------------        CASH
                                 HIGH          LOW       DISTRIBUTIONS
                              ----------   ----------    -------------
<S>                           <C>          <C>          <C>
             2000
             ----
             First Quarter    $  44.5625   $  38.5000   $   0.7750
             Second Quarter      39.9375      37.1250       0.8500
             Third Quarter       47.3750      39.6250       0.8500
             Fourth Quarter      56.3125      46.0000       0.9500

             1999
             ----
             First Quarter    $  37.9375   $  33.1250   $   0.7000
             Second Quarter      39.0000      33.9375       0.7000
             Third Quarter       45.3750      37.5000       0.7250
             Fourth Quarter      43.9375      39.6250       0.7250
</TABLE>

     The quarterly distribution for the fourth quarter of 2000 was $.95 per
unit. 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, 2001, there were approximately 36,000 beneficial owners
of our common units and one holder of our Class B units.

     Recent Sales of Unregistered Securities. During the quarter ended December
31, 2000, we issued the following equity securities, which were not registered
under the Securities Act of 1933, as amended. Effective December 31, 2000, we
acquired over $300 million of assets from KMI. As consideration for these
assets, we paid to KMI $192.7 million, 640,000 common units and 2,656,700 Class
B units. The units were issued to KMI pursuant to Section 4(2) of the Securities
Act of 1933.



                                       48
<PAGE>   49

ITEM 6. SELECTED FINANCIAL DATA (UNAUDITED)

     The following table sets forth, for the periods and at the dates indicated,
selected historical financial and operating data for us.

<TABLE>
<CAPTION>
                                                                                YEAR ENDED DECEMBER 31,
                                                        2000(7)         1999(8)          1998(9)           1997            1996
                                                      -----------     -----------      -----------      -----------     -----------
                                                                   (In thousands, except per unit and operating data)

<S>                                                   <C>             <C>              <C>              <C>             <C>
INCOME AND CASH FLOW DATA:
Revenues                                              $   816,442     $   428,749      $   322,617      $    73,932     $    71,250
Cost of product sold                                      124,641          16,241            5,860            7,154           7,874
Operating expense                                         190,329         111,275           77,162           17,982          22,347
Fuel and power                                             43,216          31,745           22,385            5,636           4,916
Depreciation and amortization                              82,630          46,469           36,557           10,067           9,908
General and administrative                                 60,065          35,612           39,984            8,862           9,132
                                                      -----------     -----------      -----------      -----------     -----------
Operating income                                          315,561         187,407          140,669           24,231          17,073
Earnings from equity investments                           71,603          42,918           25,732            5,724           5,675
Amortization of excess cost of equity investments          (8,195)         (4,254)            (764)              --              --
Interest (expense)                                        (97,102)        (54,336)         (40,856)         (12,605)        (12,634)
Interest income and other, net                             10,415          22,988           (5,992)            (353)          3,129
Income tax (provision) benefit                            (13,934)         (9,826)          (1,572)             740          (1,343)
                                                      -----------     -----------      -----------      -----------     -----------
Income before extraordinary charge                        278,348         184,897          117,217           17,737          11,900
Extraordinary charge                                           --          (2,595)         (13,611)              --              --
                                                      -----------     -----------      -----------      -----------     -----------
Net income                                            $   278,348     $   182,302      $   103,606      $    17,737     $    11,900
                                                      ===========     ===========      ===========      ===========     ===========
General partners' interest in net income              $   109,470     $    56,273      $    33,447      $     4,074     $       218
                                                      ===========     ===========      ===========      ===========     ===========
Limited partners' interest in net income              $   168,878     $   126,029      $    70,159      $    13,663     $    11,682
                                                      ===========     ===========      ===========      ===========     ===========
Basic Limited Partners' income per unit
      before extraordinary charge(1)                  $      2.68     $      2.63      $      2.09      $      1.02     $      0.90
                                                      ===========     ===========      ===========      ===========     ===========
Basic Limited Partners' net income per unit           $      2.68     $      2.57      $      1.75      $      1.02     $      0.90
                                                      ===========     ===========      ===========      ===========     ===========
Diluted Limited Partners' net income per unit(2)      $      2.67     $      2.57      $      1.75      $      1.02     $      0.90
                                                      ===========     ===========      ===========      ===========     ===========
Per unit cash distribution paid                       $      3.20     $      2.78      $      2.39      $      1.63     $      1.26
                                                      ===========     ===========      ===========      ===========     ===========
Additions to property, plant and equipment            $   125,523     $    82,725      $    38,407      $     6,884     $     8,575

BALANCE SHEET DATA (AT END OF PERIOD):
Net property, plant and equipment                     $ 3,306,305     $ 2,578,313      $ 1,763,386      $   244,967     $   235,994
Total assets                                          $ 4,625,210     $ 3,228,738      $ 2,152,272      $   312,906     $   303,603
Long-term debt                                        $ 1,255,453     $   989,101      $   611,571      $   146,824     $   160,211
Partners' capital                                     $ 2,117,067     $ 1,774,798      $ 1,360,663      $   150,224     $   118,344

OPERATING DATA:
Product Pipelines -
  Pacific - Mainline delivery volumes (MBbls)(3)          386,611         375,663          307,997               --              --
  Pacific - Other delivery volumes (MBbls)(3)              14,243          10,025           17,957               --              --
  Plantation - Delivery volumes (MBbls)                   226,795         214,900               --               --              --
  North System/Cypress - Delivery volumes (MBbls)          51,111          50,124           44,783           46,309          46,601
Natural Gas Pipelines - Transport volumes (Bcf)(4)          449.2           424.3               --               --              --
Carbon Dioxide Pipelines - Delivery volumes (Bcf)(5)        386.5           379.3               --               --              --
Bulk Terminals - Transload tonnage (Mtons)(6)              41,529          39,190           24,016            9,087           6,090
</TABLE>

(1)  Represents income before extraordinary charge per unit adjusted for the
     two-for-one split of units on October 1, 1997. Basic Limited Partners'
     income per unit before 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)  We acquired our Pacific operations on March 6, 1998.

(4)  KMIGT and Trailblazer assets were acquired on December 31, 1999. 1999
     volumes are shown for comparative purposes only.

(5)  Acquired remaining 80% interest in Kinder Morgan CO2 Company, L.P.,
     effective April 1, 2000. 2000 and 1999 volume information is adjusted to
     include properties acquired from Devon Energy effective June 1, 2000, and
     to correct volumes previously reported. 2000 and 1999 volume information is
     shown for comparative purposes only.

(6)  Represents the volumes of the Cora Terminal, excluding ship or pay volumes
     of 252 Mtons for 1996, the Grand Rivers Terminal from September 1997,
     Kinder Morgan Bulk Terminals from July 1, 1998 and the Pier IX and Shipyard
     Terminals from December 18, 1998.

(7)  Includes results of operations for KMIGT, 66 2/3% interest in Trailblazer
     Pipeline Company, 49% interest in Red Cedar, Milwaukee Bulk Terminals,
     Dakota Bulk Terminal, remaining 80% interest in KMCO2, Devon Energy
     carbon dioxide properties, Kinder Morgan Transmix Company, LLC, 32.5%
     interest in Cochin Pipeline System and Delta Terminal Services 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. Our
     remaining 80% interest in KMCO2 was acquired on April 1, 2000. The Devon
     Energy carbon dioxide properties were acquired on June 1, 2000. Buckeye
     Refining Company, LLC was acquired on October 25, 2000. Our 32.5% interest
     in Cochin was acquired on November 3, 2000, and Delta Terminal Services,
     Inc. was acquired on December 1, 2000.

(8)  Includes results of operations for 51% interest in Plantation Pipe Line
     Company, Product Pipelines' 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 Product Pipelines' transmix operations were acquired on September
     10, 1999, and our initial 33 1/3% investment in Trailblazer was made on
     November 30, 1999.

(9)  Includes results of operations for Pacific operations, Kinder Morgan Bulk
     Terminals, Inc. and the 24% interest in Plantation Pipe Line Company since
     the respective dates of acquisition. The Pacific operations were acquired
     March 6, 1998, Kinder Morgan Bulk Terminals were acquired on July 1, 1998
     and our 24% interest in Plantation Pipeline Company was acquired on
     September 15, 1998.


                                       49
<PAGE>   50

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

     You should read the following discussion and analysis in conjunction with
our Consolidated Financial Statements included elsewhere in this report.

RESULTS OF OPERATIONS

     Our financial results over the past three years reflect significant growth
in revenues, operating income and net income. During this timeframe, we made
numerous strategic business acquisitions and experienced strong growth in our
pipeline and terminal operations. The combination of targeted business
acquisitions, higher capital spending, favorable economic conditions and
management's continuing focus on controlling general and operating expenses
across our entire business portfolio led the way to strong growth in all four of
our business segments. In 2000, we reported record levels of revenue, operating
income, net income and earnings per unit.

     Our net income was $278.3 million ($2.67 per diluted unit) on revenues of
$816.4 million in 2000, compared to net income of $182.3 million ($2.57 per
diluted unit) on revenues of $428.7 million in 1999, and net income of $103.6
million ($1.75 per diluted unit) on revenues of $322.6 million in 1998. Included
in our net income for 1999 and 1998 were extraordinary charges associated with
debt refinancing transactions in the amount of $2.6 million in 1999 and $13.6
million in 1998. In addition, our 1999 net income included a benefit of $10.1
million related to the sale of our 25% interest in the Mont Belvieu
Fractionator, which separates natural gas liquids from natural gas, partially
offset by special non-recurring charges. Our total consolidated operating income
was $315.6 million in 2000, $187.4 million in 1999 and $140.7 million in 1998.
Our total consolidated net income before extraordinary charges was $278.3
million in 2000, $184.9 million in 1999 and $117.2 million in 1998.

     Our increase in overall net income and revenues in 2000 compared to
1999 primarily resulted from the inclusion of our Natural Gas Pipelines segment,
acquired from Kinder Morgan, Inc. on December 31, 1999, and our acquisition of
the remaining 80% ownership interest in Kinder Morgan CO2 Company, L.P.
(formerly Shell CO2 Company, Ltd.) effective April 1, 2000. Prior to that
date, we owned a 20% equity interest in Kinder Morgan CO2 Company, L.P. and
reported its results under the equity method of accounting. The results of
Kinder Morgan CO2 Company, L.P. are included in our CO2 Pipelines segment.
Our acquisition of substantially all of our Product Pipelines' transmix
operations in September 1999, and Milwaukee Bulk Terminals, Inc. and Dakota Bulk
Terminal, Inc. in January 2000, also contributed to our overall increase in
period-to-period revenues and net income.

     The inclusion of a full year of activity for our Pacific operations and
Bulk Terminals segment was the largest contributing factor for the increase in
total revenues and earnings in 1999 compared with 1998. We acquired our Pacific
operations in March 1998, Kinder Morgan Bulk Terminals, Inc. in July 1998 and
the Pier IX and Shipyard River terminals in December 1998.

     PRODUCT PIPELINES

     Our Product Pipelines' segment revenues increased 34%, from $314.1 million
in 1999 to $421.4 million in 2000, and net income increased 6%, from $209.0
million in 1999 to $221.2 million in 2000. The $107.3 million increase in
year-to-year segment revenues includes a $90.7 million increase in revenues
earned from transmix operations. The increase in transmix revenues resulted
primarily from the inclusion of a full year of operations from our initial
acquisition of transmix assets, acquired September 1999, and the inclusion of
two months of operations from additional transmix assets acquired in
late October 2000. The segment also reported revenues of $3.8 million from the
inclusion of two months of operations from our investment in the Cochin pipeline
system, which was acquired in November 2000. Furthermore, higher throughput
volumes on both our Pacific operations and North System pipelines contributed to
a $12.7 million increase in segment revenues. On our Pacific operations, average
tariff rates remained relatively flat between 2000 and 1999, with an almost 3%
increase in mainline delivery volumes resulting 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 demand from refineries in the Midwest, as well as a 5% increase in
average tariff rates.

     In 1998, the Product Pipelines segment earned $156.9 million on revenues of
$258.7 million. The $55.4 million increase in revenues in 1999 over 1998 relates
to the inclusion in 1999 of a full year of results from our Pacific operations,
acquired in March 1998, and the inclusion of almost four months of transmix
operations, which were


                                       50
<PAGE>   51
acquired in early September 1999. The acquired transmix assets produced
revenues of $18.3 million in 1999. Our Pacific operations reported a revenue
increase of $35.3 million in 1999 versus 1998. With a full twelve months of
activity reported in 1999, total mainline throughput volumes on our Pacific
operations pipelines increased 22% in 1999 compared to 1998. The higher 1999
segment revenues were partly offset by an almost 4% decrease in average tariff
rates on our Pacific pipelines. The decrease in average tariff rates was mainly
due to the reduction in transportation rates, effective April 1, 1999, on our
Pacific operation's East Line.

     Combined operating expenses for the Product Pipelines segment, which
include the segment's cost of sales, fuel, power and operating and maintenance
expenses, were $172.5 million in 2000, $76.5 million in 1999 and $56.3 million
in 1998. The increase in expenses in each year resulted mainly from the
inclusion of our transmix operations and the higher delivery volumes on our
Pacific operations pipelines. Depreciation and amortization expense was $41.7
million in 2000, $38.9 million in 1999 and $32.7 million in 1998, reflecting our
acquisitions, continued investments in capital additions and pipeline
expansions. Segment operating income was $193.5 million in 2000, $186.1 million
in 1999 and $159.2 million in 1998. Earnings from our equity investments, net of
amortization of excess costs, were $29.1 million in 2000, $21.4 million in 1999
and $5.9 million in 1998. The increases in our equity earnings each year were
chiefly due to our investments in Plantation Pipe Line Company. We acquired a
24% ownership interest in Plantation Pipe Line Company in September 1998 and an
additional 27% ownership interest in June 1999. Additionally, the Product
Pipelines segment benefited from favorable changes in non-operating
income/expense in 1999 compared to 1998, primarily the result of lower 1999
expense accruals made for our Federal Energy Regulatory Commission rate case
reserve (as a result of the Federal Energy Regulatory Commission's opinion
relating to an outstanding rate case dispute), 1999 insurance recoveries and
favorable adjustments to employee post-retirement benefit liabilities.

     We are parties to proceedings at the Federal Energy Regulatory Commission
and the California Public Utilities Commission that challenge our tariffs on our
Pacific operations. The Federal Energy Regulatory Commission complaint seeks
approximately $105 million in tariff refunds and approximately $35 million in
prospective annual tariff reductions. The California Public Utilities Commission
complaint seeks approximately $17 million in tariff refunds and approximately
$10 million in prospective annual tariff reductions. 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. 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 materially more favorable 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.

     NATURAL GAS PIPELINES

     Our Natural Gas Pipelines segment reported earnings of $112.9 million on
revenues of $173.0 million in 2000. These results were produced from assets that
we acquired from Kinder Morgan, Inc. on December 31, 1999. For comparative
purposes, transported gas volumes on our natural gas assets increased almost 6%
in 2000 compared with 1999 when these assets were owned by Kinder Morgan, Inc.
The overall increase includes an almost 9% increase in volumes shipped on the
Trailblazer Pipeline. 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 expenses totaled $51.2
million in 2000 and segment operating income was $97.2 million. Earnings for
2000 from the segment's 49% equity investment in Red Cedar Gathering Company,
net of amortization of excess costs, were $15.0 million.

     Segment results for 1999 and 1998 primarily represent activity from our
since divested partnership interest in the Mont Belvieu fractionation facility.
Segment earnings of $16.8 million in 1999 includes $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. In 1998, the segment reported earnings of $4.9 million,
including equity income of $4.6 million. This amount represents earnings from
our interest in the Mont Belvieu facility for a full twelve-month period.

     CO2 PIPELINES

     Our CO2 Pipelines segment consists of Kinder Morgan CO2 Company, L.P.
After our acquisition of the remaining 80% interest in Kinder Morgan CO2
Company, L.P., on April 1, 2000, we no longer accounted for our investment on an
equity basis. Our 2000 results also include the segment's acquisition of
significant carbon dioxide pipeline assets and oil-producing property interests
on June 1, 2000. For the year 2000, the segment reported


                                       51
<PAGE>   52

earnings of $68.0 million on revenues of $89.2 million. CO2 Pipelines reported
operating expenses of $26.8 million and operating income of $47.9 million.
Equity earnings from the segment's 50% interest in the Cortez Pipeline Company,
net of amortization of excess costs, were $19.3 million.

     Segment results from 1999 and 1998 primarily represent equity earnings
from our original 20% interest in Kinder Morgan CO2 Company, L.P. Segment
earnings of $15.2 million in 1999 include $14.5 million in equity earnings from
our interest in Kinder Morgan CO2 Company, L.P. In 1998, our CO2 Pipelines
segment reported earnings of $15.5 million, including $14.5 million in equity
earnings from our Kinder Morgan CO2 Company, L.P. investment. Under the terms
of the prior Kinder Morgan CO2 Company, L.P. partnership agreement, we
received a priority distribution of $14.5 million per year during 1998, 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.

     BULK TERMINALS

    Our Bulk Terminals segment reported its highest amount of revenues,
operating income and earnings in 2000. Following our acquisition of Kinder
Morgan Bulk Terminals, Inc. effective July 1, 1998, we continued to make
selective acquisitions and increase capital spending in order to grow and expand
our bulk terminal businesses. Our 2000 results include the operations of
Milwaukee Bulk Terminals, Inc. and Dakota Bulk Terminal, Inc., effective January
1, 2000, and Delta Terminal Services, Inc., acquired on December 1, 2000. The
1999 results include the full-year of operations for Kinder Morgan Bulk
Terminals, Inc. and the Pier IX and Shipyard River terminals, acquired on
December 18, 1998.

     The Bulk Terminals segment reported earnings of $37.6 million in 2000,
$35.0 million in 1999 and $19.2 million in 1998. Segment revenues were $132.8
million in 2000, $114.6 million in 1999 and $62.9 million in 1998. In addition
to our acquisitions made in 2000, which generated revenues of $11.4 million, our
Bulk Terminals segment's overall increases in year-to-year revenues were due to
a 10% increase in coal transfer revenues earned by the segment's Cora and Grand
Rivers coal terminals in 1999 and 2000. Combined, these two coal terminals
reported a $2.0 million increase in transfer revenues in 2000 over 1999 due to a
6% increase in coal volumes accompanied by a 4% increase in average coal
transfer rates. A $1.7 million increase in 1999 transfer revenues over 1998
transfer revenues resulted from an 18% increase in coal volumes handled at the
terminals, partially offset by a 7% decrease in average transfer rates. The
growth in the Bulk Terminals segment revenues over the two-year period was
partially offset by lower revenue from coal marketing activities.

     Bulk Terminals combined operating expenses totaled $81.7 million in 2000
compared to $66.6 million in 1999 and $36.9 million in 1998. 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. The increase in 1999 compared to 1998 was the result of including a
full year of operations for Kinder Morgan Bulk Terminals, Inc., partially offset
by higher 1998 cost of sales expenses related to purchase/sale marketing
contracts. Depreciation and amortization expense was $9.6 million in 2000, $7.5
million in 1999 and $3.9 million in 1998. The increases in depreciation were
primarily due to the addition of Kinder Morgan Bulk Terminals, Inc. and the Pier
IX and Shipyard River terminals in 1998 and the Milwaukee and Dakota Bulk
Terminals in 2000, and higher property balances as a result of increased capital
spending.

     OTHER

     Items not attributable to any segment include general and administrative
expenses, interest income and expense and minority interest. General and
administrative expenses totaled $60.1 million in 2000 compared with $35.6
million in 1999 and $40.0 million in 1998. The increase in our 2000 general and
administrative expenses over the prior year was mainly due to our larger and
more diverse operations. During 2000, we assimilated the operations of our
Natural Gas Pipelines and CO2 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 $93.3
million in 2000, $52.6 million in 1999 and $38.6 million in 1998. The increases
were primarily due to debt we assumed as part of the acquisition of our Pacific
operations as well as additional debt related to the financing of our 2000 and
1999 investments. Minority interest increased to $8.0 million in 2000 compared
with $2.9 million in 1999 and $1.0 million in 1998. The $5.1 million increase in
2000 over 1999 primarily resulted from the inclusion of earnings attributable to
the Trailblazer Pipeline Company. The $1.9 million increase in 1999 over 1998
resulted from higher earnings attributable to our Pacific operations as well as
to our higher overall income.



                                       52
<PAGE>   53
OUTLOOK

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

     o    Cost Reductions. We have reduced by approximately 15 percent 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 percentage 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 and Plantation Pipe Line Company. Generally, these
          reductions in expense have been achieved by eliminating functions
          which we and the acquired businesses each maintained prior to their
          combination. We expect to make similar percentage reductions in
          expenses of the recently acquired GATX pipelines and terminals and
          intend to continue to seek further reductions throughout our
          businesses where appropriate.

     o    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:

          o    completed the expansion of our San Diego Line in June 2000. The
               expansion project cost approximately $18 million and consisted of
               the construction of 23 miles of 16-inch diameter pipe and other
               appurtenant facilities. The new facilities will increase capacity
               on our San Diego Line by approximately 25%;

          o    entered into an agreement to provide pipeline transportation
               services on the North System for Aux Sable Liquid Products, L.P.
               in the Chicago area beginning in the first quarter of 2001;

          o    constructed a multi-million dollar cement import and distribution
               facility at the Shipyard River terminal, which was completed in
               the fourth quarter of 2000, as part of a 30 year cement contract
               with Blue Circle Cement;

          o    announced an expansion project on the Trailblazer Pipeline in
               August 2000. The project will involve the installation of two new
               compressor stations and the addition of horsepower at an existing
               compressor station; and

          o    continued a $13 million upgrade to the coal loading facilities at
               the Cora and Grand Rivers coal terminals. The two terminals
               handled an aggregate of 17.0 million tons of coal during 2000
               compared with 16.0 million tons in 1999.

     o    Strategic Acquisitions. Since January 1, 2000, we have made the
          following acquisitions:

          o    Milwaukee Bulk Terminals, Inc.                  January 1, 2000

          o    Dakota Bulk Terminal, Inc.                      January 1, 2000

          o    Kinder Morgan CO2 Company, L.P. (80%)           April 1, 2000

          o    CO2                                             June 1, 2000

          o    Transmix Assets                                 October 25, 2000

          o    Cochin Pipeline System                          November 3, 2000

          o    Delta Terminal Services, Inc.                   December 1, 2000

          o    Kinder Morgan Texas Pipeline L.P.               December 21, 2000

          o    Casper-Douglas Gas Gathering and Processing
               Assets                                          December 21, 2000

          o    Coyote Gas Treating, LLC (50%)                  December 21, 2000

          o    Thunder Creek Gas Services, LLC (25%)           December 21, 2000

          o    CO2 Investment to be contributed to
               Joint Venture with Marathon                     December 28, 2000

          o    Colton Transmix Processing Facility (50%)       December 31, 2000

          o    GATX Domestic Pipelines and Terminals           March 1, 2001 and
                                                               March 30, 2001

          o    Pinney Dock and Transportation Company          March 13, 2001



                                       53
<PAGE>   54
     The costs and methods of financing for each significant acquisition 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. 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 debt securities
and/or units.

     On February 14, 2001, we paid a quarterly distribution of $0.95 per unit
for the fourth quarter of 2000. The distribution for the fourth quarter of 1999
was $0.725 per unit. This distribution is 35% greater than the $0.775
distributed for the first quarter of 2000 and 11% greater than the $0.95
distributed for the fourth quarter of 2000.

LIQUIDITY AND CAPITAL RESOURCES

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

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

     o    expansion capital expenditures through additional borrowings or
          issuance of additional units;

     o    interest payments from cash flows from operating activities; and

     o    debt principal payments with additional borrowings as they become due
          or by the issuance of additional units.

     The scheduled maturities of our outstanding debt at December 31, 2000, are
summarized as follows (in thousands):

<TABLE>
<S>                                          <C>
                       2001                  $    683,649
                       2002                       253,116
                       2003                        37,016
                       2004                       207,617
                       2005                       199,670
                       Thereafter                 523,334
                                             ------------
                       Total                 $  1,904,402
                                             ============
</TABLE>

    Of the $683.6 million scheduled to mature in 2001, we intend and have the
ability to refinance $34.7 million on a long-term basis under our existing
credit facilities.

     At December 31, 2000, our current commitments for capital expenditures were
approximately $37 million. This amount has primarily been committed for the
purchase of plant and equipment. We expect to fund these commitments through
additional borrowings or the issuance of additional units. All of our capital
expenditures, with the exception of sustaining capital expenditures, are
discretionary.

     OPERATING ACTIVITIES

     Net cash provided by operating activities was $301.6 million in 2000
compared to $182.9 million in 1999. The $118.7 million increase in our
period-to-period cash flows from operations resulted from a net increase of
$118.5 million in cash receipts from the sales of services and products, net of
cash operating expenses. Higher net cash flows generated from sales and expenses
were primarily due to the business acquisitions and capital investments we made
during 2000. Other significant year-to-year changes in cash from operating
activities include:

     o    a $52.5 million payment of accrued rate refund liabilities;

     o    a $20.3 million increase in collections of trade receivables, net of
          payments on trade payables;

     o    a $13.8 million increase in distributions from equity investments; and

     o    a $11.3 million net increase in insurance receivables.

     The payment of the rate refunds was made under settlement agreements with
shippers on our natural gas pipelines. Higher cash inflows from collections on
accounts receivable, net of accounts payable payments, were mainly due to
collections from our natural gas pipelines, which were included in our 2000
operating results. The increase in distributions from equity investments was
mainly due to distributions we received in 2000 from our 50% ownership interest
in Cortez Pipeline Company and our 49% ownership interest in Red Cedar Gathering
Company. Following our acquisition of the remaining ownership interest in Kinder
Morgan CO2 Company, L.P. on April 1, 2000, we accounted for our investment in
Cortez Pipeline Company under the equity method of accounting. We acquired our
interest in Red Cedar Gathering Company from Kinder Morgan, Inc. on December 31,
1999. The


                                       54
<PAGE>   55
overall increase in distributions from equity investments was partially offset
by the absence of distributions from our original 20% interest in Kinder Morgan
CO2 Company, L.P. from April 1, 2000 through December 31, 2000 due to the fact
we no longer accounted for this investment on an equity basis. The increase in
cash flows from insurance receivables reflects higher collections on our Pacific
operations' insurance receivables.

     INVESTING ACTIVITIES

     Net cash used in investing activities was $1,197.6 million in 2000 compared
to $196.5 million in 1999, an increase of $1,001.1 million chiefly attributable
to the $1,008.6 million of asset acquisitions we made in 2000. Our 2000
acquisition outlays included:

     o    a $478.3 million payment to Kinder Morgan, Inc. for the Natural Gas
          Pipelines assets;

     o    a $188.9 million net payment for the remaining 80% interest in Kinder
          Morgan CO2 Company, L.P.;

     o    a $120.5 million payment for our 32.5% ownership interest in the
          Cochin Pipeline System;

     o    a $114.3 million payment for Bulk Terminal acquisitions, including
          Milwaukee Bulk Terminals, Inc., Dakota Bulk Terminal, Inc. and Delta
          Terminal Services, Inc.;

     o    a $53.4 million payment for our interests in the Canyon Reef Carriers
          CO2 Pipeline and SACROC oil field; and

     o    a $45.7 million payment for the acquisition of Kinder Morgan Transmix
          Company, LLC formerly Buckeye Refining Company, LLC.

     We expended an additional $42.8 million for capital expenditures in 2000
compared to 1999. Including expansion and maintenance projects, our capital
expenditures were $125.5 million in 2000 and $82.7 million in 1999. The increase
was driven primarily by continued investment in our Pacific operations and in
our Bulk Terminals business segment. Proceeds from the sale of investments,
property, plant and equipment, net of removal costs, were lower by $29.7 million
in 2000 versus 1999. Proceeds received from sales and retirements of
investments, property, plant and equipment were $13.4 million in 2000 and $43.1
million in 1999. The decrease was due to the $41.8 million we received for the
sale of our interest in the Mont Belvieu fractionation facility in September
1999.

     The overall increase in funds used in investing activities was offset by a
$82.4 million decrease in cash used for acquisitions of investments. We used
$79.4 million for acquisitions of investments in 2000 compared with $161.8
million in 1999.

     Our 2000 investment outlays included:

     o    $34.2 million for a 7.5% interest in the Yates oil field subsequently
          contributed to the carbon dioxide joint venture with Marathon Oil
          Company;

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

     Our 1999 investment outlays consisted of:

     o    $124.2 million for a 27% interest in Plantation Pipe Line Company
          (increasing our interest to 51%); and

     o    $37.6 million for a one-third interest in Trailblazer Pipeline
          Company.

     FINANCING ACTIVITIES

     Net cash provided by financing activities amounted to $915.3 million in
2000, an increase of $893.3 million from the prior year that was mainly the
result of an additional $817.1 million we received from overall debt financing
activities. The increase in borrowings was mainly due to 2000 acquisitions. We
completed a private placement of $400 million in debt securities during the
first quarter of 2000, resulting in a cash inflow of $397.9 million, net of
discounts and issuing costs. We completed a second private placement of $250
million in debt securities during the fourth quarter of 2000, resulting in a
cash inflow of $246.8 million, net of discounts and issuing costs. In addition,
we received $171.4 million as proceeds from our issuance of units during 2000,
most significantly realized from our public offering of 4,500,000 common units
on April 4, 2000. The overall increase in funds provided by our financing
activities was partially offset by a $102.8 million increase in our
distributions to partners. Distributions to


                                       55
<PAGE>   56
all partners increased to $293.6 million in 2000 compared to $190.8 million in
1999. The increase in distributions was due to:

     o    an increase in our per unit distributions paid;

     o    an increase in our number of units outstanding;

     o    our general partner incentive distributions, which resulted from
          increased distributions to our unitholders; and

     o    distributions paid by Trailblazer Pipeline Company, which were
          included in our consolidated results following the acquisition of our
          controlling 66 2/3% interest on December 31, 1999.

     We paid distributions of $3.20 per unit in 2000 compared to $2.775 per unit
in 1999. The 15% increase in paid distributions per unit resulted from favorable
operating results in 2000.

     PARTNERSHIP DISTRIBUTIONS

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

     Our general partner is granted discretion by our partnership agreement 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 our
general partner determines our quarterly distributions, they consider current
and expected reserve needs along with current and expected cash flows to
identify the appropriate sustainable distribution level. For 1998, 1999, and
2000 we distributed 93%, 97%, and 102%, of the total of cash receipts less cash
disbursements, respectively. The difference between these numbers and 100%
reflects net additions to or reductions in reserves.

     Our available cash is initially distributed 98% to our limited partners and
2% to our general partner, Kinder Morgan G.P., Inc. These distribution
percentages are modified to provide for incentive distributions to be made to
our general partner in the event that quarterly distributions to unitholders
exceed certain specified targets.

     Our available cash for each quarter is distributed:

     o    first, 98% to the owners of all classes of units pro rata and 2% to
          our general partner until the owners of all classes of units have
          received a total of $0.3025 per unit in cash for that quarter;

     o    second, 85% of any available cash then remaining to the owners of all
          classes of units pro rata and 15% to our general partner until the
          owners of all classes of units have received a total of $0.3575 per
          unit in cash for that quarter;

     o    third, 75% of any available cash then remaining to the owners of all
          classes of units pro rata and 25% to our general partner until the
          owners of all classes of units have received a total of $0.4675 per
          unit in cash for that quarter; and

     o    fourth, 50% of any available cash then remaining to the owners of all
          classes of units pro rata, in cash to owners of common units and
          Class B units, and 50% in cash to our general partner.

     Incentive distributions are generally defined as all cash distributions
made to our general partner that are in excess of 2% of the aggregate amount of
cash being distributed. The general partner's incentive distributions declared
by us for 2000 were $107,764,885, while the incentive distributions paid during
2000 were $89,399,771.

     DEBT AND CREDIT FACILITIES

     Our debt and credit facilities as of December 31, 2000, consist primarily
of:

     o    a $600 million unsecured 364-day credit facility due October 25, 2001,
          which also supports a commercial paper program of equivalent size;



                                       56
<PAGE>   57

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

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

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

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

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

     o    $20.2 million of Senior Secured Notes due September 2002 (Trailblazer
          Pipeline Company, of which we own 66 2/3%, is the obligor on the
          notes);

     o    $119 million of Series F First Mortgage Notes due December 2004 (our
          subsidiary, SFPP L.P., is the obligor on the notes); and

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

     First Union National Bank is the administrative agent under the $600
million and $300 million credit facilities referred to above.

     Interest on borrowings is payable quarterly. Interest on the credit
facilities accrues at our option at a floating rate equal to either:

     o    First Union National Bank's base rate (but not less than the Federal
          Funds Rate, plus .5%) (As of March 31, 2001, First Union National
          Bank's base rate was 8.0%); or

     o    LIBOR, plus a margin, which varies depending upon the credit rating of
          our long-term senior unsecured debt (As of March 31, 2001, we could
          borrow for one month at a rate of 5.5% under the 364-day facility and
          5.55% under the 5-year facility).

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

     The credit facilities include the following restrictive covenants:

     o    requirements to maintain certain financial ratios; total debt divided
          by EBITDA for the prior four quarters may not exceed 4.5 prior to July
          1, 2001 and 4.0 thereafter and EBITDA for the prior four quarters
          divided by interest expense for the prior four quarters may not fall
          below 3.0 prior to July 1, 2001 and 3.5 thereafter;

     o    restrictions 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;

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

     o    restrictions on granting liens;

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

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

     o    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.

     As of December 31, 2000, we had outstanding borrowings under our credit
facilities of $789.6 million. At December 31, 2000, the interest rate on our
credit facilities was 7.115% per annum. Our borrowings at December 31, 2000
included the following:

     o    $193 million borrowed to fund the purchase price of natural gas
          pipelines assets acquired in December 2000;

     o    $175 million used to pay the outstanding balance on SFPP, L.P.'s
          credit facility;

     o    $118 million borrowed to fund the purchase price of our 32.5% interest
          in the Cochin Pipeline system in December 2000;



                                       57
<PAGE>   58

     o    $114 million borrowed to fund the purchase price of Delta Terminal
          Services, Inc. in December 2000;

     o    $72 million borrowed to fund principal and interest payments on SFPP,
          L.P.'s Series F First Mortgage Notes in December 2000;

     o    $34 million borrowed to fund the purchase price of our 7.5% interest
          in the Yates oil field in December 2000; and

     o    $83.6 million borrowed to fund expansion capital projects.

     Our short-term debt at December 31, 2000, consisted of:

     o    $582 million of borrowings under our unsecured 364-day credit facility
          due October 25, 2001;

     o    $52 million of commercial paper borrowings;

     o    $35 million under SFPP L.P.'s 10.70% Series F First Mortgage Notes;
          and

     o    $14.6 million in other borrowings.

     During 2000, our cash used for acquisitions and expansions exceeded $600
million. 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 2001 through a
combination of long-term debt and equity. Based on prior successful short-term
debt refinancings and current market conditions, we do not anticipate any
liquidity problems.

     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, 2000, the
interest rate was 5.00%.

     In addition, as of December 31, 1999, we financed $330 million through
Kinder Morgan, Inc. to fund part of the acquisition of assets acquired from
Kinder Morgan, Inc. on December 31, 1999. In accordance with the Closing
Agreement entered into as of January 20, 2000, we paid Kinder Morgan, Inc. a per
diem fee of $180.56 for each $1,000,000 financed. We paid Kinder Morgan, Inc.
$200 million on January 21, 2000, and the remaining $130 million on March 23,
2000 with a portion of the proceeds from our issuance of notes on March 22,
2000.

     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 and then on October 25, 2000, in conjunction
with our new 364-day credit facility, we increased the commercial paper program
to provide for the issuance of up to $600 million of commercial paper.
Borrowings under our commercial paper program reduce the borrowings allowed
under our 364-day and five-year credit facilities combined. As of December 31,
2000, we had $52 million of commercial paper outstanding with an interest rate
of 7.02%.

     At December 31, 2000, the outstanding balance under SFPP, L.P.'s Series F
notes was $119.0 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. The Series F notes are payable in annual installments of
$39.5 million in 2001, $42.5 million in 2002 and $37.0 million in 2003. The
Series F notes may also be prepaid in full or in part at a price equal to par
plus, in certain circumstances, a premium. 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.

     At December 31, 1999, the outstanding balance under SFPP, L.P.'s bank
credit facility was $174 million. On August 11, 2000, we replaced the
outstanding balance under SFPP, L.P.'s secured credit facility with a $175
million unsecured borrowing under our five-year credit facility. SFPP, L.P.
executed a $175 million intercompany note in our favor to evidence this
obligation.

     In December 1999, Trailblazer Pipeline Company entered into a 364-day
revolving credit agreement with Toronto Dominion, Inc. providing for loans up to
$10 million. At December 26, 2000, the outstanding balance due


                                       58
<PAGE>   59

under Trailblazer Pipeline Company's bank credit facility was $10 million. On
December 27, 2000, Trailblazer Pipeline Company paid the outstanding balance
under its credit facility with a $10 million borrowing under an intercompany
account payable in favor of Kinder Morgan, Inc. 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 agreement
expires December 27, 2001. The borrowings were used to pay the account payable
to Kinder Morgan, Inc. At January 31, 2001, the outstanding balance under
Trailblazer Pipeline Company's revolving credit agreement was $10 million. The
agreement provides for an interest rate of LIBOR plus 0.875%. At January 31,
2001 the interest rate on the credit facility debt was 6.625%. Pursuant to the
terms of the revolving credit agreement with Credit Lyonnais New York Branch,
Trailblazer Pipeline Company partnership distributions are restricted by certain
financial covenants.

     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,
2000, consist of the following:

     o    $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 the proceeds to pay the outstanding balance on our
          credit facility and for working capital and other partnership
          purposes. At December 31, 2000, the unamortized liability balance on
          the 6.30% senior notes was $249.3 million;

     o    $200 million of floating rate notes due March 22, 2002 and $200
          million of 8.0% notes due March 15, 2005. We used the proceeds to
          reduce outstanding commercial paper. At December 31, 2000, the
          interest rate on our floating rate notes was 7.0%; and

     o    $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. At December 31, 2000, the
          unamortized liability balance on the 7.5% notes was $248.4 million.

     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.

     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. Trailblazer Pipeline Company provided security for the notes
principally by an assignment of certain Trailblazer Pipeline Company
transportation contracts. 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 security for
the notes, added a limitation on the amount of additional money that Trailblazer
Pipeline Company could borrow and relieved Trailblazer Pipeline Company from its
security deposit obligation. At December 31, 2000, Trailblazer Pipeline
Company's outstanding balance under the Senior Secured Notes was $20.2 million.
The Senior Secured Notes have a fixed annual interest rate of 8.03% and will be
repaid in semiannual installments of $5.05 million from March 1, 2001 through
September 1, 2002, the final maturity date. Interest is payable semiannually in
March and September. Pursuant to the terms of this Note Purchase Agreement,
Trailblazer Pipeline Company partnership distributions are restricted by certain
financial covenants. Currently, Trailblazer Pipeline Company's proposed
expansion project is pending before the Federal Energy Regulatory Commission. If
the expansion is approved, which is expected in the first quarter of 2001, we
plan to refinance these notes.

     CAPITAL REQUIREMENTS FOR RECENT TRANSACTIONS

    Milwaukee Bulk Terminals, Inc. Effective January 1, 2000, we acquired
Milwaukee Bulk Terminals, Inc. for approximately $14.6 million in aggregate
consideration consisting of $0.6 million and 0.3 million common units.

    Dakota Bulk Terminal, Inc. Effective January 1, 2000, we acquired
Dakota Bulk Terminal, Inc. for approximately $9.5 million in aggregate
consideration consisting of $0.2 million and 0.2 million common units.



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<PAGE>   60
    Kinder Morgan CO2 Company, L.P. On April 1, 2000, we acquired the
remaining 80% ownership interest in Shell CO2 Company, Ltd. that we did not
own for approximately $212.1 million before purchase price adjustments. We paid
this amount with approximately $171.4 million received from our public offering
of 4.5 million units on April 4, 2000 and approximately $40.7 million received
from the issuance of commercial paper.

     Carbon Dioxide Assets. On June 1, 2000, we acquired an interest in SACROC
oil field and Canyon Reef Carrier CO2 Pipeline assets from Devon Energy
Production Company, L.P. for approximately $55 million before purchase price
adjustments. We borrowed the necessary funds under our commercial paper program.

     Transmix Operations. On October 25, 2000, we acquired Kinder Morgan
Transmix Company, LLC, formerly known as Buckeye Refining Company, LLC, for
$45.6 million after purchase price adjustments. We borrowed the necessary funds
under our commercial paper program.

    Delta Terminal Services, Inc. Effective on December 1, 2000, we
acquired Delta Terminal Services, Inc. for $114.1 million. We borrowed $114
million under our credit facilities and our commercial paper program to fund
this acquisition.

     Cochin Pipeline. On November 3, 2000, we acquired a 32.5% ownership
interest in the Cochin Pipeline system for $120.5 million from NOVA Chemicals
Corporation. We borrowed $118 million under our credit facilities to partially
fund this acquisition.

     Colton Transmix Processing Facility. On December 31, 2000 we acquired an
additional 50% ownership interest in the Colton Transmix Processing Facility
from Duke Energy Merchants for $11.2 million. We borrowed the necessary funds
under our commercial paper program.

     Carbon Dioxide Joint Venture With Marathon Oil Company. On December 28,
2000, we paid $34.2 million for a 7.5% interest in the Yates oil field which was
subsequently contributed to a carbon dioxide joint venture with Marathon Oil
Company. The joint venture was formed on January 1, 2001. We borrowed $34
million under our credit facilities to fund this acquisition.

     Natural Gas Pipelines. On December 31, 2000, we acquired certain assets of
Kinder Morgan Inc. for approximately $349.0 million in aggregate consideration
consisting of $192.7 million, 0.64 million common units and 2.7 million Class B
units. We borrowed $193 million under our credit facilities to fund the cash
portion of the purchase price.

     GATX Acquisition. On February 22, 2001, we entered into an additional $1.1
billion unsecured credit facility that expires on December 31, 2001 with a
syndicate of financial institutions to fund the GATX acquisition. With the
proceeds from issuing $1 billion in notes described below, on March 23, 2001,
this facility was reduced by $600 million to $500 million. This facility
supports the issuance of commercial paper used to finance the GATX acquisition.
Following the closing of this offering, we expect to terminate this facility.
First Union National Bank, an affiliate of First Union Securities, Inc., is the
administrative agent under this facility. As of March 31, 2001, we could borrow
for one month at a rate of 5.5% under this 364-day facility. We issued $700
million of 6.75% notes due 2011 and $300 million of 7.40% notes due 2031 and
applied the proceeds to retire short-term debt used to fund the GATX
acquisition.

      Pinney Dock. On March 13, 2001, we purchased Pinney Dock and
Transportation Company for approximately $41.5 million in cash. We borrowed the
necessary funds under our commercial paper program.

     RISK MANAGEMENT

     The following discussion should be read in conjunction with note 14 to the
Consolidated Financial Statements included elsewhere in this report.

     To minimize the risk of price changes in the crude oil, natural gas liquids
and natural gas and associated transportation markets, 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,


                                       60
<PAGE>   61

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 parties from whom we purchase financial instruments are as follows:

<TABLE>
<CAPTION>
                                                   Credit Rating
                                                   -------------
<S>                                                <C>
Enron North American, Corp.                            BBB+
Reliant Energy Services, Inc.                          BBB
AEP Energy Services, Inc.                               A-
</TABLE>

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

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

     o    gas purchases; and

     o    system use and storage.

     Our risk management activities are only used in order to protect our profit
margins and we are prohibited 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. Gains and losses on hedging positions
are deferred and recognized as natural gas purchases expense in the periods in
which the underlying physical transactions occur.

     Through December 31, 2000, gains and losses on hedging positions have been
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 and crude oil. 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 $1.7 million of deferred
net gain as of January 1, 2001, being reported as part of other comprehensive
income in 2001, as well as subsequent changes in the market value of these
derivatives prior to consummation of the transaction being hedged.

     We measure the risk of price changes in the natural gas, natural gas
liquids and crude oil markets utilizing a Value-at-Risk model. Value-at-Risk is
a statistical measure of how much the marked-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 2000, Value-at-Risk reached a high of $6.2
million and a low of $0.0 million. Value-at-Risk at December 31, 2000, was $6.2
million and averaged $0.3 million for 2000.

     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.



                                       61
<PAGE>   62

YEAR 2000

     There was no interruption to any business operation because of any Year
2000 glitch in programming. All operations were running smoothly on January 1,
2000. All business operations ran smoothly on January 3, 2000, when a full staff
returned to work, and have continued running without incident throughout the
year. There have been no incidents of consequence reported by material
suppliers, customers or service providers, and no disruption to business through
any electronic interface with third party companies.

     Expenditures to handle the Year 2000 issue were less than the moneys
allocated and were not material. No further Year 2000 expenditures are planned.
We have contingency plans and emergency response plans to address any unexpected
incidents.

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 by
comparable terminology. In particular, statements, express or implied,
concerning future operating results or the ability to generate sales, income or
cash flow are forward-looking statements. Forward-looking statements are not
guarantees of performance. They involve risks, uncertainties and assumptions.
The future results of our operations may differ materially from those expressed
in these forward-looking statements. Many of the factors that will determine
these results are beyond our ability to control or predict. Specific factors
which could cause actual results to differ from those in the forward-looking
statements, include:

     o    price trends and overall demand for natural gas liquids, refined
          petroleum products, carbon dioxide, natural gas, coal and other bulk
          materials in the United States. Economic activity, weather,
          alternative energy sources, conservation and technological advances
          may affect price trends and demand;

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

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

     o    any difficulties or delays experienced by railroads in delivering
          products to the bulk terminals;

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

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

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

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

     o    the political and economic stability of the oil producing nations of
          the world.

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

     See Items 1 and 2 "Business and Properties - Risk Factors" for a more
detailed description of these and other factors that may affect the forward
looking statements. When considering forward looking statements, one should keep
in mind the risk factors described in "Risk Factors" above. The risk factors
could cause our actual results to differ materially from those contained in any
forward looking statement. We disclaim any obligation to update the above list
or to announce publicly the result of any revisions to any of the forward
looking statements to reflect future events or developments.

     In addition, our classification as a partnership for federal income tax
purposes means that we do not generally pay federal income taxes on our net
income. We do, however, pay taxes on the net income of subsidiaries that are
corporations. We are relying on a legal opinion from our counsel, and not a
ruling from the Internal Revenue Service, as to our proper classification for
federal income tax purposes. See Items 1 and 2 "Business and Properties - Tax
Treatment of Publicly Traded Partnerships Under the Internal Revenue Code."



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<PAGE>   63

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 and crude oil markets.
For a complete discussion of our risk management activities, see note 14 to the
Consolidated Financial Statements included elsewhere in this report.

     INTEREST RATE RISK

     The market risk inherent in our market risk sensitive 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, 2000 and 1999, the carrying values of our long-term
fixed rate debt were approximately $836.7 million and $460.6 million,
respectively, compared to fair values of $944.1 million and $471.9 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 2000 and 1999, respectively, would result in changes
of approximately $23.6 million and $12.8 million, respectively, in the fair
values of these instruments.

     The carrying value and fair value of our variable rate debt, including
accrued interest, was $1,070.5 million as of December 31, 2000 and $740.0
million as of December 31, 1999. 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 $7.4 million in our
annualized pre-tax earnings.

     As of December 31, 2000, we were party to interest rate swap agreements
with a notional principal amount of $200 million for the purpose of hedging the
interest rate risk associated with our variable rate debt obligations. A
hypothetical 10% change in the average interest rates related to these swaps
would not have a material effect on our annual pre-tax earnings.

     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, 2000, 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.


                                       63
<PAGE>   64

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 F-1.

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

     None.




                                       64
<PAGE>   65

                                    PART III

ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

DIRECTORS AND EXECUTIVE OFFICERS OF OUR GENERAL PARTNER

     As is commonly the case with publicly traded limited partnerships, we do
not employ any of the persons responsible for managing or operating our
business, but instead reimburse our general partner for its services. Set forth
below is certain information concerning the directors and executive officers 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. All officers serve at the discretion of the board of directors of
our general partner.

<TABLE>
<CAPTION>
     Name                          Age      Position with our General Partner
     ----                          ---      ---------------------------------
<S>                               <C>       <C>
     Richard D. Kinder             56       Director, Chairman and CEO
     William V. Morgan             57       Director, Vice Chairman and President
     Edward O. Gaylord             69       Director
     Gary L. Hultquist             57       Director
     Perry M. Waughtal             65       Director
     William V. Allison            53       President, Natural Gas Pipelines
     Thomas A. Bannigan            47       President, Products Pipelines
     David G. Dehaemers, Jr.       40       Vice President, Corporate Development
     Joseph Listengart             32       Vice President, General Counsel and Secretary
     Michael C. Morgan             32       Vice President, Strategy and Investor Relations
     C. Park Shaper                32       Vice President, Treasurer and Chief Financial Officer
     Thomas B. Stanley             50       President, Bulk Terminals
     James E. Street               44       Vice President, Human Resources and Administration
</TABLE>

     Richard D. Kinder was elected Director, Chairman and Chief Executive
Officer of our general partner in February 1997. From 1992 to 1994, Mr. Kinder
served as Chairman of our general partner. From October 1990 until December
1996, Mr. Kinder was President of Enron Corp. Enron and its affiliates and
predecessors employed Mr. Kinder for over 16 years.

     William V. Morgan was elected Director of our general partner in June 1994,
Vice Chairman of our general partner in February 1997 and President of our
general partner in November 1998. He has held legal and management positions in
the energy industry since 1975, including the presidencies of three major
interstate natural gas companies which are now a part of Enron: Florida Gas
Transmission Company, Transwestern Pipeline Company and Northern Natural Gas
Company. In addition, Mr. Morgan served as President of Cortez Holdings
Corporation, a pipeline investment company, from October 1992.through March
2000. Prior to joining Florida Gas in 1975, Mr. Morgan was engaged in the
private practice of law in Washington, D.C.

     Edward O. Gaylord was elected Director of our general partner in February
1997. Mr. Gaylord is the Chairman of the Board of Directors of Jacintoport
Terminal Company, a liquid bulk storage terminal on the Houston, Texas ship
channel. Mr. Gaylord also serves on the Board of Directors for EOTT Energy
Corporation, an oil trading and transportation company located in Houston,
Texas, Seneca Foods Corporation and Imperial Sugar Company.

    Gary L. Hultquist was elected Director of our general partner in October
1999. Mr. Hultquist is the Managing Director of Hultquist Capital, LLC, a San
Francisco-based strategic and merger advisory firm. He also serves as Chairman
and Chief Executive Officer of TitaniumX Corporation, a supplier of
high-performance storage disk substrates and magnetic media to the disk drive
industry. He is also a member of the Board of Directors of Rodel, Inc.
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 was elected Director of our general partner in April
2000. Mr. Waughtal is a Limited Partner and 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



                                       65
<PAGE>   66

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 was elected President, Natural Gas Pipelines of our
general partner in September 1999. He served as President, Pipeline Operations
of our general partner from February 1999 to September 1999. From April 1998 to
February 1999, he served as Vice President and General Counsel of our general
partner. From 1977 to April 1998, Mr. Allison was employed at Enron Corp. where
he held various executive positions, including President of Enron Liquid
Services Corporation, Florida Gas Transmission Company and Houston Pipeline
Company and Vice President and Associate General Counsel of Enron Corp. Prior to
joining Enron Corp., he was an attorney at the FERC.

    Thomas A. Bannigan was elected President, Products Pipelines of our general
partner in October 1999. Since 1980, Mr. Bannigan has held various legal and
management positions in the energy industry, including General Counsel and
Secretary of Plantation Pipe Line Company, and from May 1998 until October 1999,
President and Chief Executive Officer of Plantation Pipe Line Company.

     David G. Dehaemers, Jr. was elected Vice President, Corporate Development
of our general partner in January 2000. He was Treasurer of our general partner
from February 1997 to January 2000 and Vice President and Chief Financial
Officer of our general partner from July 1997 to January 2000. He served as
Secretary of our general partner from February 1997 to August 1997. From October
1992 to January 1997, he was Chief Financial Officer of Morgan Associates, Inc.,
an energy investment and pipeline management company. Mr. Dehaemers was
previously employed by the national CPA firms of Ernst & Whinney and Arthur
Young. He is a CPA, and received his undergraduate Accounting degree from
Creighton University in Omaha, Nebraska. Mr. Dehaemers received his law degree
from the University of Missouri-Kansas City and is a member of the Missouri Bar.

     Joseph Listengart was elected Vice President and General Counsel of our
general partner in October 1999. Mr. Listengart became an employee of our
general partner in March 1998 and was elected its Secretary in November 1998.
From March 1995 through February 1998, Mr. Listengart worked as an attorney for
Hutchins, Wheeler & Dittmar, a Professional Corporation. Mr. Listengart received
his Juris Doctor, magna cum laude, from Boston University in May 1994, his
Masters in Business Administration from Boston University in January 1995 and
his Bachelors of Arts degree in Economics from Stanford University in June 1990.

     Michael C. Morgan was elected Vice President, Strategy and Investor
Relations of our general partner in January 2000. He was Vice President,
Corporate Development of our general partner from February 1997 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 at PSI Energy,
Inc., an electric utility, including Assistant to the Chairman. 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.

     C. Park Shaper was elected Vice President, Treasurer and Chief Financial
Officer of our general partner in January 2000. Previously, 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 also served as Vice President and Chief Financial Officer of First
Data Analytics, a wholly-owned subsidiary of First Data Corporation, from 1997
until June 1999. From 1995 to 1997, he was a consultant with The Boston
Consulting Group. Mr. Shaper has prior experience with TeleCheck Services, Inc.
and as a management consultant with the Strategic Services Division of Andersen
Consulting. Mr. Shaper has a Bachelor of Science degree in Industrial
Engineering and a Bachelor of Arts degree in Quantitative Economics from
Stanford University. He also received a Master of Management degree from the
J.L. Kellogg Graduate School of Management at Northwestern University.

     Thomas B. Stanley was elected President, Bulk Terminals of our general
partner in August 1998. 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.



                                       66
<PAGE>   67

     James E. Street was elected Vice President, Human Resources and
Administration of our general partner in August 1999. From October 1996 to
August 1999, Mr. Street was Senior Vice President, Human Resources and
Administration for Coral Energy. Prior to joining Coral Energy, he was Vice
President, Human Resources of Enron Corp. from July 1989 to August 1992. Mr.
Street received a Bachelor of Science degree from the University of Nebraska at
Kearney in 1979 and a Masters of Business Administration degree from the
University of Nebraska at Omaha in 1984.







                                       67
<PAGE>   68

ITEM 11.  EXECUTIVE COMPENSATION

     We have no executive officers, but we are obligated to reimburse our
general partner for compensation paid to our general partner's executive
officers in connection with their operation of our business. The following table
summarizes all compensation paid to our general partner's chief executive
officer and to each of our general partner's four other most highly compensated
executive officers for services rendered to us during 2000, 1999 and 1998.

<TABLE>
<CAPTION>
                                                     Summary Compensation Table

                                                 Annual Compensation                  Long-Term Compensation
                                                                                              Awards
                                           --------------------------------        -----------------------------
                                                                                                        Units/
                                                                                   Restricted         KMI Shares
                                                                                     Stock            Underlying     All Other
Name and Principal Position                Year       Salary       Bonus(2)         Awards(3)           Options    Compensation(6)
---------------------------                ----      --------      --------        ----------         ----------   ---------------

<S>                                        <C>       <C>           <C>              <C>                <C>            <C>
Richard D. Kinder(1)                       2000      $      1      $     --         $     --                  --      $     --
   Director, Chairman and CEO              1999       150,003            --               --                  --         7,554
                                           1998       200,004            --               --                  --        13,584

David G. Dehaemers, Jr                     2000       200,000       300,000(4)       498,750           0/150,000(5)     10,920
   Vice President,                         1999       161,249       250,000(4)            --           0/250,000         7,408
      Corporate Development                1998       141,247       200,000               --                  --        34,393

Michael C. Morgan                          2000       200,000       300,000(4)       498,750           0/150,000(5)     10,836
   Vice President,                         1999       161,249       250,000(4)            --           0/250,000         7,408
      Strategy and Investor Relations      1998       141,247       200,000               --                  --        50,421

William V. Allison                         2000       200,000       300,000          498,750                  --        11,466
   President,                              1999       192,497       250,000               --           0/250,000         9,335
      Natural Gas Pipelines                1998        99,998       200,000               --            10,000/0        11,366

Joseph Listengart(7)                       2000       181,250       225,000          498,750             0/6,300        10,798
   Vice President,                         1999       124,336       175,000               --           0/175,000         5,890
      General Counsel and Secretary        1998       124,007       140,436               --             5,000/0        78,620
</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)  Amounts earned in year shown and paid the following year.

(3)  Represent shares of KMI stock awarded in 2001 that relate to performance in
     2000. Value computed as the number of shares awarded (10,000) times the
     closing price on date of grant ($49.875 at 01/17/01). Twenty five percent
     of the shares 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.

(4)  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 of our general partner's employees under the Executive
     Compensation Plan on a going forward basis. See "-Executive Compensation
     Plan."

(5)  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."

(6)  Represents 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 2000, contributions to Retirement
     Savings Plan, value of group-term life insurance exceeding $50,000 and
     parking compensation respectively were Messrs. Dehaemers ($10,200 / $420 /
     $300), Morgan ($10,200 / $336 / $300), Allison ($10,200 / $966 / $300) and
     Listengart ($10,200 / $298 / $300).

(7)  The 2000 options were granted in 2001, but relate to performance in 2000.
     The options were granted and became fully exercisable on 01/17/01 at a
     grant price of $49.875 per share.

                                       68
<PAGE>   69

     Retirement Savings Plan. Effective July 1, 1997, our general partner
established the Kinder Morgan Retirement Savings Plan, a defined contribution
401(k) plan, that permits all full-time employees of our general partner to
contribute 1% to 15% of base compensation, on a pre-tax basis, into participant
accounts. This plan was subsequently amended and merged to form the Kinder
Morgan Savings Plan. In addition to a mandatory contribution equal to 4% of base
compensation per year for each plan participant, our general partner may make
discretionary contributions in years when specific performance objectives are
met. 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 options at the employee's
discretion. In the first quarter of 2001, an additional 2% discretionary
contribution was made to individual accounts based on 2000 financial targets to
unitholders. 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.

     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% and total awards under the plan may not exceed 10%. 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 200,000 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. The board of directors of our general partner may,
however, terminate the plan 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% of the incentive compensation value to each of David
Dehaemers and Michael Morgan. Originally, 50% 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% of their awards,
or 1% 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% of their awards, or 1% 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.

     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
units. The total number of units available under the option plan is 250,000.
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 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 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 10,000 units in
any year. Our board of directors or the committee will determine the duration
and vesting of the options to employees at the time of grant. As of December 31,
2000, options for 206,800 units were granted to 99 employees of our general
partner and our subsidiaries. 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.




                                       69
<PAGE>   70

     The option plan also granted to each of our non-employee directors as of
April 1, 1998, an option to acquire 5,000 units at an exercise price equal to
the fair market value of the units on such date. In addition, each new
non-employee director will receive options to acquire 5,000 units on the first
day of the month following his or her election. Under this provision, as of
December 31, 2000, options for 15,000 units were granted to our 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.

     The following table sets forth certain information at December 31, 2000 and
for the fiscal year then ended with respect to unit options 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
have been granted unit options. No unit options were granted at an option price
below fair market value on the date of grant.

<TABLE>
<CAPTION>
                                      Aggregated Unit Option Exercises in 2000,
                                         and 2000 Year-End Unit Option Values

                                                             Number of Units
                                                           Underlying Unexercised           Value of Unexercised
                                                                Options at                  In-the-Money Options
                         Units Acquired       Value            2000 Year-End                 at 2000 Year-End(1)
Name                       on Exercise       Realized   Exercisable      Unexercisable    Exercisable  Unexercisable
----                     --------------      --------   -----------      -------------    -----------  -------------

<S>                             <C>             <C>        <C>               <C>            <C>           <C>
William V. Allison              --              --         6,000             4,000          $139,125      $ 92,750

Joseph Listengart               --              --         3,000             2,000          $ 65,250      $ 43,500
</TABLE>

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

     KMI Option Plan. Under Kinder Morgan, Inc.'s stock option plans, key
personnel of KMI and its affiliates, including employees of our general partner
and its 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, 2000 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. Dehaemers and Mr.
Morgan are the only persons named in the Summary Compensation Table that have
been granted KMI stock options during 2000. 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 expire 10 years after the date of grant.

<TABLE>
<CAPTION>
                                                     KMI Stock Option Grants in 2000

                               Number of     % of Total                                 Potential Realizable Value
                               Securities      Options                                    at Assumed Annual Rates
                               Underlying     Granted to   Exercise                     of Stock Price Appreciation
                                Options       Employees     Price       Expiration          for Option Term(1)
Name                            Granted        in 2000     Per Share       Date             5%              10%
----                           ----------    -----------   ---------    -----------     -----------      ----------

<S>                             <C>              <C>        <C>          <C>             <C>             <C>
David G. Dehaemers, Jr          150,000          12.8%      $33.125      04/20/2010      $3,124,820      $7,918,908

Michael C. Morgan               150,000          12.8%      $33.125      04/20/2010      $3,124,820      $7,918,908
</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 $53.96 and
$85.92, respectively. We express no opinion regarding whether this level of
appreciation will be realized and expressly disclaim any representation to that
effect.

                                       70
<PAGE>   71
<TABLE>
<CAPTION>
                                                 Aggregated KMI Stock Option
                                                 Exercises in 2000, and 2000
                                               Year-End KMI Stock Option Values

                                                               Number of Shares
                                                            Underlying Unexercised                Value of Unexercised
                                                                   Options at                      In-the-Money Options
                         Shares Acquired       Value              2000 Year-End                     at 2000 Year-End(1)
Name                       on Exercise        Realized    Exercisable       Unexercisable     Exercisable       Unexercisable
----                     ---------------      --------    -----------       -------------     -----------       -------------
<S>                      <C>                  <C>           <C>                <C>             <C>                <C>
David G. Dehaemers, Jr           --              --         212,500            187,500         $4,632,813         $5,320,313

Michael C. Morgan                --              --         212,500            187,500         $4,632,813         $5,320,313

William V. Allison               --              --          62,500            187,500         $1,773,438         $5,320,313

Joseph Listengart                --              --          43,750            131,250         $1,241,406         $3,724,219
</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. 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 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 are credited with the current fair value of any benefits
they have previously accrued through the defined benefit plan. On January 1,
2001, we commenced 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. Interest is credited to the
employee's personal retirement account 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. Our general partner'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 our
general partner, participate in the deliberations of the board of directors of
our general partner concerning executive officer compensation. Messrs. Kinder
and Morgan each receive $1.00 annually in total compensation for services to KMI
and us.

     Directors fees. During 2000, each of the three non-employee members of the
board of directors of our general partner was paid an annual retainer of $25,000
in lieu of all attendance fees. Non-employee directors will each receive $10,000
for each quarter in 2001 in which they serve on the board of directors.

     Employment agreements. In April 2000, Mr. David G. Dehaemers, Jr. and Mr.
Michael C. Morgan entered into four-year employment agreements with Kinder
Morgan, Inc. and our general partner. Under the employment agreements, each of
Mr. 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. A copy of each employment agreement has been
filed as an exhibit to this report.

                                       71
<PAGE>   72



ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     The following table sets forth information as of February 15, 2001,
regarding (a) the beneficial ownership of (i) our units and (ii) the common
stock of Kinder Morgan, Inc., the parent company of our general partner, by all
directors of our general partner, each of the named executive officers and all
directors and executive officers as a group and (b) all persons known by our
general partner to own beneficially more than 5% of our units.

<TABLE>
<CAPTION>
                                                   Amount and Nature of Beneficial Ownership(1)

                                                    Common Units                  Class B Units              KMI Voting Stock
                                               -----------------------       ----------------------      ------------------------
                                                 Number       Percent          Number      Percent          Number       Percent
                                               of Units(2)    of Class       of Units(3)   of Class      of Shares(4)    of Class
                                               -----------    --------       -----------   --------      ------------    --------

<S>                                               <C>            <C>        <C>            <C>            <C>             <C>
Richard D. Kinder(5)                              145,000            *             --          --         23,989,992      20.87%

William V. Morgan(6)                                2,000            *             --          --          4,500,000       3.92%

Edward O. Gaylord(7)                               19,000            *             --          --                 --         --

Gary L. Hultquist(8)                                2,500            *             --          --                 --         --

Perry M. Waughtal                                  10,000            *             --          --             10,000            *

William V. Allison(9)                               6,000            *             --          --             85,000            *

David G. Dehaemers, Jr.(10)                         4,000            *             --          --            197,500            *

Joseph Listengart(11)                               4,699            *             --          --             49,050            *

Michael C. Morgan(12)                               2,500            *             --          --            223,500            *

Directors and Executive                           261,765            *             --          --         29,227,690      25.29%
     Officers as a group (13 persons)(13)

Goldman, Sachs & Co.(14)                        4,894,303       7.55%              --          --                 --         --

Kinder Morgan, Inc.(15)                        11,312,000      17.44%       2,656,700      100.00%                --         --
</TABLE>

*Less than 1%

(1)  Except as noted otherwise, all units and KMI shares involve sole voting
     power and sole investment power.

(2)  As of February 15, 2001, we had 64,861,509 common units issued and
     outstanding.

(3)  As of February 15, 2001, we had 2,656,700 class B units issued and
     outstanding.

(4)  As of February 15, 2001, Kinder Morgan, Inc. ("KMI") had a total of
     114,931,387 shares of outstanding voting common stock.

(5)  Does not include (a) 2,987 common units owned by Mr. Kinder's spouse, Nancy
     G. Kinder (b) 463,683 KMI shares held by a Kinder family charitable
     foundation, a charitable not-for-profit corporation and (c) 2,500 KMI
     shares held by Mrs. Kinder. Mr. Kinder disclaims any and all beneficial or
     pecuniary interest in these units and shares.

(6)  Morgan Associates, Inc., a Kansas corporation, wholly owned by Mr. 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 Morgan
     Associates, Inc.

(7)  Includes options to purchase 4,000 common units exercisable within 60 days
     of February 15, 2001.

(8)  Includes options to purchase 2,000 common units exercisable within 60 days
     of February 15, 2001.

(9)  Includes options to purchase 6,000 common units and 75,000 KMI shares
     exercisable within 60 days of February 15, 2001, and includes 10,000 shares
     of restricted KMI stock, 25% of which vests on each of the first four
     anniversaries after the date of grant.

(10) Includes options to purchase 187,500 KMI shares exercisable within 60 days
     of February 15, 2001, and includes 10,000 shares of restricted KMI stock,
     25% of which vests on each of the first four anniversaries after the date
     of grant.

(11) Includes options to purchase 4,000 common units and 39,050 KMI shares
     exercisable within 60 days of February 15, 2001, and includes 10,000 shares
     of restricted KMI stock, 25% of which vests on each of the first four
     anniversaries after the date of grant.

(12) Includes options to purchase 212,500 KMI shares exercisable within 60 days
     of February 15, 2001, and includes 10,000 shares of restricted KMI stock,
     25% of which vests on each of the first four anniversaries after the date
     of grant.

(13) Includes options to purchase 22,000 common units and 656,200 KMI shares
     exercisable within 60 days of February 15, 2001, and includes 65,000 shares
     of restricted KMI stock, 25% of which vests on each of the first four
     anniversaries after the date of grant.

(14) As reported on the Schedule 13G/A filed February 13, 2001 by The Goldman
     Sachs Group, Inc. and Goldman, Sachs & Co. The Goldman Sachs companies
     report that they have sole voting power over 0 common units, shared voting
     power over 4,894,303 common units, sole disposition power over 0 common
     units and shared disposition power over 4,894,303 common units. The Goldman
     Sachs companies' address is 10 Hanover Square, New York, New York 10005.

(15) Kinder Morgan, Inc.'s address is 500 Dallas St., Ste. 1000, Houston, Texas
     77002. Common units owned include units owned by KMI and its subsidiaries,
     including 862,000 common units held by Kinder Morgan G.P., Inc.



                                       72
<PAGE>   73

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

GENERAL AND ADMINISTRATIVE EXPENSES

     Our general partner provides us with general and administrative services
and is entitled to reimbursement of all direct and indirect costs related to our
business activities. Our general partner incurred general and administrative
expenses of $54.4 million in 2000, $30.7 million in 1999 and $38.0 million in
1998.

     Since K N Energy, Inc. acquired Kinder Morgan (Delaware), Inc. in October
1999, our general partner has shared administrative personnel with KMI to
operate both KMI's business and our business. As a result, our general partner's
officers, who in some cases may also be officers of KMI, must allocate, in their
reasonable and sole discretion, the time our general partner's employees and
KMI's employees spend on behalf of KMI and on behalf of us. For 2000, KMI paid
our general partner a net payment of $1.0 million in January 2001 as
reimbursement for the services of our general partner's employees. Although we
believe this amount received from KMI for the services it provided in 2000
fairly reflects the net value of the services performed, the determination of
this amount was not the result of arms length negotiations. However, due to the
nature of the allocations, this reimbursement may not have exactly matched the
actual time and overhead spent. We believe the agreed-upon amount was a
reasonable allocation of the expenses for the services rendered. Our general
partner and KMI will continue to evaluate the net amount to be charged for the
services provided to KMI and us by the employees of our general partner and KMI.

PARTNERSHIP DISTRIBUTIONS

     See Item 7. for information regarding Partnership Distributions.

ASSET ACQUISITIONS

     Effective December 31, 2000, we acquired over $300 million of assets from
KMI. As consideration for these assets, we paid to KMI $192.7 million, 640,000
common units and 2,656,700 Class B units. The common units and Class B units
were valued at $156.3 million. We acquired Kinder Morgan Texas Pipeline, L.P.
and MidCon NGL Corp., 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 not the result of arms length negotiation, but 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 KMIGT, 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, KMIGT 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. For 2000, this amount was $6.1 million. For 2001, the
amount will increase to $9.6 million due to the addition of the natural gas
assets acquired from KMI in December 2000. See "Asset Acquisitions" discussed
above. Although we believe the amount paid to KMI for the services provided by
them in 2000 fairly reflects the value of the services performed, the
determination of this amount was not the result of arms length negotiation.
However, due to the nature of the allocations, this reimbursement may not have
exactly matched the actual time and overhead spent. We believe the agreed-upon
amount was, 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 subsidiaries in performing such services. We also reimburse KMI and its



                                       73
<PAGE>   74

subsidiaries for operating and maintenance costs and capital expenditures
incurred with respect to these assets.

OTHER

     Our general partner makes all decisions relating to the management of our
business, and KMI owns all the common stock of our general partner. Certain
conflicts of interest could arise as a result of the relationships among 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, our general partner has a fiduciary duty to manage us in a
manner beneficial to our unitholders. The partnership agreements contain
provisions that allow our general partner 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 our general partner to our unitholders. Our general
partner's Conflicts and Audit Committee of the board of directors will, at the
request of our general partner, 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.






                                       74
<PAGE>   75


                                     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 F-1.

      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, 2000
                                   -----------------------------------------------------------------------------------
                                    Balance at                  Additions                                   Balance at
                                   Beginning of   Charged to costs     Charged to                             End of
                                     Period         and expenses    other 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                                 Balance at
                                  Beginning of    Charged to costs    Charged to                            End of
                                     Period         and expenses    other accounts    Deductions(1)         Period
                                  ------------    ----------------  --------------    -------------       ----------

<S>                                  <C>               <C>              <C>              <C>                <C>
Allowance for Doubtful Accounts      $ 9,883           $   --           $   --           $(3,166)           $ 6,717
</TABLE>

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

<TABLE>
<CAPTION>
                                                                    Year Ended December 31, 1998
                                     --------------------------------------------------------------------------------------------
                                      Balance at                      Additions                                        Balance at
                                     Beginning of       Charged to costs       Charged to                                End of
                                        Period            and expenses      other accounts(1)      Deductions            Period
                                     ------------       ----------------    -----------------      ----------          ----------

<S>                                    <C>                  <C>                  <C>                <C>                  <C>
Allowance for Doubtful Accounts        $     --             $     --             $9,883             $     --             $9,883
</TABLE>

(1) Additions of $5,441 represent the allowance recognized when we acquired our
Pacific operations and our Bulk Terminals. Additions of $4,442 represent a
revaluation of the allowance account.

      (a)(3) EXHIBITS

       *2.1     -   Stock Purchase Agreement dated November 30, 2000 between
                    GATX Rail Corporation, GATX Terminals Holding Corporation
                    and Kinder Morgan Energy Partners, L.P. (filed as Exhibit
                    99(b) to the Partnership's Current Report on Form 8-K filed
                    December 1, 2000)

       *3.1     -   Second Amended and Restated Agreement of Limited Partnership
                    of Kinder Morgan Energy Partners, L.P. effective as of
                    February 14, 1997 (filed as Exhibit 3.1 to Amendment No. 1
                    to Kinder Morgan Energy Partners, L.P. Registration
                    Statement on Form S-4, file No. 333-46709, filed on
                    April 14, 1998)


                                       75
<PAGE>   76

       *3.2     -   Amendment No. 1 to Second Amended and Restated Agreement of
                    Limited Partnership of Kinder Morgan Energy Partners, L.P.
                    dated as of January 20, 2000 (filed as Exhibit 4.1 to the
                    Partnership's Current Report on Form 8-K filed
                    January 20, 2000).

        3.3     -   Amendment No. 2 to Second Amended and Restated Agreement of
                    Limited Partnership of Kinder Morgan Energy Partners, L.P.
                    dated as of December 21, 2000.

       *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     -   Registration Rights Agreement dated March 22, 2000 among
                    Kinder Morgan Energy Partners, Goldman, Sachs & Co.,
                    Merrill Lynch & Co., Banc of America Securities LLC and
                    First Union Securities, Inc. (filed as Exhibit 4.3 to
                    the April 2000 Form S-4).

        4.8     -   Indenture dated November 8, 2000 between Kinder Morgan
                    Energy Partners and First Union National Bank, as Trustee.

        4.9     -   Form of 7.50% Note (contained in the Indenture filed as
                    Exhibit 4.8).

        4.10    -   Registration Rights Agreement dated November 8, 2000
                    between Kinder Morgan Energy Partners and Banc of America
                    Securities LLC.

        4.11    -   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).

        4.12    -   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).

        4.13    -   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. Section 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
                    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).


                                       76
<PAGE>   77

     * 10.6     -   Intrastate Pipeline system Lease, dated December 31, 1996,
                    between MidCon Texas Pipeline, L.P. and MidCon Texas
                    Pipeline Operator, Inc. (filed as Exhibit 10(y) to Kinder
                    Morgan, Inc.'s 1997 Form 10-K).

     * 10.7     -   Amendment Number One to Intrastate Pipeline system Lease,
                    dated December 31, 1996, between MidCon Texas Pipeline,
                    L.P. and MidCon Texas Pipeline Operator, Inc. (filed as
                    Exhibit 10(z) to Kinder Morgan, Inc.'s 1997 Form 10-K).

       21.1     -   List of Subsidiaries.

     **23.1     -   Consent of PricewaterhouseCoopers LLP.

---------
 * Asterisk indicates exhibits incorporated by reference as indicated.

** Double asterisk indicates exhibit filed with this Form 10-K/A.

All other exhibits filed with Form 10-K for the year ended December 31, 2000.

(b) REPORTS ON FORM 8-K

     Report dated November 6, 2000, on Form 8-K was filed on November 6, 2000,
pursuant to Item 9 of that form. Notice that on November 6, 2000, Kinder Morgan,
Inc., a subsidiary of which serves as general partner of Kinder Morgan Energy
Partners, L. P., and the Partnership intend to make a presentation to a group of
analysts and others to address various strategic and financial issues relating
to the business plans and objectives of Kinder Morgan, Inc. and the Partnership
was disclosed pursuant to Item 9. Furthermore, notice was given that Kinder
Morgan, Inc. and the Partnership maintain a web site at www.kindermorgan.com, on
which Kinder Morgan, Inc. and the Partnership have posted the materials
furnished pursuant to this Item 9. A copy of the visual portion of the materials
to be presented and discussed at the meeting was furnished as an exhibit and was
incorporated by reference into this Item 9.

     Report dated November 30, 2000, on Form 8-K was filed on December 1, 2000,
pursuant to Items 5, 7 and 9 of that form. Notice of a press release announcing
a definitive agreement with GATX to acquire its U.S. pipeline and terminal
businesses was disclosed pursuant to Item 5. The press release and Stock
Purchase Agreement between GATX Rail Corporation, GATX Terminals Holding
Corporation and Kinder Morgan Energy Partners, L.P. were filed as exhibits
pursuant to Item 7. Notice of a live web cast conference call on December 1,
2000, with a group of analysts and others to discuss the proposed purchase by
the Partnership of GATX Corporation's U.S. pipeline and terminal businesses, and
various strategic and financial issues relating to the business plans and
objectives of Kinder Morgan, Inc. and the Partnership was disclosed pursuant to
Item 9.

     Report dated December 7, 2000, on Form 8-K was filed on December 7, 2000,
pursuant to Items 5 and 7 of that form. Notice that on December 4, 2000, the
Partnership issued a press release announcing that it has purchased Delta
Terminal Services, Inc. for approximately $114 million in cash was disclosed
pursuant to Item 5. A copy of the press release was disclosed as an exhibit
pursuant to Item 7.




                                       77
<PAGE>   78

                          INDEX TO FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
                                                                                Page
                                                                                ----
<S>                                                                             <C>
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES



Report of Independent Accountants                                                F-2



Consolidated Statements of Income for the years ended December 31, 2000, 1999,
  and 1998                                                                       F-3



Consolidated Balance Sheets for the years ended December 31, 2000 and 1999       F-4



Consolidated Statements of Cash Flows for the years ended December 31, 2000,
  1999, and 1998                                                                 F-5



Consolidated Statements of Partners' Capital for the years ended December 31,
  2000, 1999, and 1998                                                           F-6



Notes to Consolidated Financial Statements                                       F-7
</TABLE>


Certain supplementary financial statement schedules have been omitted because
the information required to be set forth therein is either not applicable or is
shown in the financial statements or notes thereto.




                                      F-1
<PAGE>   79


                        REPORT OF INDEPENDENT ACCOUNTANTS

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

In our opinion, the accompanying consolidated balance sheets and the related
consolidated statements of income, of cash flows and of partners' capital
present fairly, in all material respects, the financial position of Kinder
Morgan Energy Partners, L.P. and its subsidiaries (the Partnership) at December
31, 2000 and 1999, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 2000 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 75, 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.




PricewaterhouseCoopers LLP

Houston, Texas
February 14, 2001




                                      F-2
<PAGE>   80
              KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
                        CONSOLIDATED STATEMENTS OF INCOME
                     (In Thousands Except Per Unit Amounts)

<TABLE>
<CAPTION>
                                                                       Year Ended December 31,
                                                               ---------------------------------------
                                                                 2000           1999           1998
                                                               ---------      ---------      ---------

<S>                                                            <C>            <C>            <C>
Revenues
  Services                                                     $ 653,968      $ 393,131      $ 301,671
  Product sales and other                                        162,474         35,618         20,946
                                                               ---------      ---------      ---------
                                                                 816,442        428,749        322,617
                                                               ---------      ---------      ---------
Costs and Expenses
  Cost of products sold                                          124,641         16,241          5,860
  Operations and maintenance                                     164,379         95,121         65,022
  Fuel and power                                                  43,216         31,745         22,385
  Depreciation and amortization                                   82,630         46,469         36,557
  General and administrative                                      60,065         35,612         39,984
  Taxes, other than income taxes                                  25,950         16,154         12,140
                                                               ---------      ---------      ---------
                                                                 500,881        241,342        181,948
                                                               ---------      ---------      ---------

Operating Income                                                 315,561        187,407        140,669

Other Income (Expense)
  Earnings from equity investments                                71,603         42,918         25,732
  Amortization of excess cost of equity investments               (8,195)        (4,254)          (764)
  Interest, net                                                  (93,284)       (52,605)       (38,600)
  Other, net                                                      14,584         14,085         (7,263)
  Gain on sale of equity interest, net of special charges             --         10,063             --
Minority Interest                                                 (7,987)        (2,891)          (985)
                                                               ---------      ---------      ---------

Income Before Income Taxes and Extraordinary Charge              292,282        194,723        118,789

Income Taxes                                                     (13,934)        (9,826)        (1,572)

Income Before Extraordinary Charge                               278,348        184,897        117,217

Extraordinary Charge on Early Extinguishment of Debt                  --         (2,595)       (13,611)
                                                               ---------      ---------      ---------
Net Income                                                     $ 278,348      $ 182,302      $ 103,606
                                                               =========      =========      =========

Calculation of Limited Partners' Interest in Net Income:
Income Before Extraordinary Charge                             $ 278,348      $ 184,897      $ 117,217
Less: General Partner's interest in Net Income                  (109,470)       (56,273)       (33,447)
                                                               ---------      ---------      ---------
Limited Partners' Net Income before Extraordinary Charge         168,878        128,624         83,770
Less: Extraordinary Charge on Early Extinguishment of Debt            --         (2,595)       (13,611)
                                                               ---------      ---------      ---------
Limited Partners' Net Income                                   $ 168,878      $ 126,029      $  70,159
                                                               =========      =========      =========

Basic Limited Partners' Net Income per Unit:
Income before Extraordinary Charge                             $    2.68      $    2.63      $    2.09
Extraordinary Charge                                                  --           (.06)          (.34)
                                                               ---------      ---------      ---------
Net Income                                                     $    2.68      $    2.57      $    1.75
                                                               =========      =========      =========
Weighted Average Units Outstanding                                63,106         48,974         40,120
                                                               =========      =========      =========

Diluted Limited Partners' Net Income per Unit:
Income before Extraordinary Charge                             $    2.67      $    2.63      $    2.09
Extraordinary Charge                                                  --           (.06)          (.34)
                                                               ---------      ---------      ---------
Net Income                                                     $    2.67      $    2.57      $    1.75
                                                               =========      =========      =========
Weighted Average Units Outstanding                                63,150         48,993         40,121
                                                               =========      =========      =========
</TABLE>

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

                                       F-3

<PAGE>   81

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

<TABLE>
<CAPTION>
                                                                            December 31,
                                                                     -------------------------
                                                                        2000           1999
                                                                     ----------     ----------

<S>                                                                  <C>            <C>
ASSETS
Current Assets
   Cash and cash equivalents                                         $   59,319     $   40,052
   Accounts and notes receivable
     Trade                                                              345,065         71,738
     Related parties                                                      3,384             45
   Inventories
     Products                                                            24,137          8,380
     Materials and supplies                                               4,972          4,703
   Gas imbalances                                                        26,878          7,014
   Gas in underground storage                                            27,481             --
   Other current assets                                                  20,025             --
                                                                     ----------     ----------
                                                                        511,261        131,932
                                                                     ----------     ----------

Property, Plant and Equipment, net                                    3,306,305      2,578,313
Investments                                                             417,045        418,651
Notes receivable                                                          9,101         10,041
Intangibles, net                                                        345,305         56,630
Deferred charges and other assets                                        36,193         33,171
                                                                     ----------     ----------
TOTAL ASSETS                                                         $4,625,210     $3,228,738
                                                                     ==========     ==========

LIABILITIES AND PARTNERS' CAPITAL
Current Liabilities
   Accounts payable
     Trade                                                           $  293,268     $   15,692
     Related parties                                                      8,255          3,569
   Current portion of long-term debt                                    648,949        209,200
   Accrued rate refunds                                                   1,100         36,607
   Deferred Revenues                                                     43,978             --
   Gas imbalances                                                        48,834          6,189
   Accrued other liabilities                                             54,572         47,904
                                                                     ----------     ----------
                                                                      1,098,956        319,161
                                                                     ----------     ----------

Long-Term Liabilities and Deferred Credits
   Long-term debt                                                     1,255,453        989,101
   Other                                                                 95,565         97,379
                                                                     ----------     ----------
                                                                      1,351,018      1,086,480
                                                                     ----------     ----------
Commitments and Contingencies (Notes 13 and 16)

Minority Interest                                                        58,169         48,299
                                                                     ----------     ----------
Partners' Capital
   Common Units (64,858,109 and 59,137,137 units issued
    and outstanding at December 31, 2000 and 1999, respectively)      1,957,357      1,759,142
   Class B Units (2,656,700 and 0 units issued
    and outstanding at December 31, 2000 and 1999, respectively)        125,961             --
   General Partner                                                       33,749         15,656
                                                                     ----------     ----------
                                                                      2,117,067      1,774,798
                                                                     ----------     ----------
TOTAL LIABILITIES AND PARTNERS' CAPITAL                              $4,625,210     $3,228,738
                                                                     ==========     ==========
</TABLE>

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

                                      F-4
<PAGE>   82

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

<TABLE>
<CAPTION>
                                                                                         Year Ended December 31,
                                                                              ---------------------------------------------
                                                                                  2000            1999             1998
                                                                              -----------      -----------      -----------

<S>                                                                           <C>              <C>              <C>
Cash Flows From Operating Activities
Reconciliation of net income to net cash provided by operating activities
    Net income                                                                $   278,348      $   182,302      $   103,606
    Extraordinary charge on early extinguishment of debt                               --            2,595           13,611
    Depreciation and amortization                                                  82,630           46,469           36,557
    Amortization of excess cost of equity investments                               8,195            4,254              764
    Earnings from equity investments                                              (71,603)         (42,918)         (25,732)
    Distributions from equity investments                                          47,512           33,686           19,670
    Gain on sale of equity interest, net of special charges                            --          (10,063)              --
    Changes in components of working capital
      Accounts receivable                                                           6,791          (12,358)           1,203
      Other current assets                                                         (6,872)              --               --
      Inventories                                                                  (1,376)          (2,817)            (734)
      Accounts payable                                                             (8,374)          (9,515)             197
      Accrued liabilities                                                          26,479           11,106          (14,115)
      Accrued taxes                                                                (1,302)             497           (1,266)
    Rate refunds settlement                                                       (52,467)              --               --
    El Paso settlement                                                                 --               --           (8,000)
    Other, net                                                                     (6,394)         (20,382)           8,220
                                                                              -----------      -----------      -----------
Net Cash Provided by Operating Activities                                         301,567          182,856          133,981
                                                                              -----------      -----------      -----------

Cash Flows From Investing Activities
    Acquisitions of assets                                                     (1,008,648)           5,678         (107,144)
    Additions to property, plant and equipment for
        expansion and maintenance projects                                       (125,523)         (82,725)         (38,407)
    Sale of investments, property, plant and equipment,
        net of removal costs                                                       13,412           43,084               64
    Acquisitions of investments                                                   (79,388)        (161,763)        (135,000)
    Other                                                                           2,581             (800)          (1,234)
                                                                              -----------      -----------      -----------
Net Cash Used in Investing Activities                                          (1,197,566)        (196,526)        (281,721)
                                                                              -----------      -----------      -----------

Cash Flows From Financing Activities
    Issuance of debt                                                            2,928,304          550,287          492,612
    Payment of debt                                                            (1,894,904)        (333,971)        (407,797)
    Debt issue costs                                                               (4,298)          (3,569)         (16,768)
    Proceeds from issuance of common units                                        171,433               68          212,303
    Contributions from General Partner's minority interest                          7,434              146           12,349
    Distributions to partners
      Common units                                                               (194,691)        (135,835)         (93,352)
      General Partner                                                             (91,366)         (52,674)         (27,450)
      Minority interest                                                            (7,533)          (2,316)          (1,614)
    Other, net                                                                        887             (149)            (420)
                                                                              -----------      -----------      -----------
Net Cash Provided by Financing Activities                                         915,266           21,987          169,863
                                                                              -----------      -----------      -----------

Increase in Cash and Cash Equivalents                                              19,267            8,317           22,123
Cash and Cash Equivalents, beginning of period                                     40,052           31,735            9,612
                                                                              -----------      -----------      -----------
Cash and Cash Equivalents, end of period                                      $    59,319      $    40,052      $    31,735
                                                                              ===========      ===========      ===========

Noncash Investing and Financing Activities:
  Contribution of net assets to partnership investments                       $        --      $        20      $    60,387
  Assets acquired by the issuance of units                                        179,623          420,850        1,003,202
  Assets acquired by the assumption of liabilities                                333,301          111,509          569,822
Supplemental disclosures of cash flow information:
   Cash paid during the year for
   Interest (net of capitalized interest)                                          88,821           48,222           47,616
   Income taxes                                                                     1,806              529            1,354
</TABLE>

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

                                      F-5
<PAGE>   83

              KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
                  CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL
                             (Dollars in Thousands)

<TABLE>
<CAPTION>
                                                                                                                           Total
                                                 Common Units                    Class B Units           General          Partners'
                                             Units          Amount            Units        Amount        Partner          Capital
                                           ----------     -----------       ---------    -----------    -----------     -----------

<S>                                        <C>            <C>               <C>          <C>            <C>             <C>
Partners' capital at December 31, 1997     14,111,200     $   146,840              --    $        --    $     3,384     $   150,224

    Net income                                     --          70,159              --             --         33,447         103,606

    Common units issued as consideration
         in the acquisition of assets
         or businesses                     28,669,912       1,001,865              --             --             --       1,001,865

    Common units issued for cash            6,070,578         211,507              --             --             --         211,507

    Capital contributions                          --          10,234              --             --          2,678          12,912

    Distributions                                  --         (91,063)             --             --        (27,437)       (118,500)

    Repurchases                               (30,000)           (951)             --             --             --            (951)
                                           ----------     -----------       ---------    -----------    -----------     -----------
Partners' capital at December 31, 1998     48,821,690       1,348,591              --             --         12,072       1,360,663

    Net income                                     --         126,029              --             --         56,273         182,302

    Common units issued as consideration
         in the acquisition of assets
         or businesses                     10,320,147         420,610              --             --            (15)        420,595

    Common units issued for cash                2,000              68              --             --             --              68

    Distributions                                  --        (135,835)             --             --        (52,674)       (188,509)

    Repurchases                                (6,700)           (321)             --             --             --            (321)
                                           ----------     -----------       ---------    -----------    -----------     -----------
Partners' capital at December 31, 1999     59,137,137       1,759,142              --             --         15,656       1,774,798

    Net income                                     --         168,878              --             --        109,470         278,348

    Common units issued as consideration
         in the acquisition of assets
         or businesses                      1,214,172          53,050       2,656,700        125,961            (11)        179,000

    Common units issued for cash            4,506,800         170,978              --             --             --         170,978

    Distributions                                  --        (194,691)             --             --        (91,366)       (286,057)
                                           ----------     -----------       ---------    -----------    -----------     -----------
Partners' capital at December 31, 2000     64,858,109     $ 1,957,357       2,656,700    $   125,961    $    33,749     $ 2,117,067
                                           ==========     ===========       =========    ===========    ===========     ===========
</TABLE>

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

                                      F-6
<PAGE>   84

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

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 Master
Limited Partnership managing a diversified portfolio of midstream energy assets
consisting of refined petroleum product pipelines, natural gas pipelines, carbon
dioxide pipelines and bulk material terminals that provide fee-based services to
customers. Customers contract with us to provide transportation of refined
petroleum products, natural gas and carbon dioxide through our pipelines and to
transfer materials principally between railway cars and waterborne vessels at
our bulk terminal sites. We trade under the New York Stock Exchange symbol "KMP"
and presently conduct our business through four reportable business segments:

     o    Product Pipelines;

     o    Natural Gas Pipelines;

     o    CO2 Pipelines; and

     o    Bulk Terminals.

     Acquisitions in 2000 required a reevaluation of our previously reported
Pacific Operations, Mid-Continent Operations, Natural Gas Operations and Bulk
Terminals business segments. Our previous Pacific Operations segment, previous
Mid-Continent Operations segment, with the exception of our Mid-Continent's
natural gas liquids separation activities and carbon dioxide pipeline
transportation activities, and our 32.5% interest in the Cochin Pipeline System,
acquired in the fourth quarter of 2000, have been combined to present our
current Product Pipelines segment. Our prior interest in the Mont Belvieu
fractionation facility has been combined with our acquisition of certain assets
from Kinder Morgan, Inc., effective December 31, 1999 and December 31, 2000, to
present our current Natural Gas Pipelines segment. Finally, due to our
acquisition of the remaining 80% of Kinder Morgan CO2 Company, L.P., effective
April 1, 2000, we began reporting the CO2 Pipelines segment. Prior to April 1,
2000, we only owned a 20% equity interest in Shell CO2 Company, Ltd. and
reported its results under the equity method of accounting in the Mid-Continent
Operations. Other than acquisitions made during 2000, there was no change in our
Bulk Terminals business segment. See note 3 for more information on these
acquisitions and note 15 for financial information on these segments.

     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 generating 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
America, operating more than 30,000 miles of natural gas and product pipelines.
KMI also has significant retail distribution, electric generation and terminal
assets. KMI, through its subsidiary Kinder Morgan (Delaware), Inc., remains the
sole stockholder of our general partner. KMI also owns approximately 20.7% of
our outstanding units.

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.

     USE OF ESTIMATES

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



                                      F-7
<PAGE>   85

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

     o    the amounts we report for assets and liabilities;

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

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

     Actual results could differ from those estimates.

     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.

     GAS IMBALANCES

    We value gas imbalances due to or due from shippers and operators at the
appropriate index price. Gas imbalances represent the difference between gas
receipts from and gas deliveries to our transportation and storage customers.
Gas imbalances arise when these customers deliver more or less gas into the
pipeline than they take out. Natural gas imbalances are settled in cash or made
up in-kind subject to the pipelines' various terms.

     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
and oil 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 account for our interests in carbon dioxide and
oil properties under the successful efforts method of accounting. 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.

     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

     We amortize our 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. We amortize this excess for undervalued





                                      F-8
<PAGE>   86

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 report amortization of excess cost over fair value of net assets
(goodwill) as amortization expense in our accompanying consolidated statement of
income. For our investments accounted for under the equity method, we report
amortization of excess cost on investments as amortization of excess cost of
equity investments in our accompanying consolidated statement of income. Our
total unamortized excess cost over fair value of net assets on investments in
consolidated affiliates was approximately $158.1 million as of December 31, 2000
and $48.6 million as of December 31, 1999. These amounts are included within
intangibles on our accompanying consolidated balance sheet. Our total
unamortized excess cost over underlying book value of net assets on investments
accounted for under the equity method was approximately $350.2 million as of
December 31, 2000 and $273.5 million as of December 31, 1999. 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 this time, we believe no such impairment has occurred and no
reduction in estimated useful lives is warranted.

     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 transmix processing revenues based on volumes processed or sold, and
if applicable, title has passed. We recognize energy-related product sales
revenues based on delivered quantities of product.

     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:

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

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

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

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

     o    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 or 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




                                      F-9
<PAGE>   87
              KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

     Due to the absence of items of other comprehensive income, our
comprehensive income equaled our net income in each of the periods presented.

     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.

      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. 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 for us on January 1, 2001. See note 14
for more information on our risk management activities.

3.  ACQUISITIONS AND JOINT VENTURES

     During 1998, 1999 and 2000, 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.

     PRODUCT PIPELINES

     Santa Fe

     On March 6, 1998, we acquired 99.5% of SFPP, L.P., the operating
partnership of Santa Fe Pacific Pipeline Partners, L.P. SFPP owns our Pacific
operations. The transaction was valued at more than $1.5 billion inclusive of
liabilities assumed. We acquired the interest of Santa Fe Pacific Pipeline's
common unitholders in SFPP in exchange for approximately 26.5 million units
(1.39 of our units for each Santa Fe Pacific Pipeline common unit). In addition,
we paid $84.4 million to Santa Fe Pacific Pipelines, Inc. in exchange for the
general partner interest in Santa Fe Pacific Pipeline Partners, L.P. Also on
March 6, 1998, SFPP redeemed from Santa Fe Pacific Pipelines, Inc. a 0.5%
interest in SFPP for $5.8 million. The redemption was paid from SFPP's cash
reserves. After the redemption, Santa Fe Pacific Pipelines, Inc. continues to
own a 0.5% special limited partner interest in SFPP. Assets acquired in this
transaction comprise our Pacific operations, which include over 3,300 miles of
pipeline and thirteen owned and operated terminals.

     Our purchase price and the allocation to assets acquired and liabilities
assumed was as follows:

<TABLE>
<S>                                                         <C>
Purchase price:
  Common units issued                                       $  941,865
  Cash paid, including transaction costs                        93,798
  Liabilities assumed                                          518,685
                                                            ----------
  Total purchase price                                      $1,554,348
                                                            ==========

Allocation of purchase price:
  Current assets                                            $   54,234
  Property, plant and equipment                              1,490,453
  Deferred charges and other assets                              9,661
                                                            ----------
                                                            $1,554,348
                                                            ==========
</TABLE>

     Plantation Pipe Line Company

     On September 15, 1998, we acquired an approximate 24% interest in
Plantation Pipe Line Company for $110 million. On June 16, 1999, we acquired an
additional approximate 27% interest in Plantation Pipe Line Company for $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.

     Our purchase price and the allocation to assets acquired and liabilities
assumed was as follows:

<TABLE>
<S>                                                          <C>
Purchase price:
  Cash paid, including transaction costs                     $234,163
                                                             --------
  Total purchase price                                       $234,163
                                                             ========

Allocation of purchase price:
  Equity investments                                         $234,163
                                                             --------
                                                             $234,163
                                                             ========
</TABLE>


                                      F-10
<PAGE>   88
              KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Company, and therefore, we account for our investment in Plantation under the
equity method of accounting.

     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
$16.0 million and 510,147 units valued at approximately $14.3 million.

     Our purchase price and the allocation to assets acquired and liabilities
assumed was as follows:

<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>

     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.

     Our purchase price and the allocation to assets acquired and liabilities
assumed was as follows:

<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>

     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. 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:

<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>

     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. We record our proportional share of joint venture revenues and expenses
and cost of joint venture assets as part of our Product Pipelines business
segment.

     Our purchase price and the allocation to assets acquired and liabilities
assumed was as follows:

<TABLE>
<S>                                          <C>
Purchase price:
     Cash paid, including transaction costs      $120,523
                                                 --------
     Total purchase price                        $120,523
                                                 ========
Allocation of purchase price:
     Property, plant and equipment               $120,523
                                                 --------
                                                 $120,523
                                                 ========
</TABLE>

     NATURAL GAS PIPELINES

     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 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 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
under the equity method of accounting. Effective December 31, 1999, following
our acquisition of an additional 33 1/3% interest in Trailblazer, which is
discussed below, we included Trailblazer's activities as part of our
consolidated financial statements.

     Kinder Morgan, Inc. Asset Contributions

     Effective December 31, 1999, we acquired over $700 million of assets from
KMI. As consideration for the assets, we paid to KMI $330 million and 9.81
million common units, valued at $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 and a 49% equity interest
in Red Cedar Gathering Company. The acquired interest in Trailblazer, when
combined with the interest purchased on November 30, 1999, gave us a 66 2/3%
ownership interest.

     Our purchase price and the allocation to assets acquired and liabilities
assumed was as follows:

<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>



     Effective December 31, 2000, we acquired over $300 million of assets from
KMI. As consideration for these assets, we paid to KMI $192.7 million and $155.7
million in units, consisting of 640,000 common units and 2,656,700 Class B
units. We also assumed liabilities of approximately $273.3 million. We acquired
Kinder Morgan Texas Pipeline, Inc. 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.

     Our purchase price and the allocation to assets acquired and liabilities
assumed was as follows:

<TABLE>
<S>                                          <C>

Purchase price:
     Common and Class B units issued             $155,692
     Cash paid, including transaction costs       192,677
     Liabilities assumed                          273,331
                                                 --------
     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>




                                      F-11
<PAGE>   89
              KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     CO2 PIPELINES

     Kinder Morgan CO2 Company, L.P.

     On March 5, 1998, we and affiliates of Shell Oil Company agreed to combine
our carbon dioxide activities and assets into a partnership, Shell CO(2)
Company, Ltd., to be operated by a Shell affiliate. We acquired a 20% interest
in Shell CO2 Company, Ltd. in exchange for contributing our Central Basin
Pipeline and approximately $25 million in cash.

     Effective April 1, 2000, we acquired the remaining 78% limited partner
interest and the 2% general partner interest in Shell CO2 Company, Ltd. from
Shell for $212.1 million. We renamed the limited partnership Kinder Morgan CO2
Company, L.P., and going forward from April 1, 2000, we have included its
results as part of our consolidated financial statements under our CO2
Pipelines business segment. As is the case with all of our operating
partnerships, we own a 98.9899% limited partner ownership interest in KMCO2
and our general partner owns a direct 1.0101% general partner ownership
interest.

Our purchase price and the allocation to assets acquired and liabilities
assumed was as follows:

<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
     CO2 Company, L.P. of ($86,672) and our allocation of purchase price to the
     equity investment purchased in our acquisition of Shell CO2 Company, L.P.
     of $6,979.

     Other Acquisitions and Joint Ventures

     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 CO2 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:

<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>

     On December 28, 2000, we announced that KMCO2 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 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 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 KMCO2 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 will account for this investment under the equity method.

     BULK TERMINALS

     Hall-Buck Marine, Inc.

     Effective July 1, 1998, we acquired Hall-Buck Marine, Inc. for
approximately $98.7 million, consisting of approximately 2.1 million units and
assumed liabilities. Hall-Buck, headquartered in Sorrento, Louisiana, is
one of the nation's largest independent operators of dry bulk terminals. In
addition, Hall-Buck owns all of the common stock of River Consulting
Incorporated, a nationally recognized leader in the design and construction of
bulk material facilities and port related structures. After the acquisition, we
changed the name of Hall-Buck Marine, Inc. to Kinder Morgan Bulk Terminals,
Inc.

Our purchase price and the allocation to assets acquired and liabilities
assumed was as follows:

<TABLE>
<S>                                                     <C>
     Purchase price:
         Common units issued                            $   60,000
         Cash paid, including transaction costs                170
         Liabilities assumed                                37,916
                                                        ----------
         Total purchase price                           $   98,086
                                                        ==========
     Allocation of purchase price:
         Current assets                                 $   14,082
         Property, plant and equipment                      30,738
         Goodwill                                           50,962
         Deferred charges and other assets                   2,304
                                                        ----------
                                                        $   98,086
                                                        ==========
</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 $24.1 million, including 574,172
units and approximately $0.8 million in cash. The Milwaukee terminal, 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 salt and grain products.

Our purchase price and the allocation to assets acquired and liabilities
assumed was as follows:

<TABLE>
<S>                                                     <C>
     Purchase price:
         Common units issued                            $   23,319
         Cash paid, including transaction costs                757
         Liabilities assumed                                 3,140
                                                        ----------
         Total purchase price                           $   27,216
                                                        ==========
     Allocation of purchase price:
         Current assets                                 $    1,764
         Property, plant and equipment                      15,201
         Goodwill                                           10,251
                                                        ----------
                                                        $   27,216
                                                        ==========
</TABLE>


                                      F-12
<PAGE>   90

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

     Delta Terminal Services, Inc.

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

     Our purchase price and the allocation to assets acquired and liabilities
assumed was as follows:

<TABLE>
<S>                                                                          <C>
Purchase price:
  Cash paid, including transaction costs                                     $  114,112
  Liabilities assumed                                                             7,647
                                                                             ----------
  Total purchase price                                                       $  121,759
                                                                             ==========
Allocation of purchase price:
  Current assets                                                             $    1,137
  Property, plant and equipment                                                  70,189
  Goodwill                                                                       50,396
  Deferred charges and other assets                                                  37
                                                                             ----------
                                                                             $  121,759
                                                                             ==========
</TABLE>

     PRO FORMA INFORMATION

     The following summarized unaudited Pro Forma Consolidated Income Statement
information for the twelve months ended December 31, 2000 and 1999, assumes the
2000 and 1999 acquisitions and joint ventures had occurred as of January 1,
1999. 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
2000 and 1999 acquisitions and joint ventures as of January 1, 1999 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
                                                                                 Twelve Months Ended
                                                                                     December 31,
                                                                                 2000             1999
                                                                             -------------    -------------
Income Statement                                                                       (Unaudited)
<S>                                                                          <C>              <C>
Revenues                                                                     $   2,954,180    $   1,806,453
Operating Income                                                                   393,982          350,075
Net Income before extraordinary charge                                             334,817          290,134
Net Income                                                                         334,817          287,539
Basic Limited Partners' Net Income per unit before extraordinary charge      $        2.82    $        2.63
Basic Limited Partners' Net Income per unit                                  $        2.82    $        2.59
Diluted Limited Partners' Net Income per unit before extraordinary charge    $        2.81    $        2.63
Diluted Limited Partners' Net Income per unit                                $        2.81    $        2.59
</TABLE>

     Acquisitions Subsequent to December 31, 2000

     On November 30, 2000, we announced that we had signed a definitive
agreement with GATX Corporation to purchase its United States' pipeline and
terminal businesses for approximately $1.15 billion, consisting of cash, assumed
debt and other obligations. Primary assets included in the transaction are the
CALNEV Pipe Line Company, the Central Florida Pipeline Company and twelve
terminals that store refined petroleum products and chemicals. The transaction
closed March 1, 2001, except for CALNEV, which closed on March 30, 2001.

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 Product Pipelines business
segment, and a charge of $0.4 million relating to prior years' over-billed
storage tank lease fees, also within our Product 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):



                                      F-13
<PAGE>   91
              KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
                               Year Ended December 31,
                             2000        1999        1998
                            -------     -------     -------

<S>                         <C>         <C>         <C>
Taxes currently payable:
   Federal                  $10,612     $ 8,169     $ 1,432
   State                      1,416       1,002         168
                            -------     -------     -------
   Total                     12,028       9,171       1,600

Taxes deferred:
   Federal                    1,627         583         (25)
   State                        279          72          (3)
                            -------     -------     -------
   Total                      1,906         655         (28)
                            -------     -------     -------
Total tax provision         $13,934     $ 9,826     $ 1,572
                            =======     =======     =======

Effective tax rate              4.8%        5.0%        1.3%
</TABLE>

     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,
                                                                   2000      1999      1998
                                                                   ----      ----      ----

<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)%   (35.3)%   (35.4)%
   Corporate subsidiary earnings subject to tax                     0.6%      1.0%      0.8%
   Income tax expense attributable to corporate equity earnings     4.1%      4.4%      1.6%
   Gain on distribution of appreciated property from
      corporate subsidiary                                           --        --       3.7%
   Utilization of net operating loss                                 --        --      (1.0)%
   Utilization of alternative minimum tax credits                    --        --      (1.5)%
   Prior year adjustments                                            --        --      (2.0)%
   State taxes                                                      0.1%      0.1%      0.5%
   Other                                                             --      (0.2)%    (0.4)%
                                                                   ----      ----      ----
Effective Tax Rate                                                  4.8%      5.0%      1.3%
                                                                   ====      ====      ====
</TABLE>


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

<TABLE>
<CAPTION>
                                        December 31,
                                       2000      1999
                                      ------    ------

<S>                                   <C>       <C>
Deferred tax assets:
   State taxes                        $  184    $   --
   Book accruals                         176     1,110
   Alternative minimum tax credits     1,376     1,376
                                      ------    ------
Total deferred tax assets              1,736     2,486

Deferred tax liabilities:
   Property, plant and equipment       4,223     3,323
   Book accruals                          --       661
   Other                                  --         2
                                      ------    ------
Total deferred tax liabilities         4,223     3,986
                                      ------    ------
Net deferred tax liabilities          $2,487    $1,500
                                      ======    ======
</TABLE>


                                      F-14
<PAGE>   92
              KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     We had available, at December 31, 2000, approximately $1.4 million of
alternative minimum tax credit carryforwards, which are available indefinitely.

6.  PROPERTY, PLANT AND EQUIPMENT

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

<TABLE>
<CAPTION>
                                                                                   December 31,
                                                                             ---------------------------
                                                                                2000           1999
                                                                             -----------    -----------
<S>                                                                          <C>            <C>
           Natural Gas, liquids and carbon dioxide pipelines                 $ 1,732,607    $ 1,729,034
           Natural Gas, liquids and carbon dioxide pipeline station equip.     1,072,185        550,044
           Coal and bulk tonnage transfer, storage and services                  191,313        107,052
           Natural Gas and transmix processing                                    95,624         45,232
           Land                                                                   79,653         72,259
           Land right-of-way                                                     116,456         93,909
           Construction work in process                                           90,067         38,653
           Other                                                                 117,981         59,939
                                                                             -----------    -----------
           Total cost                                                          3,495,886      2,696,122
           Accumulated depreciation and depletion                               (189,581)      (117,809)
                                                                             -----------    -----------
                                                                             $ 3,306,305    $ 2,578,313
                                                                             ===========    ===========
</TABLE>

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

<TABLE>
<CAPTION>
                                                           2000              1999         1998
                                                         ---------         --------     --------
<S>                                                      <C>               <C>          <C>
           Depreciation and depletion expense            $ 79,740          $ 44,553     $ 35,288
</TABLE>

7.  INVESTMENTS

     Our significant equity investments at December 31, 2000 consisted of:

     o    Plantation Pipe Line Company (51%);

     o    Red Cedar Gathering Company (49%);

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

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

     o    Cortez Pipeline Company (50%); and

     o    Heartland Pipeline Company (50%).

     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
CO2 Company, Ltd. and renamed the entity Kinder Morgan CO2 Company, L.P.
(KMCO2). 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 effective December 31, 1999.

     We acquired our investment in Cortez as part of our KMCO2 acquisition and
we acquired our investments in Coyote Gas Treating and Thunder Creek from KMI on
December 31, 2000.

     Please refer to notes 3 and 4 for more information.




                                      F-15
<PAGE>   93
              KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

<TABLE>
<CAPTION>

                                                               December 31,
                                                             2000         1999
                                                          ----------   ----------

<S>                                                       <C>          <C>
Plantation Pipe Line Company                              $  223,627   $  229,349
Red Cedar Gathering Company                                   96,388       88,249
Thunder Creek Gas Services, LLC                               27,625           --
Coyote Gas Treating, LLC                                      17,000           --
Cortez Pipeline Company                                        9,559           --
Heartland Pipeline Company                                     6,025        4,818
Shell CO2 Company, Ltd.                                           --       86,675
Colton Transmix Processing Facility                               --        5,263
All Others                                                     2,658        4,297
                                                          ----------   ----------
Total Equity Investments                                  $  382,882   $  418,651
Investment in oil and gas assets to be contributed
   to joint venture                                           34,163           --
                                                          ----------   ----------
Total Investments                                         $  417,045   $  418,651
                                                          ==========   ==========
</TABLE>

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

<TABLE>
<CAPTION>

                                                   Year ended December 31,
                                              2000          1999          1998
                                           ----------    ----------    ----------

<S>                                        <C>           <C>           <C>
Plantation Pipe Line Company               $   31,509    $   22,510    $    4,421
Cortez Pipeline Company                        17,219            --            --
Red Cedar Gathering Company                    16,110            --            --
Shell CO2 Company, Ltd.                         3,625        14,500        14,500
Colton Transmix Processing Facility             1,815         1,531           803
Heartland Pipeline Company                      1,581         1,571         1,394
Coyote Gas Treating, LLC                           --            --            --
Thunder Creek Gas Services, LLC                    --            --            --
Mont Belvieu Associates                            --         2,500         4,577
Trailblazer Pipeline Company                      (24)          284            --
All Others                                       (232)           22            37
                                           ----------    ----------    ----------
Total                                      $   71,603    $   42,918    $   25,732
                                           ==========    ==========    ==========
Amortization of excess costs               $   (8,195)   $   (4,254)   $     (764)
                                           ==========    ==========    ==========
</TABLE>


                                      F-16
<PAGE>   94

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

     Summarized combined unaudited financial information for our significant
equity investments is reported below (in thousands):

<TABLE>
<CAPTION>
                                                    Year ended December 31,
Income Statement                              2000            1999            1998
                                          -----------     ----------     -----------
<S>                                       <C>             <C>            <C>
Revenues                                  $   399,335     $  344,017     $   236,534
Costs and expenses                            276,000        244,515         148,616
Earnings before extraordinary items           123,335         99,502          87,918
Net income                                    123,335         99,502          87,918
</TABLE>

<TABLE>
<CAPTION>
                                                  December 31,
Balance Sheet                                 2000            1999
                                          -----------     -----------
<S>                                       <C>             <C>
Current assets                            $   117,050     $   137,828
Non-current assets                            665,435         450,791
Current liabilities                            92,027          64,333
Non-current liabilities                       576,278         289,671
Partners'/Owners' equity                      114,180         234,615
</TABLE>

     On December 28, 2000, we announced that KMCO2 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 KMCO2 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 will account for this investment under the equity method.

8.  INTANGIBLES

     Our intangible assets include value associated with acquired:

     o    goodwill;

     o    contracts and agreements; and

     o    intangible lease value associated with our acquisition of Kinder
          Morgan Texas Pipeline, L.P. on December 31, 2000.

      All of our intangible assets are amortized on a straight-line basis over
their estimated useful lives. Goodwill is being amortized over a period of 40
years. Beginning in 2001, the intangible lease value will be amortized over 26
years, the remaining life of an operating lease covering the use of KMTP's
natural gas pipeline.




                                      F-17
<PAGE>   95

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

     Intangible assets consisted of the following (in thousands):

<TABLE>
<CAPTION>
                                 December 31,
                              2000          1999
                            ---------     ---------

<S>                         <C>           <C>
Goodwill                    $ 162,271     $  50,546
Accumulated amortization       (4,201)       (1,941)
                            ---------     ---------
Goodwill, net               $ 158,070     $  48,605

Lease value                 $ 185,982     $   6,592
Contracts and agreements        1,768         1,768
Other                              93            93
                            ---------     ---------
Accumulated amortization         (608)         (428)
                            ---------     ---------
Other intangibles, net      $ 187,235     $   8,025
                            ---------     ---------
Total intangibles, net      $ 345,305     $  56,630
                            =========     =========
</TABLE>

9.   DEBT

     Our debt facilities as of December 31, 2000, consist primarily of:

     o    a $600 million unsecured 364-day credit facility due October 25, 2001;

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

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

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

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

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

     o    $119 million of Series F First Mortgage Notes (our subsidiary, SFPP,
          is the obligor on the notes);

     o    $20.2 million of Senior Secured Notes (our subsidiary, Trailblazer, is
          the obligor on the notes);

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

     o    a $600 million short-term commercial paper program.

     Our short-term debt at December 31, 2000, consisted of:

     o    $582 million of borrowings under our unsecured 364-day credit facility
          due October 25, 2001;

     o    $52 million of commercial paper borrowings;

     o    $35 million under the SFPP 10.7% First Mortgage Notes; and

     o    $14.6 million in other borrowings.

     During 2000, our cash acquisitions and expansions exceeded $600 million.
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 2001 through a
combination of long-term debt and equity. Based on prior successful short-term
debt refinancings and current market conditions, we do not anticipate any
liquidity problems.

     Credit Facilities

     In February 1998, we refinanced our first mortgage notes and existing bank
credit facilities with a $325 million secured revolving credit facility expiring
in February 2005. On December 1, 1998, the credit facility was amended to
release the collateral and the credit facility became unsecured. Borrowings
under the credit facility were primarily used to fund our investment in
Plantation Pipe Line Company in June 1999. On September 29, 1999, the $325
million credit facility was replaced with a $300 million unsecured five-year
credit facility expiring in


                                      F-18
<PAGE>   96
              KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 the $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. The
terms of the new credit facility are substantially similar to the terms of the
previous facility. The two credit facilities are with a syndicate of financial
institutions. First Union National Bank is the administrative agent under the
agreements.

     The outstanding balance under our five-year credit facility was $197.6
million at December 31, 1999. On August 11, 2000, we refinanced the outstanding
balance under SFPP'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 364-day credit facility at
December 31, 1999. The outstanding balance under our 364-day credit facility was
$582 million at December 31, 2000.

     Interest on our credit facilities accrues at our option at a floating rate
equal to either:

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

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

     The five-year credit facility also permits us to obtain bids for fixed rate
loans from members of the lending syndicate. At December 31, 2000, the interest
rate on our credit facilities was 7.115% per annum. The weighted average
interest rate on our borrowings under our credit facilities was 6.8987% during
2000 and 6.1313% during 1999.

     Senior Notes

     On January 29, 1999, we closed a public offering of $250 million in
principal amount of 6.30% senior notes due February 1, 2009 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
the proceeds to pay the outstanding balance on our credit facility and for
working capital and other partnership purposes. In connection with the
refinancing of our credit facility on September 29, 1999, our subsidiaries were
released from their guarantees of the credit facility. As a result, the
subsidiary guarantees under these senior notes were also automatically released
in accordance with the terms of the notes. At December 31, 2000, the unamortized
liability balance on the 6.30% senior notes was $249.3 million.

     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 the issuance of these notes were used to reduce our
outstanding commercial paper. At December 31, 2000, the unamortized liability
balance on the 8.0% notes was $199.7 million and the unamortized liability
balance on the floating rate notes was $200 million. At December 31, 2000, the
interest rate on our floating rate notes was 7.0%.

     On November 8, 2000, we closed a private placement of $250 million of 7.5%
notes due November 1, 2010. We agreed to offer to exchange these notes with
substantially identical notes that are registered under the Securities Act of
1933 within 210 days of the close of this transaction. The proceeds from this
offering, net of underwriting discounts, were $246.8 million. These proceeds
were used to reduce our outstanding commercial paper. At December 31, 2000, the
unamortized liability balance on the 7.5% notes was $248.4 million.

     In addition, as of December 31, 1999, we financed $330 million through KMI
to fund part of the acquisition of assets acquired from KMI on December 31,
1999. In accordance with the Closing Agreement entered into as of January 20,
2000, we paid KMI a per diem fee of $180.56 for each $1,000,000 financed. We
paid KMI $200 million on January 21, 2000, and the remaining $130 million on
March 23, 2000 with a portion of the proceeds from our issuance of notes on
March 22, 2000.



                                      F-19
<PAGE>   97
              KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     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. As of December 31, 1999, we had not issued any
commercial paper. 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. Borrowings under our
commercial paper program reduce the borrowings allowed under our 364-day and
five-year credit facilities combined. As of December 31, 2000, we had $52
million of commercial paper outstanding with an interest rate of 7.02%.

     SFPP Debt

     At December 31, 2000, the outstanding balance under SFPP's Series F notes
was $119.0 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. The Series F notes are payable in annual installments of $39.5 million
in 2001, $42.5 million in 2002 and $37.0 million in 2003. The Series F notes may
also be prepaid in full or in part at a price equal to par plus, in certain
circumstances, a premium. The Series F notes are secured by mortgages on
substantially all of the properties of SFPP (the "Mortgaged Property"). The
Series F notes contain certain covenants limiting the amount of additional debt
or equity that may be issued and limiting the amount of cash distributions,
investments, and property dispositions.

     At December 31, 1999, the outstanding balance under SFPP's bank facility
was $174.0 million. On August 11, 2000, we refinanced the outstanding balance
under SFPP's secured credit facility with a $175.0 million borrowing under our
five-year credit facility. Upon refinancing, SFPP executed a $175 million
intercompany note in favor of Kinder Morgan Energy Partners, L.P. The weighted
average interest rate on the SFPP bank facility was 5.477% for 1999 and 6.4797%
in 2000.

     Trailblazer Debt

     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. Trailblazer provided security for the notes principally by an
assignment of certain Trailblazer transportation contracts. Effective April 29,
1997, Trailblazer amended the Note Purchase Agreement. This amendment allowed
Trailblazer to include several additional transportation contracts as security
for the notes, added a limitation on the amount of additional money that
Trailblazer could borrow and relieved Trailblazer from its security deposit
obligation. At December 31, 2000, Trailblazer's outstanding balance under the
Senior Secured Notes was $20.2 million. The Senior Secured Notes have a fixed
annual interest rate of 8.03% and will be repaid in semiannual installments of
$5.05 million from March 1, 2001 through September 1, 2002, the final maturity
date. Interest is payable semiannually in March and September. Pursuant to the
terms of this Note Purchase Agreement, Trailblazer partnership distributions are
restricted by certain financial covenants. Currently, Trailblazer's proposed
expansion project is pending before the FERC. If the expansion is approved,
which is expected in the first quarter of 2001, we plan to refinance these
notes.

     In December 1999, Trailblazer entered into a 364-day revolving credit
agreement with Toronto Dominion, Inc. providing for loans up to $10 million. At
December 26, 2000, the outstanding balance due under Trailblazer's bank facility
was $10 million. Trailblazer paid the outstanding balance under its credit
facility with a $10 million borrowing under an intercompany account payable in
favor of KMI on December 27, 2000.

     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 agreement expires December 27, 2001. At January 31, 2001, the
outstanding balance under Trailblazer's revolving credit agreement was $10
million. The borrowings were used to pay the account payable to KMI. The
agreement provides for an interest rate of LIBOR plus 0.875%. At January 31,
2001, the interest rate on the credit facility debt was 6.625%. Pursuant to the
terms of the revolving credit agreement, Trailblazer partnership distributions
are restricted by certain financial covenants.


                                      F-20
<PAGE>   98

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

     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 2000, the weighted-average interest
rate on these bonds was 4.47% per annum, and at December 31, 2000 the interest
rate was 5.00%. 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 KMCO2, we severally
guarantee 50% of the debt of Cortez Capital Corporation. Shell Oil Company
shares our guaranty obligations jointly and severally through December 31, 2006
for Cortez's debt programs in place as of April 1, 2000.

     At December 31, 2000, the debt facilities of Cortez Capital Corporation
consisted of:

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

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

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

     o    $151.7 million of Series D notes.

MATURITIES OF DEBT

     The scheduled maturities of our outstanding debt at December 31, 2000, are
summarized as follows (in thousands):

<TABLE>
<S>                                          <C>
                       2001                  $    683,649
                       2002                       253,116
                       2003                        37,016
                       2004                       207,617
                       2005                       199,670
                       Thereafter                 523,334
                                             ------------
                       Total                 $  1,904,402
                                             ============
</TABLE>

    Of the $683.6 million scheduled to mature in 2001, we intend and have the
ability to refinance $34.7 million on a long-term basis under our existing
credit facilities.

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, 2000 and December 31, 1999 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, 2000                      December 31, 1999
                        ---------------------------------     ----------------------------------
                          Carrying           Estimated           Carrying           Estimated
                            Value           Fair Value            Value            Fair Value
                        --------------     --------------     ---------------     --------------
                                                    (in thousands)
<S>                     <C>                <C>                <C>                 <C>
          Total Debt    $    1,904,402     $    2,011,818     $     1,198,301     $    1,209,625

</TABLE>



                                      F-21
<PAGE>   99
              KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

10.  PENSIONS AND OTHER POSTRETIREMENT BENEFITS

     In connection with the acquisition of SFPP and Kinder Morgan Bulk Terminals
in 1998, we acquired certain liabilities for pension and postretirement
benefits. We have a noncontributory defined benefit pension plan covering the
former employees of Kinder Morgan Bulk Terminals. The benefits under this plan
were based primarily upon years of service and final average pensionable
earnings. We provide medical and life insurance benefits to current employees,
their covered dependents and beneficiaries of SFPP and Kinder Morgan Bulk
Terminals. We also provide the same benefits to former salaried employees of
SFPP. Additionally, we will continue to fund these costs for those employees
currently in the plan during their retirement years.

    SFPP's postretirement benefit plan is frozen and no additional participants
may join the plan. Similarly, benefit accruals were frozen as of December 31,
1998 for the Hall-Buck plan. As a result of these events, we recognized a
curtailment gain related to the SFPP's plan of $3.9 million in 1999 and a gain
related to Hall-Buck's plan of $0.4 million in 1998.

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

<TABLE>
<CAPTION>
                                                   2000                        1999                          1998
                                        --------------------------     --------------------------     --------------------------
                                                        Other                          Other                          Other
                                         Pension    Postretirement     Pension     Postretirement     Pension     Postretirement
                                         Benefits      Benefits        Benefits       Benefits        Benefits       Benefits
                                        -------     --------------     -------     --------------     -------     --------------
<S>                                     <C>         <C>                <C>         <C>                <C>         <C>
Net periodic benefit cost

Service cost                            $    --     $           46     $    --     $           80     $    98     $          636
Interest cost                               145                755         141                696          76                983
Expected return on plan assets             (171)                --        (150)                --         (70)                --
Amortization of transition obligation         1                 --          --                 --          --                 --
Amortization of prior service cost           --               (493)         --               (493)         --               (493)
Actuarial loss (gain)                        --               (290)         --               (340)         --               (208)
                                        -------     --------------     -------     --------------     -------     --------------

Net periodic benefit cost               $   (25)    $           18     $    (9)    $          (57)    $   104     $          918
                                        =======     ==============     =======     ==============     =======     ==============

Additional amounts recognized
Curtailment (gain) loss                 $    --     $           --     $    --     $       (3,859)    $  (425)    $           --

Weighted-average assumptions as of
December 31:
Discount rate                               7.5%              7.75%        7.0%               7.0%        7.0%               7.5%
Expected return on plan assets              8.5%                --         8.5%                --         8.5%                --
Rate of compensation increase                --                 --          --                 --         4.0%               4.0%
</TABLE>


                                      F-22
<PAGE>   100
             KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

<TABLE>
<CAPTION>
                                               2000                          1999
                                       ---------------------------    ---------------------------
                                                       Other                          Other
                                       Pension     Postretirement     Pension     Postretirement
                                       Benefits       Benefits        Benefits        Benefits
                                       --------    ---------------    --------    ---------------
<S>                                   <C>          <C>                <C>        <C>
Change in benefit obligation

Benefit obligation at Jan. 1           $  1,737    $         9,564    $  1,862    $        14,734
Service cost                                 --                 46          --                 80
Interest cost                               145                755         141                696
Amendments                                   --               (371)         --                 --
Administrative expenses                      (9)                --         (12)                --
Actuarial (gain) loss                       299              1,339          86             (1,521)
Curtailment (gain)                           --                 --          --             (3,859)
Benefits paid from plan assets             (189)              (435)       (340)              (566)
                                       --------    ---------------    --------    ---------------

Benefit obligation at Dec. 31          $  1,983    $        10,898    $  1,737    $         9,564
                                       ========    ===============    ========    ===============

Change in plan assets

Fair value of plan assets at Jan. 1    $  2,060    $            --    $  1,833    $            --
Actual return on plan assets               (138)                --         300                 --
Employer contributions                       92                435         279                566
Administrative expenses                      (9)                --         (12)                --
Benefits paid from plan assets             (189)              (435)       (340)              (566)
                                       --------    ---------------    --------    ---------------
Fair value of plan assets at Dec. 31   $  1,816    $            --    $  2,060    $            --
                                       ========    ===============    ========    ===============

Funded status                          $   (167)   $       (10,898)   $    323    $        (9,564)
Unrecognized net transition
     obligation                               1                 --           2                 --
Unrecognized net actuarial
     (gain) loss                            359             (1,383)       (250)            (3,012)
Unrecognized prior service (benefit)         --             (1,656)         --             (1,777)
                                       --------    ---------------    --------    ---------------
Prepaid (accrued) benefit cost         $    193    $       (13,937)   $     75    $       (14,353)
                                       ========    ===============    ========    ===============
</TABLE>


     In 2001, SFPP modified benefits associated with its postretirement benefit
plan. This plan amendment resulted in a $0.4 million decrease in its benefit
obligation for 2000. 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, an 8% annual rate of increase in the per
capita cost of covered health care benefits was assumed for 2000. The rate was
assumed to decrease gradually to 5% by 2005 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:

                                      F-23
<PAGE>   101
             KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
                                                       1-Percentage Point        1-Percentage Point
                                                            Increase                  Decrease
                                                      -------------------        -------------------
<S>                                                   <C>                        <C>
Effect on total of service and interest cost
     components                                       $            61            $           (52)

Effect on postretirement benefit obligation           $           773            $          (665)
</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
contributed $0.6 million during each of the years 2000 and 1999. 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 $0.5 million for each of the years 2000 and 1999. The
amount charged from the period of acquisition through December 31, 1998 was $0.5
million.

     We terminated the Employee Stock Ownership Plan held by Kinder Morgan Bulk
Terminals for the benefit of its employees on August 13, 1998. All ESOP
participants became fully vested retroactive to July 1, 1998, the effective date
of our acquisition of Kinder Morgan Bulk Terminals. We distributed the assets
remaining in the plan during 1999.

     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, that permits all
full-time employees of our general partner to contribute 1% to 15% of base
compensation, on a pre-tax basis, into participant accounts. This plan was
subsequently amended and merged to form the Kinder Morgan Savings Plan. In
addition to a mandatory contribution equal to 4% of base compensation per year
for each plan participant, our general partner may make discretionary
contributions in years when specific performance objectives are met. 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 2001, an additional 2% discretionary contribution was made to
individual accounts based on 2000 financial targets to unitholders. The total
amount charged to expense for our Retirement Savings Plan was $1.8 million
during 2000. 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. 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.


                                      F-24
<PAGE>   102
             KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

11.  PARTNERS' CAPITAL

     In connection with KMI's transfer to us of Natural Gas Pipelines assets
effective December 31, 2000, we paid to KMI cash consideration and issued to KMI
640,000 common units and 2,656,700 Class B units representing limited
partnership interests in us. These units will not participate in our
distribution declared for the fourth quarter of 2000. Our Class B units are
similar to our common units except our Class B units are not eligible for
trading on the New York Stock Exchange. Our Class B unitholders (KMI) have the
same rights as our common unitholders with respect to, without limitation,
distributions from us, voting rights and allocations of income, gain, loss or
deductions. The Class B units are convertible into common units after such time
as the New York Stock Exchange has advised us that common units issuable upon
such conversion are eligible for listing on the NYSE. At any time after December
21, 2001, the holders of a majority of our Class B units may notify us of their
desire to convert their Class B units into our common units.

      At December 31, 2000, Partners' capital consisted of 64,858,109 common
units and 2,656,700 Class B units. Together, these 67,514,809 units represent
the limited partners' interest and an effective 98% economic interest in the
Partnership, exclusive of our general partner's incentive distribution. The
common unit total consisted of 53,546,109 units held by third parties,
10,450,000 units held by KMI and 862,000 units held by our general partner. The
Class B units were held entirely by KMI. At December 31, 1999 and 1998 there
were 59,137,137 and 48,821,690 common units outstanding, respectively. The
general partner has an effective 2% interest in the Partnership, excluding the
general partner's incentive distribution.

     During 1998, we issued 26,548,879 on March 6, 1998 for the acquisition of
SFPP and 2,121,033 units on August 13, 1998 for the acquisition of Hall-Buck.
Additionally, we issued 6,070,578 units in a primary public offering on June 12,
1998 and we repurchased 30,000 units in December 1998.

     During 1999, we issued 510,147 units on September 10, 1999 for the
acquisition of assets from Primary Corporation and 9,810,000 units on December
31, 1999 related to the acquisition of assets from KMI. Additionally, in 1999,
we issued 2,000 units in accordance with unit option exercises, and we
repurchased 6,000 units in January 1999 and 700 units in December 1999.

     During 2000, we issued 574,172 units on February 2, 2000 for the
acquisition of Milwaukee Bulk Terminals, Inc. and Dakota Bulk Terminal, Inc. On
April 4, 2000, we issued 4,500,000 units in a public offering at an issuance
price of $39.75 per unit, less commissions and underwriting expenses. We used
the proceeds from the April 2000 unit issuance to acquire the remaining
ownership interest in Kinder Morgan CO2 Company, L.P. On December 21, 2000, we
issued 3,296,700 units to KMI as partial consideration for acquired assets (see
note 3). Additionally, in 2000, we issued 6,800 common units in accordance with
common unit option exercises.

     For purposes of maintaining partner capital accounts, our partnership
agreement specifies that items of income and loss shall be allocated among the
partners in accordance with their percentage interests. Normal allocations
according to percentage interests are made, however, only after giving effect to
any priority income allocations in an amount equal to the incentive
distributions that are allocated 100% to our general partner.

     Incentive distributions allocated to our general partner are determined by
the amount quarterly distributions to unitholders exceed certain specified
target levels. For the years ended December 31, 2000, 1999 and 1998, we
distributed $3.425, $2.85 and $2.4725, respectively, per unit. Our distributions
to unitholders for 2000, 1999 and 1998 required incentive distributions to our
general partner in the amount of $107.8 million, $55.0 million and $32.7
million, respectively. The increased incentive distributions paid for 2000 over
1999 and 1999 over 1998 reflect the increase in amounts distributed per unit as
well as the issuance of additional units.


     On January 17, 2001, we declared a cash distribution for the quarterly
period ended December 31, 2000, of $0.95 per unit. This distribution was paid on
February 14, 2001, to unitholders of record as of January 31, 2001, except for
the 640,000 common units and 2,656,700 Class B units issued to KMI on December
21, 2000. This distribution required an incentive distribution to our general
partner in the amount of $32.8 million. Since this distribution was declared
after the end of the quarter, no amount is shown in the December 31, 2000
balance sheet as a Distribution Payable.


                                      F-25
<PAGE>   103
             KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

12.  RELATED PARTY TRANSACTIONS

     GENERAL AND ADMINISTRATIVE EXPENSES

     Our general partner provides us with general and administrative services
and is entitled to reimbursement of all direct and indirect costs related to our
business activities. Our general partner incurred on behalf of us general and
administrative expenses of $54.4 million in 2000, $30.7 million in 1999 and
$38.0 million in 1998. We believe that these amounts were a reasonable
allocation of the expenses incurred on our behalf.

     Since K N Energy, Inc. acquired Kinder Morgan (Delaware), Inc. in October
1999, our general partner has shared administrative personnel with KMI to
operate both KMI's business and our business. As a result, our general partner's
officers, who in some cases may also be officers of KMI, must allocate, in their
reasonable and sole discretion, the time our general partner's employees and
KMI's employees spend on behalf of KMI and on behalf of us. For 2000, KMI paid
our general partner a net payment of $1.0 million in January 2001 as
reimbursement for the services of our general partner's employees. Although we
believe this amount received from KMI for the services it provided in 2000
fairly reflects the net value of the services performed, the determination of
this amount was not the result of arms length negotiations. However, due to the
nature of the allocations, this reimbursement may not have exactly matched the
actual time and overhead spent. We believe the agreed-upon amount was a
reasonable allocation of the expenses for the services rendered. Our general
partner and KMI will continue to evaluate the net amount to be charged for the
services provided to KMI and us by the employees of our general partner and KMI.

     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: 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, 2000, our general partner owned 862,000 common units,
representing approximately 1.3% of the outstanding 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 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 in respect of its remaining 0.5%
special limited partner interest in SFPP.

     Available Cash is initially distributed 98% to our limited partners
(including the approximate 1.3% limited partner interest owned by our general
partner) and 2% to our general partner. These distribution percentages are
modified to provide for incentive distributions to be paid to our general
partner in the event that quarterly distributions to unitholders exceed certain
specified targets.

     Available Cash for each quarter is distributed;

o    first, 98% to the owners of all classes of units pro rata and 2% to our
     general partner until the owners of all classes of units have received a
     total of $0.3025 per unit for such quarter;

o    second, 85% 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 $0.3575 per unit for such quarter;

o    third, 75% 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 $0.4675 per unit for such quarter; and

o    fourth, thereafter 50% to the owners of all classes of units pro rata and
     50% to our general partner.



                                      F-26
<PAGE>   104
             KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     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, 2000, 1999 and 1998 were $107.8 million, $55.0
million and $32.7 million, respectively.

     Kinder Morgan, Inc.

     KMI, through its subsidiary Kinder Morgan (Delaware), Inc., remains the
sole stockholder of our general partner. At December 31, 2000, KMI directly
owned 10,450,000 common units and 2,656,700 Class B units. These units,
excluding the common units indirectly owned by our general partner, represent
approximately 19.4% of the outstanding units.

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
43 years. Future commitments related to these leases at December 31, 2000 are as
follows (in thousands):

<TABLE>
<S>                                         <C>
                   2001                     $       30,622
                   2002                             50,021
                   2003                             48,497
                   2004                             46,480
                   2005                             45,591
                   Thereafter                      670,711
                                            --------------
                 Total minimum payments     $      891,922
                                            ==============
</TABLE>

     We have not reduced our total minimum payments for future minimum sublease
rentals aggregating approximately $2.4 million. Total lease and rental expenses,
including related variable charges were $7.5 million for 2000, $8.8 million for
1999 and $7.3 million for 1998.

     During 1998, we established a unit option plan, which provides that key
personnel are eligible to receive grants of options to acquire units. The number
of units available under the option plan is 250,000. The option plan terminates
in March 2008. As of December 31, 2000, options for 206,800 units were granted
to certain personnel with a term of seven years at exercise prices equal to the
market price of the units at the grant date. In addition, as of December 31,
2000, options for 15,000 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 unit options
granted under our 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.

     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, 1998, two executive officers of our general partner each
had outstanding awards totaling 2% of the incentive compensation value eligible
to be granted under the Executive Compensation Plan. On January 4, 1999, 50% of
the awards granted to these executive officers were vested and paid out. On
April 28, 2000, the remaining 50% of the awards granted to these executive
officers were vested and paid out.



                                      F-27
<PAGE>   105
             KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

14.  RISK MANAGEMENT

     We use energy financial instruments to reduce our risk of price changes in
the spot and fixed price 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:

     o    commodity futures and options contracts;

     o    fixed-price swaps; and

     o    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:

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

     o    gas purchases; and

     o    system use and storage.

     Our risk management activities are only used in order to protect our profit
margins and we are prohibited 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. Gains and losses on hedging positions
are deferred and recognized as natural gas purchases expense in the periods in
which the underlying physical transactions occur.

     Purchases or sales of commodity contracts require a dollar amount to be
placed in margin accounts. In addition, we are required to post margins with
certain over-the-counter swap partners. These margin requirements are determined
based upon credit limits and mark-to-market positions. At December 31, 2000, we
had $7.0 million in margin deposits associated with commodity contract positions
and $0.0 million in margin deposits associated with over-the-counter swap
partners.

     The differences between the current market value and the original physical
contracts value associated with hedging activities are reflected, depending on
maturity, as deferred charges or credits and other current assets or liabilities
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.

     Given our portfolio of businesses as of December 31, 2000, 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.

     The short and long positions shown in the table that follows are
principally associated with the activities described above. Current deferred net
gains (losses) are reported as Deferred Revenues in the current liability
section on the accompanying consolidated balance sheet at December 31, 2000.
Long-term deferred net gains (losses) are included with Other Long-Term
Liabilities and Deferred Credits on the accompanying consolidated balance sheet
at December 31, 2000. In 2001, these amounts will be included with other
comprehensive income as discussed below.



                                      F-28
<PAGE>   106
             KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     As of December 31, 2000, our commodity contracts and over-the-counter swaps
and options (in thousands) consisted of the following:

<TABLE>
<CAPTION>
                                                   Commodity     Over the Counter
                                                   Contracts     Swaps and Options      Total
                                                  ------------   -----------------  ------------
<S>                                               <C>            <C>                <C>
Deferred Net (Loss) Gain                          $     6,977    $       (36,229)   $   (29,252)
Contract Amounts - Gross                          $   816,216    $     1,537,671    $ 2,353,887
Contract Amounts - Net                            $   (58,679)          (156,966)   $  (215,645)
Credit Exposure of Loss                           $        --    $        23,570    $    23,570

Natural Gas
Notional Volumetric Positions: Long                     5,206             11,837
Notional Volumetric Positions: Short                   (5,475)           (14,298)
Net Notional Totals to Occur in 2001                      186             (2,014)
Net Notional Totals to Occur in 2002 and Beyond          (455)              (447)

Crude Oil
Notional Volumetric Positions: Long                        34                102
Notional Volumetric Positions: Short                   (1,585)            (5,108)
Net Notional Totals to Occur in 2001                   (1,107)            (2,147)
Net Notional Totals to Occur in 2002 and Beyond          (444)            (2,589)

Natural Gas Liquids
Notional Volumetric Positions: Long                        --                120
Notional Volumetric Positions: Short                       --               (951)
Net Notional Totals to Occur in 2001                       --               (510)
Net Notional Totals to Occur in 2002 and Beyond            --               (321)
</TABLE>

     In June 1998, the Financial Accounting Standards Board issued SFAS No. 133
"Accounting for Derivative Instruments and Hedging Activities". The statement
establishes accounting and reporting standards requiring that every derivative
instrument (including certain derivative instruments embedded in other
contracts) be recorded in the balance sheet as either an asset of liability
measured at its fair value. The statement requires that changes in the
derivatives fair value be recognized currently in earnings unless specific hedge
accounting criteria are met. If the derivatives meet these criteria, the
statement 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.

     SFAS No. 133, after amendment by SFAS No. 137 and SFAS No. 138, is
effective for all quarters of all fiscal years beginning after June 15, 2000.
The statement cannot be applied retroactively. 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. The statement 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 the
statement will result in the deferred net loss shown in the preceding table
being reported as part of other comprehensive income, as well as subsequent
changes in the market value of these derivatives.

15.  REPORTABLE SEGMENTS

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


                                      F-29
<PAGE>   107
             KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     o    Product Pipelines;

     o    Natural Gas Pipelines;

     o    CO2 Pipelines; and

     o    Bulk 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 excludes general and administrative
expenses, third-party debt costs, interest income and expense and minority
interest. Our reportable segments are strategic business units that offer
different products and services. Each segment is managed separately because each
segment involves different products and marketing strategies. Our Product
Pipelines segment derives its revenues primarily from the transportation of
refined petroleum products, including gasoline, diesel fuel, jet fuel and
natural gas liquids. Our Natural Gas Pipelines segment derives its revenues
primarily from the gathering and transmission of natural gas. Our CO2
Pipelines segment's revenues are primarily derived from the marketing and
transportation of carbon dioxide used as a flooding medium for recovering crude
oil from mature oil fields. Our Bulk Terminals segment derives its revenues from
transloading and storing multiple dry and liquid bulk products, including coal,
petroleum coke, cement, alumina and salt.

     Financial information by segment follows (in thousands):

<TABLE>
<CAPTION>
                                                             2000         1999         1998
                                                           ---------    ---------    ---------
<S>                                                        <C>          <C>          <C>
Revenues
   Product Pipelines                                       $ 421,423    $ 314,113    $ 258,722
   Natural Gas Pipelines                                     173,036           --           --
   CO2 Pipelines                                              89,214           23          979
   Bulk Terminals                                            132,769      114,613       62,916
                                                           ---------    ---------    ---------
   Total consolidated revenues                             $ 816,442    $ 428,749    $ 322,617
                                                           =========    =========    =========

Operating income
   Product Pipelines                                       $ 193,531    $ 186,086    $ 159,227
   Natural Gas Pipelines                                      97,198           --         (103)
   CO2 Pipelines                                              47,901           18          957
   Bulk Terminals                                             36,996       36,917       20,572
                                                           ---------    ---------    ---------
   Total segment operating income                            375,626      223,021      180,653
   Corporate administrative expenses                         (60,065)     (35,614)     (39,984)
                                                           ---------    ---------    ---------
   Total consolidated operating Income                     $ 315,561    $ 187,407    $ 140,669
                                                           =========    =========    =========

Earnings from equity investments, net of amortization of
  excess costs
   Product Pipelines                                       $  29,105    $  21,395    $   5,854
   Natural Gas Pipelines                                      14,975        2,759        4,577
   CO2 Pipelines                                              19,328       14,487       14,500
   Bulk Terminals                                                 --           23           37
                                                           ---------    ---------    ---------
   Consolidated equity earnings, net of amortization       $  63,408    $  38,664    $  24,968
                                                           ---------    ---------    ---------
</TABLE>

                                      F-30

<PAGE>   108

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

<TABLE>
<CAPTION>
                                                        2000         1999         1998
                                                     ---------    ---------    ---------
<S>                                                  <C>          <C>          <C>
Interest revenue
   Product Pipelines                                 $      --    $      --    $      22
   Natural Gas Pipelines                                    --           --           --
   CO2 Pipelines                                            --           --           --
   Bulk Terminals                                           --           --           --
                                                     ---------    ---------    ---------
   Total segment interest revenue                           --           --           22
   Unallocated interest revenue                          3,818        1,731        2,234
                                                     ---------    ---------    ---------
   Total consolidated interest revenue               $   3,818    $   1,731    $   2,256
                                                     =========    =========    =========

Interest (expense)
   Product Pipelines                                 $      --    $      --    $      --
   Natural Gas Pipelines                                    --           --         (338)
   CO2 Pipelines                                            --           --           --
   Bulk Terminals                                           --           --           --
                                                     ---------    ---------    ---------
   Total segment interest (expense)                         --           --         (338)
   Unallocated interest (expense)                      (97,102)     (54,336)     (40,518)
                                                     ---------    ---------    ---------
   Total consolidated interest (expense)             $ (97,102)   $ (54,336)   $ (40,856)
                                                     =========    =========    =========

Other, net
   Product Pipelines                                 $  10,492    $  10,008    $  (6,492)
   Natural Gas Pipelines                                   744       14,099           (6)
   CO2 Pipelines                                           741          710           --
   Bulk Terminals                                        2,607         (669)        (765)
                                                     ---------    ---------    ---------
   Total consolidated other, net                     $  14,584    $  24,148    $  (7,263)
                                                     =========    =========    =========

Income tax benefit (expense)
   Product Pipelines                                 $ (11,960)   $  (8,493)   $  (1,698)
   Natural Gas Pipelines                                    --          (45)         726
   CO2 Pipelines                                            --           --           --
   Bulk Terminals                                       (1,974)      (1,288)        (600)
                                                     ---------    ---------    ---------
   Total consolidated income tax benefit (expense)   $ (13,934)   $  (9,826)   $  (1,572)
                                                     =========    =========    =========

Segment earnings
   Product Pipelines                                 $ 221,168    $ 208,996    $ 156,913
   Natural Gas Pipelines                               112,917       16,813        4,856
   CO2 Pipelines                                        67,970       15,215       15,457
   Bulk Terminals                                       37,629       34,983       19,244
                                                     ---------    ---------    ---------
   Total segment earnings                              439,684      276,007      196,470
   Interest and corporate
     administrative expenses (a)                      (161,336)     (93,705)     (92,864)
                                                     ---------    ---------    ---------
   Total consolidated net income                     $ 278,348    $ 182,302    $ 103,606
                                                     =========    =========    =========
</TABLE>


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


                                      F-31
<PAGE>   109
             KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
                                                                  2000           1999           1998
                                                               -----------    -----------    -----------
<S>                                                            <C>            <C>            <C>
Assets at December 31
   Product Pipelines                                           $ 2,230,287    $ 2,015,995    $ 1,817,126
   Natural Gas Pipelines                                         1,544,489        879,076         27,518
   CO2 Pipelines                                                   417,278         86,684         86,760
   Bulk Terminals                                                  357,689        203,601        186,298
                                                               -----------    -----------    -----------
   Total segment assets                                          4,549,743      3,185,356      2,117,702
   Corporate assets (a)                                             75,467         43,382         34,570
                                                               -----------    -----------    -----------

   Total consolidated assets                                   $ 4,625,210    $ 3,228,738    $ 2,152,272
                                                               ===========    ===========    ===========

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

Depreciation and amortization
   Product Pipelines                                           $    41,659    $    38,928    $    32,687
   Natural Gas Pipelines                                            20,780             --             --
   CO2 Pipelines                                                    10,559             --             --
   Bulk Terminals                                                    9,632          7,541          3,870
                                                               -----------    -----------    -----------

   Total consolidated depreciation and amortization            $    82,630    $    46,469    $    36,557
                                                               ===========    ===========    ===========

Equity Investments at December 31
   Product Pipelines                                           $   231,651    $   243,668    $   124,283
   Natural Gas Pipelines                                           141,613         88,249         27,568
   CO2 Pipelines                                                     9,559         86,675         86,688
   Bulk Terminals                                                       59             59             69
                                                               -----------    -----------    -----------
   Total consolidated equity investments                       $   382,882    $   418,651    $   238,608
Investment in oil and gas assets to be contributed
   to joint venture                                                 34,163             --             --
                                                               -----------    -----------    -----------

                                                                   417,045        418,651        238,608
                                                               ===========    ===========    ===========

Capital expenditures
   Product Pipelines                                           $    69,243    $    68,674    $    28,393
   Natural Gas Pipelines                                            14,496             --             --
   CO2 Pipelines                                                    16,115             --             69
   Bulk Terminals                                                   25,669         14,051          9,945
                                                               -----------    -----------    -----------
   Total consolidated capital expenditures                     $   125,523    $    82,725    $    38,407
                                                               ===========    ===========    ===========
</TABLE>

(1)   The following reconciles segment earnings to net income.

<TABLE>
<CAPTION>
                                                                   2000          1999           1998
                                                               -----------    -----------    -----------
<S>                                                            <C>            <C>            <C>
Segment earnings                                               $   439,684    $   276,007    $   196,470
Interest and corporate
   administrative expenses (a)                                    (161,336)       (93,705)       (92,864)
                                                               -----------    -----------    -----------
Net Income                                                     $   278,348    $   182,302    $   103,606
                                                               ===========    ===========    ===========

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


(2)   The following reconciles segment assets to consolidated assets.

<TABLE>
<CAPTION>
                                                                  2000           1999           1998
                                                               -----------    -----------    -----------
<S>                                                            <C>            <C>            <C>
Segment assets                                                 $ 4,549,743    $ 3,185,356    $ 2,117,702
Corporate assets (a)                                                75,467         43,382         34,570
                                                               -----------    -----------    -----------

Total assets                                                   $ 4,625,210    $ 3,228,738    $ 2,152,272
                                                               ===========    ===========    ===========

(a)  Includes cash, cash equivalents and certain unallocable deferred charges.
</TABLE>


                                      F-32

<PAGE>   110
             KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Our total operating revenues are derived from a wide customer base. During each
of the years ended December 31, 2000 and December 31, 1999, no revenues from
transactions with a single external customer amounted to 10% or more of our
consolidated revenues. In 1998, revenues from one customer of our Products
Pipelines and Bulk Terminals segments represented approximately $42.5 million
(13.2%) of our consolidated revenues. Additionally, in 1998, three other
customers of our Product Pipelines segment accounted for more than 10% of our
consolidated revenues. Revenues from these customers were approximately $39.7
million (12.3%), $35.29 million (11.0%) and $35.28 million (10.9%),
respectively, of consolidated revenues. Our management believes that we are
exposed to minimal credit risk, and we generally do not require collateral for
our receivables.

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, 2000, 1999 and 1998,
the application of the indexing methodology did not significantly affect our
tariff rates.

     FEDERAL ENERGY REGULATORY COMMISSION PROCEEDINGS

     SFPP, L.P.

     SFPP, L.P. is the partnership that owns our Pacific operations. Tariffs
charged by SFPP are subject to certain proceedings involving shippers' protests
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:

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

     o    challenging SFPP's proration policy; and

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

     At various 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:

     o    Chevron U.S.A. Products Company;

     o    Navajo Refining Company;

     o    ARCO Products Company;

     o    Texaco Refining and Marketing Inc.;

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

     o    Mobil Oil Corporation; and

     o    Tosco Corporation.

     Certain of these parties also claimed that a gathering enhancement 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


                                      F-33
<PAGE>   111
             KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

"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:

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

     o    the level of income tax allowance; and

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

     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. SFPP and a number of the
complainants each sought rehearing by FERC of elements of Opinion No. 435. 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.

     SFPP and certain complainants sought rehearing of Opinion No. 435 by the
FERC, asking that a number of rulings be modified. 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.


                                      F-34
<PAGE>   112

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

     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:

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

     o    elimination of civil litigation costs;

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

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

     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:

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

     o    dismiss the Chevron, RHC and SFPP petitions; and

     o    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.

     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.


                                      F-35
<PAGE>   113
             KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     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. Upon the filing by SFPP and other parties of briefs opposing and
supporting the initial decision with the FERC, the ultimate disposition of
SFPP's market rate application will be before the FERC.

     Since the issuance of the initial decision in the Sepulveda case, the FERC
judge has indicated an intention to proceed to consideration of the justness and
reasonableness of the existing rate for service on the Sepulveda Lines. SFPP has
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. Further proceedings on this matter have
been suspended pending resolution of SFPP's motion for clarification to the
FERC.

     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.

     Discovery in this new proceeding is currently being conducted, with a
hearing scheduled for August 2001 and an initial decision by the administrative
law judge due in January 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




                                      F-36
<PAGE>   114
             KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

     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. 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. 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 together with reparations for periods
from the date of the complaint to the date of the implementation of the new
rates.

     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.

     KMIGT

     On January 23, 1998, KMIGT filed a general rate case with the FERC
requesting a $30.2 million increase in annual revenues. As a result of the
FERC's action, KMIGT was allowed to place its rates into effect on August 1,
1998, subject to refund. On November 3, 1999, KMIGT filed a comprehensive
Stipulation and Agreement to resolve all issues in this proceeding. The FERC
approved the Stipulation and Agreement on December 22, 1999. The settlement
rates have been placed in effect, and KMIGT paid refunds of $34.7 million during
2000. The refunds did not exceed amounts previously accrued.

     Trailblazer

     On July 1, 1997, Trailblazer filed a rate case with the FERC (Docket No.
RP97-408) which reflected a proposed annual revenue increase of $3.3 million.
The timing of the rate case filing was in accordance with the requirements of
Trailblazer's previous rate case settlement in Docket No. RP93-55. The FERC
issued an order on July 31, 1997, which suspended the rates to be effective
January 1, 1998. Major issues in the rate case included:

     o    throughput levels used in the design of rates;

     o    levels of depreciation rates;

     o    return on investment; and

     o    the cost of service treatment of the Columbia settlement revenues.

     Trailblazer filed a proposed settlement agreement with the administrative
law judge on May 8, 1998. The presiding administrative law judge certified the
settlement to the FERC in an order dated June 25, 1998. The FERC issued an order
on October 19, 1998 remanding the settlement, which was contested by two
parties, to the presiding administrative law judge for further action. A revised
settlement was filed on November 20, 1998. The presiding administrative law
judge certified the revised settlement to the FERC on January 25, 1999.

     The FERC issued orders on April 28, 1999 and August 3, 1999, approving the
revised settlement as to all parties except the two parties who contested the
settlement. As to the two contesting parties, the FERC established hearing
procedures. On March 3, 2000, Trailblazer and the two parties filed a joint
motion indicating that a settlement in principle had been reached. On March 6,
2000, the presiding administrative law judge issued an order suspending the
procedural schedule and hearing pending the filing of the appropriate documents
necessary to terminate the proceeding. On March 16, 2000, the two contesting
parties filed a motion to withdraw their requests for rehearing of the FERC
orders approving the settlement and concurrently those parties and Trailblazer
jointly moved to terminate the proceeding. On March 30, 2000, the administrative
law judge issued an order granting motion to terminate further proceedings,
followed by an initial decision on April 7, 2000, terminating the


                                      F-37
<PAGE>   115
             KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

proceedings. On May 18, 2000, the FERC issued a notice of the finality of the
initial decision. Refunds related to the rate case were made in April 28, 2000
and totaled approximately $17.8 million. Adequate reserves had previously been
established.

     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.

     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.

     Procedurally, the rehearing complaint will be heard first, followed by
consideration of the April 2000 complaint and SFPP's market-based application,
which have been consolidated for hearing by the CPUC. The rehearing complaint
was the subject of evidentiary hearings in October 2000, and a decision is
expected within two to six months. The April 2000 complaint and SFPP's
market-based application will be the subject of evidentiary hearings in February
2001, with a decision expected within six months of the hearings.

     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.

     FERC ORDER 637

     On June 15, 2000, KMIGT made its filing to comply with the FERC's Orders
637 and 637-A. That filing contained KMIGT's compliance plan to implement the
changes required by the FERC dealing with the way business is conducted on
interstate pipelines. All interstate pipelines are required to make such
compliance filings, according to a schedule established by the FERC. KMIGT's
filing is currently pending FERC action, and any changes to its tariff
provisions are not expected to take effect until after the entire Order 637
process is finished for all pipelines. Separately, numerous petitioners,
including KMIGT, have filed appeals of Order No. 637 in the D.C. Circuit,
potentially raising a wide array of issues.



                                      F-38
<PAGE>   116

     CARBON DIOXIDE LITIGATION

     Kinder Morgan CO2 Company, L.P., as the successor to Shell CO2 Company,
Ltd. and directly and 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 are comprised of royalty, overriding royalty and small share working
interest owners who claim that they were underpaid by the defendants. These
cases are: CO2 Claims Coalition, LLC v. Shell Oil Co., et al., No. 96-Z-2451
(U.S.D.C. Colo.); Rutter & Wilbanks et al. v. Shell Oil Co., et al., No.
00-Z-1854 (U.S.D.C. Colo.); Watson v. Shell Oil Co., et al., No. 00-Z-1855
(U.S.D.C. Colo.); Ainsworth et al. v. Shell Oil Co., et al., No. 00-Z-1856
(U.S.D.C. Colo.); United States ex rel. Crowley v. Shell Oil Company, et al.,
No. 00-Z-1220 (U.S.D.C. Colo.); Ptasynski et al. v. Shell Western E&P Inc., et
al., No. 3:97-CV-1208-R (U.S.D.C. Tex. N. Dist. Dallas Div.); Feerer et al. v.
Amoco Production Co., et al., No. 99-2231 (U.S. Ct. App. 10th Cir.); Shell
Western E&P Inc. v. Bailey, et al., No 98-28630 (215th Dist. Ct. Harris County,
Tex.); Shores, et al. v. Mobil Oil Corporation, et al., No. GC-99-01184 (Texas
Probate Court, Denton County); and Celeste C. Grynberg v. Shell Oil Company, et
al., No. 98-CV-43 (Colo. Dist. Ct. Montezuma County).

     Although no assurances can be given, we believe that we have meritorious
defenses to 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 generally imposes joint and several liability for
cleanup and enforcement costs on current or predecessor owners and operators of
a site, without regard to fault or the legality of the original conduct. Our
operations are also subject to federal, state and local laws and regulations
relating to protection of the environment. Although we believe our operations
are in substantial compliance with applicable environmental regulations, risks
of additional costs and liabilities are inherent in pipeline and terminal
operations, and there can be no assurance that we will not incur significant
costs and liabilities. Moreover, it is possible that other developments, such as
increasingly stringent environmental laws, regulations and enforcement policies
thereunder, and claims for damages to property or persons resulting from our
operations, could result in substantial costs and liabilities to us.

     We are currently involved in the following governmental proceedings related
to compliance with environmental regulations:

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

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

     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 five sites. Further delineation and remediation of these
impacts will be conducted. A reserve was established to address the closure of
these issues.

     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 results of
operations. We have recorded a reserve for environmental claims in the amount of
$21.1 million at December 31, 2000.

     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.



                                      F-39
<PAGE>   117

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

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>
2000
    First Quarter             $157,358        $63,061           $59,559           $0.63          $0.63
    Second Quarter             193,758         79,976            71,810            0.70           0.70
    Third Quarter              202,575         79,826            69,860            0.67           0.67
    Fourth Quarter             262,751         92,698            77,119            0.68           0.68


1999
    First Quarter             $100,049        $47,645           $41,069           $0.57          $0.57
    Second Quarter             102,933         47,340            43,113            0.61           0.61
    Third Quarter (1)          104,388         48,830            52,553            0.77           0.77
    Fourth Quarter             121,379         43,592            45,567            0.62           0.62

</TABLE>

(1) 1999 third quarter includes an extraordinary charge of $2.6 million due to
    an early extinguishment of debt. Net income before extraordinary charge was
    $55.1 million and basic net income per unit before extraordinary charge was
    $0.82.



                                      F-40
<PAGE>   118
                                   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 on the 27th day of
April 2001.


                                      KINDER MORGAN ENERGY PARTNERS, L.P.
                                      (A Delaware Limited Partnership)
                                      By: KINDER MORGAN G.P., INC.
                                      as General Partner

                                      By: /s/ JOSEPH LISTENGART
                                         --------------------------------------
                                            Joseph Listengart
                                            Vice President and General Counsel


                                      S-1


<PAGE>   119
                                 EXHIBIT INDEX

<TABLE>
<CAPTION>
      EXHIBIT
      NUMBER        DESCRIPTION
      -------       -----------
<S>                <C>
       *2.1         Stock Purchase Agreement dated November 30, 2000 between
                    GATX Rail Corporation, GATX Terminals Holding Corporation
                    and Kinder Morgan Energy Partners, L.P. (filed as Exhibit
                    99(b) to the Partnership's Current Report on Form 8-K filed
                    December 1, 2000).

       *3.1     -   Second Amended and Restated Agreement of Limited Partnership
                    of Kinder Morgan Energy Partners, L.P. effective as of
                    February 14, 1997 (filed as Exhibit 3.1 to Amendment No. 1
                    to Kinder Morgan Energy Partners, L.P. Registration
                    Statement on Form S-4, file No. 333-46709, filed on
                    April 14, 1998).

       *3.2     -   Amendment No. 1 to Second Amended and Restated Agreement of
                    Limited Partnership of Kinder Morgan Energy Partners, L.P.
                    dated as of January 20, 2000 (filed as Exhibit 4.1 to the
                    Partnership's Current Report on Form 8-K filed
                    January 20, 2000).

        3.3     -   Amendment No. 2 to Second Amended and Restated Agreement of
                    Limited Partnership of Kinder Morgan Energy Partners, L.P.
                    dated as of December 21, 2000.

       *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     -   Registration Rights Agreement dated March 22, 2000 among
                    Kinder Morgan Energy Partners, Goldman, Sachs & Co.,
                    Merrill Lynch & Co., Banc of America Securities LLC and
                    First Union Securities, Inc. (filed as Exhibit 4.3 to
                    the April 2000 Form S-4).

        4.8     -   Indenture dated November 8, 2000 between Kinder Morgan
                    Energy Partners and First Union National Bank, as Trustee.

        4.9     -   Form of 7.50% Note (contained in the Indenture filed as
                    Exhibit 4.8).

        4.10    -   Registration Rights Agreement dated November 8, 2000
                    between Kinder Morgan Energy Partners and Banc of America
                    Securities LLC.

        4.11    -   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).

        4.12    -   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).

        4.13    -   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. Section 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
                    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).
</TABLE>


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<TABLE>
<S>                <C>
     * 10.6     -   Intrastate Pipeline system Lease, dated December 31, 1996,
                    between MidCon Texas Pipeline, L.P. and MidCon Texas
                    Pipeline Operator, Inc. (filed as Exhibit 10(y) to Kinder
                    Morgan, Inc.'s 1997 Form 10-K).

     * 10.7     -   Amendment Number One to Intrastate Pipeline system Lease,
                    dated December 31, 1996, between MidCon Texas Pipeline,
                    L.P. and MidCon Texas Pipeline Operator, Inc. (filed as
                    Exhibit 10(z) to Kinder Morgan, Inc.'s 1997 Form 10-K).

       21.1     -   List of Subsidiaries.

     **23.1     -   Consent of PricewaterhouseCoopers LLP.
</TABLE>

---------
*  Asterisk indicates exhibits incorporated by reference as indicated.
** Double asterisk indicates exhibit filed with this Form 10-K/A.

All other exhibits filed with Form 10-K for the year ended December 31, 2000.