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

                                    FORM 10-K

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

   For the fiscal year ended December 31, 2001   Commission File Number: 1-12872

                                       OR

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

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


                  Delaware                             76-0424520
--------------------------------------------   ----------------------------
      (State or Other Jurisdiction of               (I.R.S. Employer
       Incorporation or Organization)              Identification No.)

     2000 West Sam Houston Parkway South,
                   Suite 400
                Houston, Texas                            77042
--------------------------------------------   -------------------------------
   (Address of principal executive offices)             (Zip Code)

                                 (713) 993-5200
              ----------------------------------------------------
              (Registrant's telephone number, including area code)


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

   Title of each class               Name of each exchange on which registered
---------------------------        -------------------------------------------
      Common Units                            New York Stock Exchange


           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     No  X
                                              ---    ---

     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. [ ]

     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 May 1, 2002, was approximately $76,601,935.

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                           EOTT ENERGY PARTNERS, L.P.
                                TABLE OF CONTENTS


<Table>
<Caption>

                                                                            Page
                                                                            ----
<S>      <C>                                                                <C>
                                     PART I

Item 1.  Business                                                             3
Item 2.  Properties                                                          23
Item 3.  Legal Proceedings                                                   24
Item 4.  Submission of Matters to a Vote of Security Holders                 27

                                     PART II

Item 5.  Market for Registrant's Common Units and Related Security
           Holder Matters                                                    28
Item 6.  Selected Financial Data                                             30
Item 7.  Management's Discussion and Analysis of Financial Condition
           and Results of Operations                                         33
Item 7a. Quantitative and Qualitative Disclosures about Market Risk          57
Item 8.  Financial Statements and Supplementary Data                         59
Item 9.  Changes in and Disagreements with Accountants on Accounting and
           Financial Disclosures                                             59


                                 PART III

Item 10. Directors and Executive Officers of the Registrant                  61
Item 11. Executive Compensation                                              65
Item 12. Security Ownership of Certain Beneficial Owners
           and Management                                                    72
Item 13. Certain Relationships and Related Transactions                      74

                                  PART IV

Item 14. Exhibits, Financial Statement Schedule, and Reports on Form 8-K     75
</Table>



                                       2
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                                     PART I

ITEM 1. BUSINESS

GENERAL

     EOTT Energy Partners, L.P. (the "MLP") is a Delaware limited partnership
that operates principally through its four affiliated operating limited
partnerships, EOTT Energy Operating Limited Partnership, EOTT Energy Canada
Limited Partnership, EOTT Energy Pipeline Limited Partnership, and EOTT Energy
Liquids L.P., each of which is a Delaware limited partnership. In 1999, we
formed EOTT Energy Finance Corp., as a direct wholly-owned subsidiary of the
MLP. This entity was set up in connection with a debt offering to facilitate
certain investors' ability to purchase our senior notes, more fully described in
Note 8 to the Consolidated Financial Statements. In 2001, we formed EOTT Energy
General Partner, L.L.C., which now serves as the general partner for our four
affiliated operating limited partnerships. Unless the context otherwise
requires, the terms "we", "EOTT" and the "Partnership" refer to EOTT Energy
Partners, L.P., our four affiliated limited operating partnerships, EOTT Energy
Finance Corp., and EOTT Energy General Partner, L.L.C., and for periods prior to
our initial public offering in March 1994, EOTT Energy Corp., its wholly-owned
subsidiary, EOTT Energy Ltd., and its affiliated company, Enron Products
Marketing Company.

     We are engaged in the purchasing, gathering, transporting, trading, storage
and resale of crude oil, refined petroleum products, natural gas liquids ("NGL")
and related activities. We are also engaged in the ownership and operation of a
hydrocarbon processing plant that produces methyl tertiary butyl ether ("MTBE")
and in the ownership and operation of a natural gas liquids storage facility.
Our principal business segments are our North American - East of Rockies crude
oil gathering and marketing operations, our Pipeline Operations, our Liquids
Operations and our West Coast Operations. See Note 15 to the Consolidated
Financial Statements for certain financial information by business segment.

     EOTT Energy Corp. (our "General Partner"), a Delaware corporation and a
wholly-owned subsidiary of Enron Corp. ("Enron"), serves as the sole general
partner of the MLP. In August 2001, we reorganized the ownership of our three
original operating partnerships, EOTT Energy Operating Limited Partnership, EOTT
Energy Pipeline Limited Partnership and EOTT Energy Canada Limited Partnership,
to make all of our operating partnerships 100% owned subsidiaries of the MLP. In
the reorganization, our General Partner exchanged its 1% general partner
interest in each of our three original operating partnerships for an additional
0.98% general partner interest in the MLP. EOTT Energy General Partner, L.L.C.,
which is wholly-owned by the MLP, serves as general partner of our three
original operating partnerships and of EOTT Energy Liquids, L.P. This
reorganization was effected in order to save substantial costs of compliance
with Securities and Exchange Commission (the "SEC") regulations adopted in 2000.
Without the reorganization, the rules would have required us to provide
separate, audited financial statements for each of the three original operating
partnerships in connection with any guaranteed securities we might choose to
register. The reorganization had no material impact on our unitholders or on the
MLP because the interests contributed to the MLP by our General Partner were at
least equal in value to the additional 0.98% general partner interest that the
MLP issued in consideration for the contribution.

     As of December 31, 2001, our General Partner owned an approximate 1.98%
general partner interest in the MLP. Based upon information provided by Enron,
Enron beneficially owns approximately 18% of our outstanding common units, 78%
of our outstanding subordinated units and 37% of our total units outstanding
because it retains voting power and shared investment power over the securities.
For details concerning Enron and its bankruptcy filing see "Impact of Enron
Bankruptcy on Our Business" below and Item 7. "Management's Discussion and
Analysis of Financial Condition and Results of Operations - Impact of the
Bankruptcy of Enron and Certain of Its Subsidiaries, and Related Events" below.


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PRIOR YEAR UNAUDITED FINANCIAL INFORMATION

     In connection with a proxy filing as submitted to the SEC in the fall of
2001 concerning our planned recapitalization, which was subsequently terminated
due to the Enron bankruptcy, the SEC reviewed our previous 1934 Act filings and
we received comments from the SEC to which we are in the process of responding.
In response to certain SEC comments regarding unauthorized trading activities,
disclosed in our previous SEC filings, we are restating prior year financial
results to reflect the fair value impact of these transactions over the periods
during which the contracts were outstanding. See "Management Discussion and
Analysis - Results of Operations" and Note 3 to the Consolidated Financial
Statements.

     On February 5, 2002, Arthur Andersen LLP ("Andersen") withdrew as our
independent accountants. We were informed that Andersen's withdrawal related to
Andersen's professional standard concerns, including auditor independence
issues, related to events involving Enron. The restatement of our financial
statements for the years 1998 and 1999, and the quarterly periods in 1999 and
2000, requires the issuance of an updated audit opinion covering the years 1999
and 2000 from Andersen or the issuance of a new audit opinion covering those
years by a new independent accountant. Since Andersen has advised us they will
not issue an updated opinion due to the independence issues related to their
resignation, and our current independent accountants' engagement for purposes of
this Annual Report is presently limited to an audit of 2001, we are filing
unaudited financial statements for the years 1999 and 2000 with this Annual
Report. We have requested PricewaterhouseCoopers LLP ("PWC"), our current
independent accountants, to consider auditing the affected periods and they are
reviewing our request. We will consider alternatives for obtaining an audit of
the affected periods, as necessary. We can make no assurances we will be able
to obtain an audit of the affected periods. See Note 3 to the Consolidated
Financial Statements.

OVERVIEW

     We are one of the largest independent crude oil gathering and marketing
companies in North America. We currently gather and market from approximately
30,000 field gathering points in 19 states and Canada, averaging 329,600 barrels
per day at the end of 2001. In addition, we are engaged in interstate and
intrastate crude oil transportation, crude oil terminalling and storage
activities and refined petroleum products marketing. We purchase crude oil from
various producers and operators and market the crude oil to refiners and other
customers nationwide. We transport crude oil through pipelines, including
approximately 8,000 miles of active gathering and transmission pipelines that we
own, and through our trucking operation, which includes a fleet of 238 owned or
leased trucks. We have approximately 12.2 million barrels of active storage
capacity associated with field tanks. During 2001, we purchased liquids
processing, storage and transportation assets, and through those assets, we are
engaged in the production of MTBE and the transportation and storage of natural
gas liquids.

IMPACT OF ENRON BANKRUPTCY ON OUR BUSINESS

     Enron and certain of its subsidiaries filed voluntary petitions for relief
under Chapter 11 of Title 11 of the United States Code with the United States
Bankruptcy Court for the Southern District of New York (the "Bankruptcy Court")
beginning on December 2, 2001. Although our General Partner is a wholly-owned
subsidiary of Enron, neither we nor our General Partner are a party to any of
these Chapter 11 filings.

     Enron's bankruptcy filing, however, has adversely impacted us in various
ways. At the time of the filing of the bankruptcy petition, we had a number of
contractual relationships with Enron and its subsidiaries. The most significant
of these relationships included ten-year toll conversion and storage agreements
(the "Toll Conversion Agreement" and the "Storage Agreement") with Enron Gas
Liquids, Inc. ("EGLI"), a wholly-owned subsidiary of Enron that was included in
Enron's bankruptcy filings; Enron's guaranty of payments under the Toll
Conversion and Storage Agreements (limited to $50 million under the Toll
Conversion Agreement and $25 million under the Storage Agreement); an obligation
of Enron to provide cash distribution


                                       4
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support up to $29 million to us for any shortfall in available cash below our
minimum quarterly distribution amount through the fourth quarter of 2001; an
Enron credit facility in the amount of $1.0 billion to provide us credit support
in the form of guarantees, letters of credit and working capital loans with
sublimits of $100 million for working capital loans and $900 million for
guarantees and letters of credit that expired December 31, 2001; and Enron
indemnity obligations entered into in connection with our purchase of the
liquids processing, storage and transportation assets in June 2001. For further
details regarding our relationships with Enron and its subsidiaries, see Item 7.
"Management's Discussion and Analysis of Financial Condition and Results of
Operations - Impact of the Bankruptcy of Enron and Certain of Its Subsidiaries,
and Related Events," and Item 13. "Certain Relationships and Related
Transactions."

     Enron's financial deterioration and related bankruptcy filings and related
events have had a number of material effects on our business and management:

     o   Our trade creditors have been less willing to extend credit to us on an
         unsecured basis, increasing the amount of letters of credit we have
         been required to post for our North American Crude Oil - East of
         Rockies business segment. Letters of credit increased from
         approximately $150 million in September 2001 to $196 million in
         December 2001, and to approximately $243 million in March 2002 (which
         also reflects an increase in crude oil prices during this period).

     o   As a result of EGLI's non-performance of the Toll Conversion and
         Storage Agreements, we recorded a $29.1 million impairment in the
         fourth quarter of 2001 representing our total remaining investment in
         the agreements. In addition, we have assumed significant commodity
         price risk, conversion risk and volatility related to the liquids
         processing assets purchased from Enron in June of 2001. As a result,
         our financial results could be significantly different than we
         anticipated when we acquired these assets.

     o   Andersen resigned as our auditors on February 5, 2002, citing
         professional standards concerns, including auditor independence issues,
         relating to the events involving Enron.

     o   The three independent directors of our General Partner, constituting
         all of the members of our audit committee, as well as an Enron
         affiliated director, resigned as directors citing personal reasons.

     o   Our senior notes have been downgraded, our recapitalization plan
         proposed in 2001 was terminated, and the value of our common units has
         declined significantly, which has restricted our access to the equity
         markets.

     o   In 2001, we financed the purchase price of our liquids processing,
         storage and transportation assets through borrowings from Standard
         Chartered Trade Services Corporation ("SCTS") under short-term
         inventory and receivables financing facilities. Under our current
         circumstances, any refinancing of these assets on a long-term basis
         will likely be at higher interest rates than we expected to incur prior
         to the Enron bankruptcy.

     We have acted to address the numerous significant effects of the Enron
bankruptcy and related developments and, among other actions have taken the
following significant steps:

     o   On April 10, 2002, three independent directors were elected to our
         General Partner's Board of Directors ("Board of Directors"). These
         three directors comprise our current Audit Committee, Compensation
         Committee and our new Restructuring Committee. In addition, one of
         these independent directors was named Chairman of the Board of
         Directors.

     o   We engaged PWC to replace Andersen on March 25, 2002.


                                       5
<PAGE>


     o   We have retained UBS Warburg as our financial adviser to help us
         evaluate a number of strategic alternatives for our business.

     o   In January 2002, we announced that the distribution for the fourth
         quarter of 2001 would be $0.25 per common unit, a decrease from the
         $0.475 per common unit minimum quarterly distribution intended under
         our Partnership Agreement. We requested distribution support from Enron
         for the cash distribution shortfall of $0.225 per common unit, which
         Enron did not provide. Any potential claim relating to Enron's failure
         to provide the requested support will be addressed through Enron's
         bankruptcy proceedings.

     o   Our primary lender, Standard Chartered Bank ("Standard Chartered"),
         provided us with an interim credit facility in November 2001 that
         provided for up to $150 million of letters of credit to replace our
         Enron credit facility. On December 21, 2001, we increased this interim
         credit facility to $300 million, including a $40 million sub-limit for
         working capital loans. Effective April 23, 2002, we amended and
         extended our credit facility with Standard Chartered, which is now
         available through the end of February 2003 for working capital loans
         and for the issuance of letters of credit of up to $300 million.
         Additionally, on April 23, 2002, we amended and extended our
         receivables financing and inventory repurchase facilities totaling $200
         million, provided by SCTS.

     o   Based upon our contractual relationships with Enron, we are evaluating
         claims against Enron's and its pertinent affiliates' bankruptcy estate.
         We are, however, uncertain regarding the amount of damages for any such
         claims that we will be able to establish in the bankruptcy proceedings,
         and we cannot predict the amounts or timing of collection of any such
         damages, if any are ever collected.

     For further details on the impact of Enron's bankruptcy see "Liquids
Operations - Toll Conversion and Storage Agreements," Item 7. "Management's
Discussion and Analysis of Financial Condition and Results of Operation," and
Item 10. "Directors and Executive Officers of the Registrant" below.

BUSINESS ACTIVITIES

     We engage in the following business activities:

     o   GATHERING AND MARKETING. We gather, store and transport crude oil in
         the United States and Canada. This involves purchasing and gathering
         crude oil from over 1700 producers, operators and other sellers for
         subsequent sale to refiners and other customers. We operate gathering
         systems in all major production areas in the lower 48 states. We also
         provide certain accounting and administrative services to some
         producers and operators. We believe that our ability to offer reliable
         and reasonably priced services to producers and operators is a key
         factor in maintaining lease crude oil volumes. After the sale of our
         West Coast crude oil gathering and marketing operations in June 2001,
         all of these operations are included in our North American Crude Oil -
         East of Rockies business segment.

     o   PIPELINE OPERATIONS. Through our common carrier pipeline systems, we
         transport crude oil for our gathering and marketing operations and for
         third parties pursuant to published tariff rates regulated by the
         Federal Energy Regulatory Commission ("FERC") and state regulatory
         authorities. We transported an average of approximately 500,000 barrels
         per day at the end of 2001, a significant portion of which was
         transported for our own gathering and marketing operations. We conduct
         these operations in our Pipeline Operations business segment.
         Approximately 80% of the revenues from our Pipeline Operations business
         segment for the twelve months ended December 31, 2001 were generated
         from tariffs charged to our North American Crude Oil - East of Rockies
         business segment and sales of crude oil inventory to our North American
         Crude Oil - East of Rockies business segment.


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<PAGE>


     o   LIQUIDS OPERATIONS. We own and operate liquids processing, storage and
         transportation assets purchased in June 2001, which are located in the
         Texas Gulf Coast region. Our hydrocarbon processing complex at Morgan's
         Point, Texas (the "MTBE Plant"), produces approximately 16,000 barrels
         per day of MTBE and other end products. Our natural gas liquids storage
         facility located in Mont Belvieu, Texas (the "Mont Belvieu Facility")
         consists of 10 active storage wells and, through that facility, we
         provide capacity of approximately ten million barrels. Through a
         120-mile liquids pipeline grid system and related loading, unloading
         and transportation facilities, we transport natural gas liquids and
         other products to and from the Mont Belvieu Facility, the MTBE Plant
         and other distribution points.

     o   WEST COAST OPERATIONS. We own and operate a gas processing plant, a
         fractionation plant, and refrigerated propane storage and related truck
         and rail distribution facilities in Kern County, California. We also
         participate in the refined petroleum products marketing business on the
         West Coast. Effective June 30, 2001, we sold our former West Coast
         crude oil gathering and blending operations.

NORTH AMERICAN CRUDE OIL - EAST OF ROCKIES OPERATIONS

     Our crude oil gathering and marketing operations consist of purchasing and
gathering crude oil from producers and operators in 19 states and Canada for
subsequent sale to refiners and other customers. Gathering and marketing of
crude oil consists of:

     o   purchasing lease crude oil from producers and operators at field
         gathering points and in bulk from aggregators at major pipeline
         interconnections and marketing locations;

     o   transporting crude oil through our own proprietary or common carrier
         pipelines, through our fleet of trucks or on assets owned and operated
         by third parties;

     o   buying and selling crude oil or exchanging it for either another grade
         of crude oil or for crude oil at a different geographic location or
         delivery time in order to increase margins or meet contract delivery
         requirements; and

     o   marketing crude oil to refiners, large integrated oil companies and
         other customers.

     As a gatherer and marketer, we seek to earn profits primarily by buying
crude oil at competitive prices, efficiently transporting and handling the
purchased crude oil and marketing the crude oil to refinery customers or other
trade partners. We purchase and sell crude oil primarily under contracts with
30-day renewable terms, with some contracts having terms from two months to one
year. In connection with the acquisition of assets from Koch Oil Company, now
Koch Supply & Trading, L.P. ("Koch") in December 1998, we entered into a 15-year
supply contract at market-based prices with Koch for less than 25% of our lease
crude oil volumes. For further details, see Item 7. "Management's Discussion and
Analysis of Financial Condition and Results of Operations - Other Matters."

Crude Oil Gathering

     In a typical producer's operation, crude oil flows from the oil well to a
separator where the petroleum gases are removed. After separation, the crude oil
is treated to remove water, sand and other contaminants and is then moved into
the producer's on-site storage tanks. When the tank is full, the producer
contacts field personnel to purchase and transport the crude oil to market. We
use our pipelines and trucks to transport to market most of the crude oil we
purchase.

     We engage in several types of purchases, sales and exchanges of crude oil.
Most transactions we enter into are at market responsive prices, with a large
number of transactions on a 30-day renewable basis. Such


                                       7
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purchases are automatically renewable on a month-to-month basis until terminated
by either party. The purchases are typically based on our daily posted prices,
or the price at which we are willing to pay producers in a particular region,
plus a bonus. The bonus is determined based on grade of oil, transportation
costs and other competitive factors. Both the posted price and the bonus change
in response to market conditions. Posted prices can change daily, and bonuses,
in general, can change every 30 days as contracts renew. Conducting business
under these short-term contracts with multiple producers helps us reduce our
overall basis risk (i.e., the risk that price relationships between delivery
points, grades of crude oil or delivery periods will change). See "Risk
Management/Derivatives."

Crude Oil Marketing

     The marketing of crude oil is complex and requires detailed knowledge of
the crude oil market and a familiarity with a number of factors including: types
of crude oil, individual refinery demand for specific grades of crude oil, area
market price structures for the different grades of crude oil, location of
customers, availability of transportation facilities, and timing and costs
(including storage) involved in delivering crude oil to the appropriate
customer. We market crude oil through our extensive gathering and marketing
asset base, which allows us to select among several transportation, storage and
delivery alternatives.

     Generally, as we purchase lease crude oil, we enter into corresponding sale
transactions involving physical deliveries of crude oil to third party users,
such as independent refineries, or corresponding sales of futures contracts on
the New York Mercantile Exchange ("NYMEX"). This process enables us to minimize
our exposure related to price risk until we make physical delivery of the crude
oil. After the initial purchase of a lease barrel, we may re-market that barrel
both in the futures and physical markets in order to maximize the value of the
lease crude oil volumes. Throughout the process, we seek to maintain a
substantially balanced position with respect to the price and volume of crude
oil purchases and sales; however, we have certain risks that cannot be
completely hedged, including, among other things, basis risks and the risk that
the estimated lease volumes to be purchased could vary significantly from what
is actually purchased.

     Market conditions significantly impact our sales and marketing strategies.
During periods when the demand for crude oil is weak, the market for crude oil
is often in "contango," meaning that the price of crude oil in a given month is
less than the price of crude oil in a subsequent month. In a contango market,
storing crude oil is favorable, because storage owners at major trading
locations can simultaneously purchase production at lower current prices for
storage and sell at higher prices for future delivery. When there is a higher
demand than supply of crude oil in the near term, the market is "backwardated,"
meaning that the price of crude oil in a given month exceeds the price of crude
oil in a subsequent month. A backwardated market has a positive impact on
marketing margins because crude oil gatherers can capture a premium for prompt
deliveries.

Producer Services

     Purchasing crude oil from producers and operators is done on the basis of
competitive pricing and reliable and responsive customer service. We believe
that our ability to offer services to producers and operators is an important
factor in maintaining lease crude oil volumes and in obtaining new volumes. Our
gathering and marketing assets and related service capabilities allow us to
provide timely pickup of crude oil from producers' tanks at the lease or
production point, accurate measurement of crude oil volumes delivered, and
certain accounting and administrative services. Accounting and administrative
services include processing division orders (dividing payments among the owners
of interests in a lease), providing statements of the crude oil purchased by us
each month, disbursing production proceeds to interest owners and calculation
and payment of severance and production taxes on behalf of interest owners. In
order to compete effectively, we must efficiently handle title and division
order issues and payment and regulatory reporting of all severance and
production taxes. We must do this in a professional and timely manner, thereby
ensuring the prompt and


                                       8
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correct processing or payment of crude oil production proceeds and taxes. These
producer services will continue to be a key component in our strategy as the
smaller producers find it difficult to maintain these services internally.

Competition

     Competitive factors in the crude oil gathering and marketing business
include price, quality of service, transportation facilities, financial strength
and knowledge of products and markets. There are a number of structural and
economic factors impacting all of our market segments that drive new customer
needs, change competitor dynamics and, consequently, create new challenges and
opportunities for responsive market participants. The general decline in
domestic lease crude oil production has made competition among gatherers and
marketers even more intense.

     In our crude oil gathering and marketing business, we compete with major
oil companies, large independent crude gatherers and a large number of small
independent gatherers. Our principal competitors in the purchase of leasehold
crude oil production include BP Amoco PLC, Equiva, Plains All American and Sun
Refining & Marketing.

PIPELINE OPERATIONS

     Through our common carrier pipeline systems, we transport crude oil for our
North American Crude Oil - East of Rockies business segment and third party
customers pursuant to published tariff rates regulated by the FERC and state
regulatory authorities. Accordingly, we offer transportation services to any
shipper of crude oil, provided that the crude oil meets the conditions and
specifications contained in the applicable pipeline tariff. Our Pipeline
Operations business segment transported an average of approximately 500,000
barrels per day through our regulated pipeline systems as of the end of 2001.
Pipeline revenues are primarily a function of the amount of crude oil
transported through the pipeline, known as throughput, and the applicable
pipeline tariffs. Approximately 80% of the revenues from our Pipeline Operations
business segment for the twelve months ended December 31, 2001 were generated
from tariffs charged to our North American Crude Oil - East of Rockies business
segment and sales of crude oil inventory to our North American Crude Oil - East
of Rockies business segment. Our operating income from our Pipeline Operations
business segment is primarily generated by the difference between the published
tariff and the fixed and variable costs of operating the pipelines.

     Our General Partner entered into an agreement with Enron Pipeline Services
Company ("EPSC"), a wholly-owned subsidiary of Enron Corp. that is not in
bankruptcy, to provide certain operating and administrative services to our
General Partner, effective October 1, 2000. These services were previously
performed directly by our General Partner. The agreement provides that our
General Partner will reimburse EPSC for its costs and expenses in rendering the
services. In turn, we have a corresponding obligation to our General Partner.
The General Partner anticipates taking over these services in 2002 to provide
them to us directly. See also Item 7. "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Impact of the Bankruptcy of
Enron and Certain of Its Subsidiaries, and Related Events - Our General
Partner's Operation and General Administration of the Partnership."

     We believe that pipelines provide the lowest-cost method of transportation,
and accordingly, we have focused on increasing the percentage of barrels
transported via pipelines through acquisitions of pipeline assets. Our extensive
pipeline network allows us to be the low-cost operator in many of the regions in
which we operate. In addition, with an increase in volume, we have the
opportunity to add incremental cash flow at marginal additional cost given that
our pipeline system operates at approximately two-thirds of capacity.


                                       9
<PAGE>


LIQUIDS OPERATIONS

     In June 2001, we purchased certain liquids processing, storage and
transportation assets located in the Texas Gulf Coast region through our newly
created, wholly-owned subsidiary, EOTT Energy Liquids, L.P. and concurrently
entered into ten-year Toll Conversion and Storage Agreements. We paid $117
million in cash to Enron and State Street Bank and Trust Company of Connecticut,
National Association, Trustee. The assets held by the Trustee were held under a
lease financing arrangement with Enron. Immediately prior to the acquisition,
all of the assets were operated by EGP Fuels Company, a wholly-owned subsidiary
of Enron. The acquisition included the following:

     o   the MTBE Plant, a hydrocarbon-processing complex located in Morgan's
         Point, Texas, used for the production of isobutylene and MTBE;

     o   the Mont Belvieu Facility, an underground natural gas liquids storage
         facility located in Mont Belvieu, Texas, that consists of ten active
         storage wells with a total capacity of approximately ten million
         barrels;

     o   a 120-mile liquids pipeline grid system used for the transportation of
         natural gas liquids to and from the Mont Belvieu Facility, the MTBE
         Plant and other distribution points; and

     o   related loading, unloading and transportation facilities, consisting of
         a barge dock, railcar, and truck loading and unloading facilities, as
         well as several interconnections to other pipelines.

     We acquired these facilities pursuant to the terms of an agreement with
Enron, effective June 30, 2001. We financed the purchase price through
borrowings from SCTS under short-term inventory and receivables financing
facilities.

Production of MTBE and Other Products

     MTBE is a component used by refiners and blenders as an octane enhancer and
oxygenate for gasoline. The market for MTBE as an octane enhancer grew rapidly
in the 1980s as a result of the phasing out of lead gasoline additives for
environmental reasons. The passage of additional environmental legislation,
particularly the Clean Air Act Amendments of 1990, to reduce carbon monoxide and
ozone pollution in a large number of U.S. cities furthered the growth in demand
for MTBE as an oxygenate to enhance the clean burning properties of gasoline.
The Oxygenated Fuel Program, effective November 1992, mandated oxygenate content
for gasoline in winter months in carbon monoxide non-attainment areas and the
Reformulated Fuel Program, effective January 1, 1995, required the sale of
reformulated gasoline year-round in cities having severe ozone depletion.
Approximately 85% of reformulated gasoline contains MTBE as an oxygenate.

     MTBE is produced by reacting methanol with isobutylene, which is derived
from isobutane. We produce isobutylene from butane streams by first isomerizing
butane to isobutane in our butane isomerization unit. The isobutane is treated
for the removal of sulfur and then, at our MTBE Plant, the isobutane is
dehydrogenated into isobutylene, which is finally reacted with methanol to
produce MTBE. In the process of producing MTBE, we utilize licenses from UOP,
Inc.

Product Distribution System

     Our MTBE Plant is strategically located at the entrance to the Houston Ship
Channel, with existing pipeline connections to draw upon the vast supplies of
feedstock available at Mont Belvieu, Texas, which is the world's largest
aggregation point for natural gas liquids and other hydrocarbons and has
excellent access to a large number


                                       10
<PAGE>


of major refining and petrochemical complexes in the area. Our principal
feedstocks are methanol, normal butane and natural gas, which we purchase from
various suppliers on both a short-term contract and spot basis at prices linked
to prevailing market prices. We sell MTBE to oil refiners and gasoline producers
on both a short-term contract and spot basis at prices linked to prevailing
market prices. The MTBE we produce leaves our MTBE Plant by way of our barge
dock located at the entrance of the Houston Ship Channel.

Market and Competition

     The growth in the market for MTBE has been driven by the requirements of
the Clean Air Act ("CAA"). Although oxygen requirements under the CAA can be
attained using other oxygenates such as ethanol, MTBE has gained the broadest
acceptance due to its availability and the fact that gasoline containing MTBE
can be transported through pipelines, which is a significant competitive
advantage over ethanol. Substantially all of the MTBE produced in the United
States is used in the production of oxygenated and reformulated gasoline. Demand
for MTBE is therefore dependent on the demand for oxygenated and reformulated
gasoline, which accounts for approximately 42% of the gasoline consumed in the
United States. Gasoline usage is affected by many factors, including its price,
which is dependent on the price of crude oil, seasonal demand patterns and the
economy. Future MTBE demand is also highly dependent on environmental regulation
and federal and state legislation.

     We compete with MTBE producers in the United States including refiners who
produce MTBE for internal consumption in the blending of oxygenated gasoline.
Competitive factors affecting the MTBE market include the cost of feedstocks and
other productions costs, the availability of long term contracts for feedstocks
and end products, the availability of commercial capacity, the availability and
cost of shipping and federal and state regulations regarding the oxygen content
of gasoline.

Restrictions on MTBE Production or Use

     The presence of MTBE in some water supplies in California and other states
due to gasoline leakage from underground and aboveground storage tanks,
automobile and tanker truck accidents, pipelines and certain other sources has
led to public concern that MTBE has contaminated drinking water supplies, and
thereby resulted in a possible health risk. As a result, in 1999, the Governor
of California ordered the ban of the use of MTBE as a gasoline component by the
end of 2002. The Governor of California recently extended the deadline for the
ban of the use of MTBE in California to December 31, 2003, based on concerns
about the availability and cost of alternatives to MTBE. Heightened public
awareness has also resulted in other states and the U.S. Environmental
Protection Agency ("EPA") either passing or proposing restrictions on, or
banning the use of, MTBE. If MTBE were to be restricted or banned in Texas or
throughout the United States, we could modify the MTBE Plant to produce other
products by a conversion of the MTBE Plant. However, modifying our existing MTBE
Plant to produce other gasoline blendstocks such as alkylates could require a
substantial capital investment, and we cannot provide any assurance that we
will have the resources available to effect such a conversion or that such
conversion would be economically viable. For further details, see "Environmental
Matters" below.

Mont Belvieu Facility

     In connection with our acquisition of the processing facility at Morgan's
Point described above, we also purchased natural gas storage and transportation
facilities located at Mont Belvieu, Texas. This area is considered to be the hub
of the natural gas liquids industry in the United States because its geologic
structure is conducive to the operation of natural gas liquids storage
facilities and because of its close proximity to numerous refineries and
petrochemical plants. While the area is filled with potential buyers, it is also
filled with many of our principal competitors, such as Enterprise and Lyondell,
each of which has substantial storage facilities in or near Mont Belvieu. The
presence of competitors means that our product, pricing and profit margins are
subject to significant competition.


                                       11
<PAGE>


     We use these storage facilities primarily to store feedstocks and natural
gas liquids. Although we do use some of our storage capacity to store our own
feedstocks and natural gas liquids, we agreed to sell most of our storage
capacity at the Mont Belvieu Facility to EGLI, which had an immediate and
long-term need for storage space as a result of its operations. As part of its
bankruptcy proceedings, EGLI rejected its Storage Agreement with us. For further
detail concerning our agreements with EGLI, see "Toll Conversion and Storage
Agreements" below.

     Our costs of providing storage space are largely fixed, with the only major
exception being the cost of power. Therefore, for the most part, our prices and
profit margins are affected primarily by fluctuations in commodity prices.
Specifically, when the market is said to be backwardated, that is, when the
price of natural gas liquids or the feedstocks used to make them is expected to
be lower in future months than it is in the current month, then the demand for
storage space at our storage facilities, and the prices that we can charge, will
fall, because suppliers would rather sell natural gas liquids and their
associated feedstocks at a premium price. Conversely, when the market is said to
be in contango, that is, when the price in the current month is believed to be
lower than it will be in the future, then we may be able to charge higher rates
for storage capacity because suppliers will be more willing to store natural gas
liquids and feedstocks and wait until more favorable pricing terms can be
obtained in the future.

Toll Conversion and Storage Agreements

     Concurrently with acquiring the liquids processing, storage and
transportation assets described above, we entered into a ten-year Toll
Conversion Agreement pursuant to which we were to receive fees for converting
feedstocks, consisting of various types of natural gas liquids, into liquid
petroleum products, and a ten-year Storage Agreement for the use of a
significant portion of our Mont Belvieu Facility and pipeline grid system and
the provision of certain related transportation, handling, maintenance and other
operational services, both agreements being with EGLI. Under both agreements,
EGLI retained all existing third party commodity, transportation and storage
contracts associated with these facilities.

     As a result of these contractual arrangements with EGLI, we expected that
the future performance of the acquired assets would differ substantially from
the historical financial and operating performance of the assets. On December 3,
2001, EGLI was included in Enron's Chapter 11 filings. As a result of EGLI's
non-performance under these agreements, we recorded a $29.1 million impairment
in the fourth quarter of 2001, representing our total remaining investment in
the agreements. See Note 7 to our Consolidated Financial Statements for
information regarding this impairment charge.

     Under the Toll Conversion Agreement, we agreed to convert feedstocks to
MTBE and other liquid petroleum products as designated by EGLI on a quarterly
basis. EGLI agreed to use commercially reasonable efforts to deliver feedstocks
to us in specified quantities corresponding to the products EGLI designated that
we produce in a quarter, agreed to accept delivery of products that we produce
that meet quality specifications for the products designated by EGLI and further
agreed to hold us harmless with respect to certain risks, including the risk
that future laws or regulations would prohibit the production or use of MTBE in
the United States. We were to receive a fixed fee for a minimum quantity of MTBE
or its equivalent produced, as specified in the agreement, which would escalate
on an annual basis commencing on January 1, 2003. For each gallon of MTBE or its
equivalent produced in excess of such minimum quantity, EGLI was to pay a
separate fee based on a formula that took into account market prices for MTBE
and specified feedstocks. This Toll Conversion Agreement was designed to shift
to EGLI our exposure to price fluctuations in the commodities markets in both
the short and long term, while providing us with a constant and predictable
stream of income.

     Under the Storage Agreement, EGLI agreed to purchase fixed throughput and
storage capacity on a take-or-pay basis for ten years. Under the Storage
Agreement, we were to receive a fixed storage and throughput fee, which
escalated throughout the term of the agreement, based on firm storage
quantities. We were also to receive a fee for any storage or throughput capacity
used by EGLI above the fixed amounts.


                                       12
<PAGE>


     Following EGLI's non-performance and bankruptcy, we took over commercial
operation of the MTBE Plant. We could not, however, enter into any long-term
contracts until the Toll Conversion Agreement was rejected. In addition, until
the Storage Agreement was rejected, we could not enter into any third party
storage contracts. As a result, the storage assets have generated minimal
revenue.

     On April 2, 2002, the Bankruptcy Court entered a stipulation and agreed
order rejecting the Toll Conversion and Storage Agreements (the "Stipulation"),
which order became final and non-appealable on April 12, 2002. Rejection of our
Storage Agreement with EGLI resulted in the loss of the buyer of the fixed
throughput and storage capacity at the Mont Belvieu Facility. However, the
rejection allows us to directly seek new customers and pursue long-term
contracts for the Mont Belvieu Facility to replace the long-term and continuous
stream of revenue we expected under the Storage Agreement with EGLI. Although we
expect to use some of our storage capacity in our operations and marketing
activities related to the MTBE Plant, we expect to market the majority of the
storage capacity to third parties, preferably those with a presence in Mont
Belvieu, Texas.

     As a result of the rejection of our Toll Conversion Agreement by EGLI, our
operation of the MTBE Plant has been converted to a merchant operation, which
means that we take title to feedstocks and sell products directly to third
parties, as opposed to providing tolling services to EGLI. This means that we
bear the risk of physical loss associated with storing these feedstocks and
products. We are also exposed to fluctuations in the commodities market. We are
subject to a significant increase in commodity price risk for feedstocks and
marketing and commodity price risk associated with owning and selling MTBE and
other end products, which may vary based on factors beyond our control. Due to
this commodity risk, our cash flow over the expected life of this asset will
likely vary significantly from levels previously anticipated.

     Also as a result of the rejection of these agreements, we filed a claim for
rejection damages in the Bankruptcy Court. For further detail regarding our
claims against Enron and its subsidiaries, see Item 7. "Management's Discussion
and Analysis of Financial Condition and Results of Operations - Impact of the
Bankruptcy of Enron and Certain of its Subsidiaries, and Related Events - Claims
Against Enron's Bankruptcy Estate." We are continuing to operate the assets and
are examining long-term options for their operation, which could include
long-term tolling arrangements with third parties or a sale of the facilities.

WEST COAST OPERATIONS

     Prior to June 30, 2001 we were engaged in crude oil gathering and
marketing, natural gas liquids and refined products marketing on the West Coast.
Effective June 30, 2001, we sold our crude oil gathering and marketing
operations on the West Coast to Pacific Marketing and Transportation LLC for
$14.3 million. We could be required to repay up to $1.5 million of the sale
price, subject to a two-year look-back provision regarding average operating
results during the period July 1, 2001 through June 30, 2003. Such amount is
reflected in Other Long Term Liabilities in the Consolidated Balance Sheet at
December 31, 2001.

     Our remaining West Coast assets include a gas processing plant with 20
million cubic feet per day of gas processing capacity, a fractionation plant
with 8,000 barrels per day of fractionation capacity and five million gallons of
refrigerated propane storage along with related truck and rail distribution
facilities. In addition, our West Coast Operations include a refined petroleum
products marketing business. This business specializes in marketing distillate
and gasoline at terminals.

RISK MANAGEMENT/DERIVATIVES

     We attempt to minimize our exposure to commodity prices. Generally, as we
purchase lease crude oil at prevailing market prices, we enter into
corresponding sales transactions involving physical deliveries of crude oil to
third party users, such as refiners or other trade partners, or a sale of
futures contracts on the NYMEX.


                                       13
<PAGE>


This process gives us the opportunity to profit on the transaction at the time
of purchase and to minimize our exposure to commodity price fluctuations.

     Price risk management strategies, including those involving price hedges
using NYMEX futures contracts, are very important in maintaining or increasing
our gross margins. Such hedging techniques require significant resources
dedicated to the management of futures positions and physical inventories.
Another important element of the hedging techniques is the accurate estimation
of lease crude oil volumes that will actually be purchased when we pick them up
from the producers. We effect transactions both in the futures and physical
markets in order to deliver the crude oil to its highest value location or
otherwise to maximize the value of the crude oil we control. Throughout the
process, we seek to maintain a substantially balanced risk position at all
times. We do have certain risks that cannot be completely hedged such as basis
risks (the risk that price relationships between delivery points, grades of
crude oil or delivery periods will change) and the risk that transportation
costs will change, and from time to time we enter into transactions providing
for purchases and sales in future periods in which the volumes of crude oil are
balanced, but where either the purchase or sale prices are not fixed at the time
at which the transactions are consummated. In such cases, we are subject to the
risk that prices may change or that price changes will not occur as anticipated.

     As a result of the rejection of our Toll Conversion and Storage Agreements,
as discussed above in "Liquids Operations - Toll Conversion and Storage
Agreements," we are also now subject to a significant increase in commodity
price risk associated with the MTBE Plant. Our ability to maintain or increase
gross profit and to protect ourselves from adverse price changes is dependent on
the success of our marketing and price risk management strategies. We can make
no assurance that our marketing and price risk management strategies will be
successful in protecting us from risks or in maintaining our gross margins at
desirable levels.

CREDIT

     Credit review and analysis are integral to our marketing activities.
Payment for all or substantially all of the monthly lease crude oil gathered is,
in many instances, made to the operator of the lease. The operator, in turn, is
responsible for the correct payment and distribution of such production proceeds
to the proper parties. In these situations, we determine whether the operator
has sufficient financial resources to make such payments and distributions and
to indemnify and defend us in the event any third party should bring a protest,
action or complaint in connection with the ultimate distribution of production
proceeds by the operator.

     In our marketing activities, we use a proprietary credit rating system to
determine the amount, if any, of the line of credit to be extended to any given
customer. Since typical sales transactions can involve tens of thousands of
barrels of crude oil or other products, the risk of non-payment and
non-performance by customers is a major consideration in our business. We,
however, can make no assurances that our credit system, policies and procedures
will be successful in preventing a significant loss from customer default.

     The amount and profitability of our business is also dependent on our own
credit standing and the willingness of third parties to engage in transactions
with us without requiring us to furnish third party credit support. As discussed
in Item 7. "Management's Discussion and Analysis of Financial Condition and
Results of Operations - Impact of the Bankruptcy of Enron and Certain of Its
Subsidiaries, and Related Events" and in this section, "Business - Impact of
Enron Bankruptcy on Our Business," as a result of the Enron bankruptcy and in
part as a result of the recent increase in crude oil prices, our trade creditors
have been less willing than before the Enron bankruptcy to extend credit to us
on an unsecured basis, and the amount of letters of credit we have been required
to post for our North American Crude Oil - East of Rockies business segment
increased from approximately $150 million in September 2001 to $196 million in
December 2001, and to $243 million in March 2002.


                                       14
<PAGE>


ENVIRONMENTAL MATTERS

     We are subject to federal, state and local laws and regulations governing
the discharge of materials into the environment or otherwise relating to
environmental protection. At the federal level, such laws include, among others,
the CAA, the Clean Water Act, the Oil Pollution Act, the Federal Resources
Conservation and Recovery Act ("RCRA"), the Comprehensive Environmental
Response, Compensation and Liability Act ("CERCLA"), and the National
Environmental Policy Act ("NEPA"), as each may be amended from time to time.
Failure to comply with these laws and regulations may result in the assessment
of administrative, civil, and criminal penalties or the imposition of injunctive
relief. Moreover, compliance with such laws and regulations in the future could
prove to be costly, and there can be no assurance that we will not incur such
costs in material amounts. Environmental laws and regulations have changed
substantially and rapidly over the last 20 years, and we anticipate that there
will be continuing changes. The clear trend in environmental regulation is to
place more restrictions and limitations on activities that may impact the
environment, such as emissions of pollutants, generation and disposal of wastes
and use and handling of chemical substances. Increasingly strict environmental
restrictions and limitations have resulted in increased operating costs for us
and other businesses throughout the United States, and 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.

     The CAA controls, among other things, the emission of volatile organic
compounds, nitrogen oxides, and all other ozone-producing compounds in order to
protect national ambient air quality in accordance with standards established
for ozone and other pollutants. Such emissions may occur from the handling or
storage of petroleum or natural gas liquids. The sources of emissions that are
subject to control and the types of controls required are a matter of individual
state air quality control implementation plans that set forth emission
limitations. Both federal and state laws impose substantial administrative,
civil and even criminal penalties for violation of applicable requirements. As
part of our regular overall evaluation of current operations, we assess the need
for new, or amendment of existing, air permits at our properties. We believe
that our overall operations are in substantial compliance with applicable air
quality requirements.

     We generate wastes, including hazardous wastes, that are subject to the
RCRA and comparable state statutes. The EPA and various state agencies have
limited the approved methods of disposal for certain hazardous and nonhazardous
wastes. Furthermore, certain oil and gas exploration and production wastes
handled by us that are currently exempt from treatment as "hazardous wastes" may
in the future be designated as "hazardous wastes" and therefore be subject to
more rigorous and costly operating and disposal requirements.

     The CERCLA, also known as the "Superfund" law, imposes liability, without
regard to fault or the legality of the original conduct, on certain classes of
persons that are considered to have contributed to the release of a "hazardous
substance" into the environment. These persons include the owner or operator of
the disposal site or sites where the release occurred and companies that
transported or disposed or arranged for the transport or disposal of the
hazardous substances that have been released at the site. Persons who are or
were responsible for releases of hazardous substances under CERCLA may be
subject to joint and several liability for the costs of cleaning up the
hazardous substances that have been released into the environment and for
damages to natural resources, and it is not uncommon for neighboring landowners
and other third parties to file claims for personal injury and property damage
allegedly caused by the hazardous substances released into the environment. In
the ordinary course of our operations, substances may be generated that fall
within the definition of "hazardous substances." Our operations are also
impacted by regulations governing the disposal of naturally occurring
radioactive materials ("NORMs"). Although we have utilized operating and
disposal practices that were standard in the industry at the time, hydrocarbons
or other wastes may have been disposed


                                       15
<PAGE>


of or released on or under the properties owned or leased by us or under other
locations where such wastes have been taken for disposal. Moreover, we may own
or operate properties that in the past were operated by third parties whose
operations were not under our control. Those properties and any wastes that may
have been disposed or released on them may be subject to CERCLA, RCRA and
analogous state laws, and we potentially could be required to remediate such
properties.

     The Clean Water Act, as amended by the Oil Pollution Act of 1990 ("OPA"),
controls, among other things, the discharge of oil and other petroleum products
into waters of the United States. The Clean Water Act provides penalties for any
unauthorized discharges of pollutants (including petroleum products) into waters
of the United States and imposes substantial potential liability for the costs
of responding to an unauthorized discharge of pollutants, such as an oil spill.
State laws governing the control of water pollution also provide varying
administrative, civil and criminal penalties and liabilities in the event of a
release of petroleum or other related products into surface waters or onto the
ground. Federal and state permits for such water discharges may be required.

     OPA also imposes a variety of requirements on "responsible parties" for oil
and gas facilities related to the prevention of oil spills and liability for
damages resulting from such spills in waters of the United States. The term
"responsible parties" includes the owner or operator of an oil or gas facility
that could be the source of an oil spill affecting jurisdictional waters of the
United States. The term "waters of the United States" has been broadly defined
to include inland water bodies, such as wetlands, rivers, and creeks, as well
as coastal waters. OPA assigns liability to each responsible party for oil spill
removal costs and a variety of public and private damages from oil spills. OPA
establishes a liability limit for onshore facilities of up to $350 million while
the limit for offshore facilities is all removal costs plus up to $75 million in
other damages. Responsible parties, however, cannot take advantage of liability
limits if the spill is caused by gross negligence or willful misconduct, if the
spill resulted from violation of a federal safety, construction or operating
regulation, or if a responsible party fails to report a spill or to cooperate
fully in the cleanup. Few defenses exist to the liability for oil spills imposed
by OPA. OPA also imposes other requirements on facility operators, such as the
preparation of an oil spill response plan, and a demonstration of the operator's
ability to pay for environmental cleanup and restoration costs likely to be
incurred in connection with an oil spill. Failure to comply with these OPA
requirements or inadequate cooperation in a spill event may subject a
responsible party to administrative, civil or criminal actions. While we believe
that we are in substantial compliance with the requirements of OPA, we cannot
predict future events which would have a material impact on our financial
condition or our results of operations.

     NEPA may apply to certain extensions or additions to a pipeline system.
Under NEPA, if any project is to be undertaken which would significantly affect
the quality of the environment and require a permit or approval from a federal
agency, the federal agency may require preparation of a detailed environmental
impact study. The issuance by a federal agency of a permit or approval to
construct or extend a pipeline system may constitute a major federal action
under NEPA. The effect of NEPA may be to delay or prevent construction of new
facilities or to alter their location, design or method of construction. Similar
state laws may also be applicable to us.

     Enron received a request for information from the EPA under Section 308 of
the Clean Water Act requesting information regarding certain discharges and
releases from oil pipelines owned or operated by Enron and its affiliated
companies for the time period July 1, 1998 to July 11, 2001. Because we are the
only Enron affiliated entity with domestic crude oil pipelines operated by
Enron, Enron responded for itself and on behalf of us to the EPA's request on
January 29, 2002. At this time, we are not able to predict the outcome of the
response made to the EPA's Section 308 request.

     The presence of MTBE in some water supplies in California and other states
due to gasoline leakage from underground and aboveground storage tanks,
automobile and tanker truck accidents, pipelines and certain other sources
including operation of recreational watercraft on surface waters has led to
public concern that


                                       16
<PAGE>


MTBE has contaminated drinking water supplies, and thereby resulted in a
possible health risk. As a result, in 1999, the Governor of California ordered
the ban of the use of MTBE as a gasoline component by the end of 2002. The
Governor of California recently extended the deadline for the ban of the use of
MTBE in California to December 31, 2003, based on concerns about the
availability and cost of alternatives to MTBE.

     Heightened awareness of possible MTBE contamination has resulted in the
filing of numerous lawsuits, generally pursuing products liability theories, in
numerous jurisdictions including Texas. Defendants in these suits, including
MTBE producers, oil and gas companies, fuel distributors and others, have
claimed generally that federal and state laws permitted them to use MTBE to meet
federal clean air standards. Some defendants have contended that products
liability claims are pre-empted by the CAA amendments passed in 1999. This
defense has been recognized in at least two courts. One such case, which reached
trial in a California Superior Court, resulted in a jury verdict against
numerous defendants for contaminating ground water near Lake Tahoe, California.
As of May 7, 2002, this case was still pending with no determination of
penalties. While we believe we have manufactured and sold MTBE in compliance
with applicable laws permitting our activities, and we have not been included in
any of these lawsuits, it is possible that we could be adversely affected by
such a lawsuit in the future.

     Heightened public awareness has also resulted in other states and the EPA
either passing or proposing restrictions on, or banning the use of, MTBE. As of
June 2001, 12 states had enacted laws to phase out or limit MTBE. In July 2001,
Illinois enacted legislation banning MTBE as of July 2004. Rhode Island plans to
eliminate MTBE by July 2003. The New England Governors' Conference resolved in
August 2001 to engage in a coordinated effort to amend the CAA to lift the
oxygen mandate for reformulated gasoline ("RFG") or to press the EPA to allow
these states to opt out of the RFG program's oxygen requirements. Currently,
Texas, the only state in which we produce MTBE, has not banned MTBE. No
assurances, however, can be made that Texas will not enact such legislation. The
July 1999 report of the EPA's "Blue Ribbon Panel on Oxygenates in Gasoline"
recommended the reduced use of MTBE in the United States. In 2000, the EPA
announced its intent to seek legislative changes to give the EPA the authority
to ban the use of MTBE over a three-year period, and as of March 2000, the EPA
also sought to ban MTBE using its rulemaking authority under the Toxic
Substances Control Act. Both the EPA and state regulatory agencies have also
established remediation and drinking water standards for MTBE that require
treatment for water with high concentrations of MTBE (the EPA drinking water
standard is 20 to 40 parts per billion).

     The U.S. House of Representatives and the U.S. Senate introduced
legislation in February 2001 with the goal of eliminating the use of MTBE in
gasoline three years from the date of enactment. Provisions are included within
the proposed Energy Policy Act of 2002 that would ban the use of MTBE four years
post enactment. However, the proposed Energy Policy Act of 2002 also includes
provisions that would provide monetary assistance to domestic MTBE producers to
be used to defray the costs associated with the transition of current MTBE
production facilities into facilities producing MTBE substitutes. The Bush
Administration has made statements in favor of conversion for MTBE substitutes
to the use of ethanol as an alternative to MTBE. If MTBE were to be restricted
or banned in Texas or throughout the United States, we could modify the MTBE
Plant to produce other products. We believe that modifying our existing MTBE
Plant to produce other gasoline blendstocks such as alkylates could require a
substantial capital investment. We cannot be certain that we would have the
resources available to effect such a conversion or that such conversion would be
economically viable. Further, we cannot predict whether the proposed Energy
Policy Act of 2002 or other similar legislation may be passed or whether the
federal government will take steps to reverse California's ban on the use of
MTBE as a gasoline component, or if the federal government will provide monetary
assistance for conversion. If the proposed federal legislation is enacted, or
the ban in California becomes effective, or Texas bans the use of MTBE, we would
expect such ban to materially reduce MTBE demand, which would have a material
adverse effect on our financial results.


                                       17
<PAGE>


     We may experience future releases of crude oil, MTBE or other substances
into the environment or discover releases that were previously unidentified.
While an inspection program is maintained on our pipelines to prevent and detect
such releases, and operational safeguards and contingency plans are in place for
the operation of our processing facilities, damages and liabilities incurred due
to any future environmental releases could affect our business. We believe that
our operations and facilities are in substantial compliance with applicable
environmental laws and regulations and that there are no outstanding potential
liabilities or claims relating to safety and environmental matters the
resolution of which, individually or in the aggregate, would have a materially
adverse effect on our financial position or results of operations. Our
environmental expenditures include amounts spent on permitting, compliance and
response plans, monitoring and spill cleanup and other remediation costs. In
addition, we could be required to spend substantial sums to ensure the integrity
of and upgrade our pipeline systems, and in some cases, we may take pipelines
out of service if we believe the cost of upgrades will exceed the value of the
pipeline in our business.

     We cannot give any assurance as to the ultimate amount or timing of future
expenditures for environmental remediation or compliance, and actual future
expenditures may be different from the amounts currently anticipated. In the
event of future increases in costs, we may be unable to pass on those increases
to our customers.

REGULATION

     We are subject to a variety of federal and state regulations relating to
our interstate and intrastate pipeline transportation and safety activities,
motor carrier activities, and commodities trading business, the most significant
of which are discussed below.

Pipeline Regulation

     Interstate Regulation Generally. Our interstate common carrier pipeline
operations are subject to rate regulation by the FERC under the provisions of
the Interstate Commerce Act ("ICA"). These operations include our Hobbs Pipeline
in New Mexico and Texas, our crude oil system in Mississippi and Alabama ("the
Mississippi-Alabama Pipeline"), our crude oil systems acquired from CITGO
Pipeline Company ("CITGO Pipeline"), portions of our crude oil systems acquired
from Koch Pipeline Company, L.P. ("Koch Pipelines") and crude oil systems
acquired from Texas-New Mexico Pipe Line Company ("Texas-New Mexico Pipe
Lines"). 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 pipeline as well as the rules and
regulations governing these services. The ICA also requires, among other things,
that petroleum pipeline rates be just and reasonable and non-discriminatory. The
ICA permits interested parties to challenge proposed new 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 the 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 collected during the
pendency of the investigation in excess of those that would have been collected
under the prior tariff. In addition, the FERC, upon complaint or on its own
motion and after investigation, may order a carrier to change its rate
prospectively. Upon an appropriate showing, a shipper may obtain reparations for
damages sustained for a period of up to two years prior to the filing of a
complaint.

     Energy Policy Act of 1992 and Subsequent Developments. In October 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 vast majority of our FERC pipeline rates are grandfathered
under the Energy Policy Act, and therefore are deemed just and reasonable. The
Energy Policy Act provides that the FERC may change the grandfathered rates upon
complaints only under the following limited circumstances:


                                       18
<PAGE>


     o   a substantial change has occurred since enactment in either the
         economic circumstances or the nature of the services which were the
         basis for the rate;

     o   the complainant was contractually barred from challenging the rate
         prior to enactment of the Energy Policy Act and filed the complaint
         within 30 days of the expiration of the contractual bar; or

     o   a provision of the tariff is unduly discriminatory or preferential.

     The Energy Policy Act further required the FERC to issue rules establishing
a simplified and generally applicable ratemaking methodology for interstate
petroleum pipelines and to streamline procedures in petroleum pipeline
proceedings. On October 22, 1993, the FERC responded to this mandate by issuing
several orders, including Order No. 561, which adopts a new indexing rate
methodology for interstate petroleum pipelines. Under the new regulations,
effective January 1, 1995, petroleum pipelines are able to change their rates
within prescribed ceiling levels that are tied to changes in the Producer Price
Index for Finished Goods, minus one percent. Rate increases made pursuant to the
indexing methodology are subject to protest, 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. If the indexing
methodology results in a reduced ceiling level that is lower than a pipeline's
filed rate, Order No. 561 requires the pipeline to reduce its rate to comply
with the lower ceiling. The new indexing methodology is applicable to any
existing rate, whether grandfathered or whether established after enactment of
the Energy Policy Act.

     The FERC, however, has retained cost-based ratemaking, market-based rates
and settlements as alternatives to the indexing approach. A pipeline can follow
a cost-based approach when it can demonstrate that there is a substantial
divergence between the actual costs experienced by the carrier and the rates
resulting from application of the index. Under FERC's cost-based methodology,
crude oil pipeline rates are permitted to generate operating revenues, based on
projected volumes, not greater than the total of operating expenses,
depreciation and amortization, federal and state income taxes and an overall
allowed rate of return on the pipeline's rate base. In addition, a pipeline can
charge market-based rates if it first establishes that it lacks significant
market power in a particular relevant market, and a pipeline can establish rates
pursuant to a settlement if agreed upon by all current shippers. Initial rates
for new services can be established through a cost-based filing or through an
uncontested agreement between the pipeline and at least one shipper not
affiliated with the pipeline.

     Since July of 1995, we have annually amended our tariffs on all of our
regulated pipelines as provided by FERC regulations. Although no assurance can
be given that the tariffs charged by us will ultimately be upheld if challenged,
we believe that the tariffs now in effect for all of our pipelines are within
the maximum rates allowed under the current FERC guidelines.

     In addition to the regulatory considerations noted above, it is expected
that the tariff rates of the Hobbs, Mississippi-Alabama, CITGO, Koch and
Texas-New Mexico Pipe Line will continue to be constrained by competitive and
other market factors.

     FERC Form 6 Annual Reporting. The FERC requires annual reporting from oil
pipelines through the submission of FERC Form 6, "Annual Report of Oil Pipeline
Companies." The FERC Form 6 is designed to provide the FERC with the financial,
operational and ratemaking information it needs to regulate and monitor the oil
pipeline industry. FERC advised us, in a letter dated January 9, 2002, that FERC
began an industry-wide audit with respect to the annual reporting requirements
of FERC Form 6 in December 2001, and that we had been selected for the audit.
The audit covers the period from January 1, 2000 through December 31, 2001. FERC
staff has subsequently visited our Houston office to review relevant
documentation and has made


                                       19
<PAGE>


numerous data requests to which we have provided various data and responses. The
audit remains ongoing, and it is uncertain at this point what, if any, actions
FERC may propose upon completion of the audit. We timely filed our FERC Form 6
for the year 2001 on March 29, 2002.

     Intrastate Regulation. Some of our pipeline operations are subject to
regulation by the respective agency of the state in which the pipeline is
located. The applicable state statutes require, among other things, that
pipeline rates be non-discriminatory and provide a fair return on the aggregate
value of the pipeline property used to render services. State commissions have
generally not been aggressive in regulating common carrier pipelines and have
generally not investigated the rates or practices of petroleum pipelines in the
absence of shipper complaints. Complaints to state agencies have been infrequent
and are usually resolved informally. Although no assurance can be given that our
intrastate rates would ultimately be upheld if challenged, we believe that,
given this history, the tariffs now in effect are more likely subject to
informal reviews rather than formal challenges.

     Petroleum Pipeline Safety Legislation and Regulation. Our petroleum
pipelines are subject to regulation by the United States Department of
Transportation ("DOT") under the Accountable Pipeline and Safety Partnership Act
of 1996, sometimes referred to as the Hazardous Liquid Pipeline Safety Act
("HLPSA"), and comparable state statutes relating to the design, installation,
testing, construction, operation, replacement, and management of our pipeline
facilities. The HLPSA covers petroleum and petroleum products and requires any
entity that owns or operates pipeline facilities to comply with such
regulations, to permit access to and copying of records, and to prepare certain
reports and provide information as required by the Secretary of the DOT.
Comparable regulation exists in some states in which we conduct intrastate
common carrier or private pipeline operations.

     We are subject to the Office of Pipeline Safety ("OPS") regulation
requiring qualification of pipeline personnel. The regulation requires pipeline
operators to develop and maintain a written qualification program for
individuals performing covered tasks on pipeline facilities. The intent of this
regulation is to ensure a qualified work force and to reduce the probability and
consequence of incidents caused by human error. The regulation establishes
qualification requirements for individuals performing covered tasks, and amends
certain training requirements in existing regulations. We believe we are in
compliance with these requirements through the applicable Enron written
qualification program.

     Pipeline safety issues are currently receiving significant attention in
various political and administrative arenas at both the state and federal
levels. For example, recent federal rule changes require operators of pipelines
of greater than 500 miles to: (i) develop and maintain a written qualification
program for individuals performing covered tasks on pipeline facilities, and
(ii) establish pipeline integrity management programs. In particular, during
2000, the DOT adopted the OPS Integrity Management regulations requiring
operators of interstate pipelines to develop and follow an integrity management
program ("IMP") that provides for continual assessment of the integrity of all
pipeline segments that could affect so-called high consequence areas ("HCA"),
including high population areas, drinking water areas and ecological resource
areas that are unusually sensitive to environmental damage from a pipeline
release, and commercially navigable waterways. HCAs related to our pipelines
were initially identified as all areas where jurisdictional lines are located.
We completed our IMP before the deadline of March 31, 2002. Our IMP has now been
reviewed by DOT personnel on two occasions, and we anticipate that we will
receive a Notice of Amendment for DOT-requested changes to our IMP sometime in
the near future.

     The OPS Integrity Management regulations also require us to evaluate
pipeline conditions by means of periodic internal inspection, pressure testing,
or other equally effective assessment means and to correct identified anomalies.
If, as a result of our evaluation process, we determine that there is a need to
provide further protection to the HCA, then we will be required to implement
additional prevention and mitigation risk control measures for our pipelines,
including enhanced damage prevention programs, corrosion control


                                       20
<PAGE>


program improvements, leak detection system enhancements, installation of
emergency flow restricting devices, and emergency preparedness improvements. The
regulations also require us to evaluate and, as necessary, improve our
management and analysis processes for integrating available integrity-related
data relating to our pipeline segments and to remediate potential problems found
as a result of the required assessment and evaluation process. The regulations
require that initial HCA baseline integrity assessments are conducted within
seven years, with all subsequent assessments conducted on a five-year cycle. We
will evaluate each pipeline segment's integrity by analyzing available
information and develop a range of potential impacts resulting from a release to
a HCA.

     In connection with extensive asset purchases in 1998 and 1999, we
instituted a pipeline integrity management program in 1999. This program was
expanded in December of 2001 with a pipeline integrity assurance program to
comply with certain regulatory and legislative changes. Under this program, the
integrity of a pipeline is evaluated to avoid operating a pipeline that poses
significant risk of crude oil spills. Our written EOTT Pipeline Integrity
Program, which was intended to comply with the new Office of Pipeline Safety
Integrity Management regulations, was formally implemented in January 2002.
Anticipated operating expenses and capital expenditures to comply with that
program are budgeted annually; however, actual future expenditures may be
different from the amounts currently anticipated.

     Although we believe that our pipeline operations are in substantial
compliance with applicable HLPSA requirements, these developments reflect the
prospect of incurring significant expenses if additional safety requirements are
imposed that exceed our current pipeline control system capabilities.

     States are largely preempted by federal law from regulating pipeline
safety, but may assume responsibility for enforcing federal intrastate pipeline
regulations and inspection of intrastate pipelines. In practice, states vary
considerably in their authority and capacity to address pipeline safety.

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

Trucking Regulation

     Generally, we operate our fleet of trucks as a private carrier.
Additionally, we have engaged in contract carrier hauling of crude oil in
Louisiana and natural gas liquids in California for third parties. In Oklahoma,
Texas, Alabama and Mississippi, we haul salt water, crude oil and other fluids
for others as a common carrier. Although a private or common carrier that
transports property in interstate commerce is not required to obtain operating
authority from the Surface Transportation Board, the carrier is subject to
certain motor carrier safety regulations issued by the DOT. The trucking
regulations extend to driver operations, keeping of log books, truck manifest
preparations, safety placards on the trucks and trailer vehicles, drug and
alcohol testing, safety of operation and equipment, and many other aspects of
truck operations. We are also subject to OSHA regulations with respect to our
trucking operations. We believe that we are in substantial compliance with
applicable trucking regulation requirements.

     We provide contract and common carrier services pursuant to permits issued
by the various state regulatory agencies. Accordingly, we, as a common or
contract carrier, are also subject to certain safety regulations related to
service and operations. We believe that we are in substantial compliance with
applicable state common or contract carrier regulation requirements.


                                       21
<PAGE>


Commodities Regulation

     Our price risk management operations are subject to constraints imposed
under the Commodity Exchange Act (the "CEA"). Our futures and options contracts
that are traded on the NYMEX are subject to strict regulation by the Commodity
Futures Trading Commission (the "CFTC"). Although NYMEX futures contracts
include contracts on sweet crude oil, No. 2 heating oil and other refined
petroleum products, there are many products that we purchase and sell for which
no futures contracts are available, due in part to the strict regulatory scheme
for futures contracts. In addition, trading volumes and pricing bases of futures
contracts on some products are such that our ability to use them to hedge our
price risks may be limited.

Other Regulation

     We currently market refined products at the wholesale level in four states.
We market reformulated gasoline in California and oxygenated gasoline and
conventional gasoline in ozone non-attainment areas during control periods. We
are subject to extensive federal and state laws and regulations governing
product specifications, transfer documentation, record keeping and sampling.
Many of these laws and regulations impose significant financial penalties for
non-compliance. We believe that we are in substantial compliance with applicable
federal and state laws and regulations governing product specifications,
transfer documentation, record keeping and sampling.

INFORMATION REGARDING FORWARD-LOOKING INFORMATION

     The statements in this Annual Report on Form 10-K that are not historical
information are 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. Such forward-looking statements include, in particular, the discussion
under "Business - Environmental Matters," and "Impact of Enron's Bankruptcy on
Our Business," the discussion under Item 3. "Legal Proceedings," the discussion
in Item 7. "Management's Discussion and Analysis of Financial Condition and
Results of Operations - Impact of the Bankruptcy of Enron and Certain of Its
Subsidiaries, and Related Events," "Risk Factors," "Liquidity and Capital
Resources," "Other Matters," and "Environmental Matters." Any forward-looking
statements are not guarantees of future performance, and involve significant
risks and uncertainties, and actual results may vary materially from those in
the forward-looking statements as a result of various factors. Important factors
that could cause actual results to differ materially from those in the
forward-looking statements herein include, but are not limited to, the impact of
the bankruptcy proceedings of Enron and certain of its subsidiaries on our
contractual and other arrangements with those entities, the success of our
marketing activities, the success of our ongoing financing activities, our
success in obtaining additional lease crude oil barrels and maintaining existing
lease crude oil barrels, demand for various grades of crude oil and the
resulting changes in pricing relationships, ability to process and deliver
liquids products, ability to operate the MTBE Plant efficiently, developments
relating to possible acquisitions or business combination opportunities,
industry conditions, our ability to avoid environmental liabilities,
developments at FERC relating to pipeline tariff regulation, the successful
resolution of litigation, the success of our risk management activities and
conditions of the capital markets and equity markets during the periods covered
by the forward-looking statements. We believe that our expectations regarding
future events are based on reasonable assumptions. However, we can give no
assurance that these are all the factors that could cause actual results to vary
materially from the forward-looking statements or that our expectations
regarding future developments will prove to be correct.


                                       22
<PAGE>


ITEM 2.  PROPERTIES

PIPELINE AND TRANSPORTATION ASSETS AND PROPERTIES

     At year end 2001, we owned and operated approximately 8,000 miles of active
crude oil gathering and transmission pipelines. There are approximately 12.2
million barrels of active storage capacity associated with field tanks. By
state, the pipeline assets are as follows:

<Table>
<Caption>


                 COMMON CARRIER PIPELINES                                PROPRIETARY PIPELINES
                 ------------------------                                ---------------------
                                        MILES BY STATE                                          MILES BY STATE
                                        --------------                                          --------------
<S>                                     <C>                   <C>                               <C>
Alabama.....................                  43              Alabama.....................            38
Arkansas....................                  --              Arkansas....................             2
Colorado....................                  91              Colorado....................            --
Kansas......................               1,025              Kansas......................            --
Louisiana...................                 348              Louisiana...................           131
Mississippi.................                 306              Mississippi.................           267
Montana.....................                 146              Montana.....................            --
Nebraska....................                  63              Nebraska....................            --
New Mexico..................               1,158              New Mexico..................           157
North Dakota................                 435              North Dakota................            --
Oklahoma....................               1,422              Oklahoma....................            --
South Dakota................                  38              South Dakota................            --
Texas.......................               2,347              Texas.......................             4
                                           -----                                                     ---
           Total............               7,422                        Total.............           599
                                           =====                                                     ===
</Table>

     In addition, we own a gas processing plant in California, with 20 million
cubic feet per day of gas processing capacity; a fractionation plant with 8,000
barrels per day of fractionation capacity; five million gallons of refrigerated
propane storage; and related truck and rail distribution facilities. We operate
four active barge facilities in Louisiana, and one in Alabama. Approximately 2.2
million barrels of storage capacity are associated with these barge facilities.
We currently own one terminal in Alabama with approximately 125,000 barrels of
storage capacity.

LIQUIDS ASSETS

     Our MTBE Plant used in our Liquids Operations for the production of MTBE is
located in southeast Harris County within the city limits of Morgan's Point,
Texas, approximately 30 miles from Houston. The MTBE Plant consists of three
processing units and extensive product handling facilities. The MTBE Plant has a
design capacity of 15,300 barrels per day and a rated capacity of 16,500 barrels
per day of equivalent MTBE production. On average, the MTBE Plant produces
approximately 16,000 barrels per day. The product handling facilities include
on-site tank storage, a barge dock and railcar and truck loading/unloading
facilities as well as various interconnections to a number of pipelines. The
dock is located at the entrance of the Houston Ship Channel. The dock has the
necessary facilities to load MTBE, natural gasoline, normal butane, isobutane,
isobutane (low sulfur) and to unload methanol and normal butane. The dock can
provide a loading berth for barges up to 400 feet in length.

     The natural gas liquids storage and transportation facilities used in our
Liquids Operations include an underground storage facility and a liquids
pipeline grid system and related loading, unloading and transportation
facilities. The storage facility is located at Mont Belvieu, Texas,
approximately 30 miles east of Houston, Texas. The Mont Belvieu Facility
consists of ten active storage wells with a total capacity of 10 million
barrels, a surface brine pit with a total capacity of 1.1 million barrels and a
brine disposal well capable of disposing of up to 40,000 barrels of product per
day. The pipeline grid system and related facilities include an extensive
transportation and distribution system that allows us to transport natural gas
liquids and other products to and from the Mont Belvieu Facility and the MTBE
Plant by pipeline, ship or barge to the various refineries, petrochemical plants
and other buyers and suppliers of natural gas liquids that are located in and
throughout the area.


                                       23
<PAGE>


ITEM 3.  LEGAL PROCEEDINGS

     We are, in the ordinary course of business, a defendant in various
lawsuits, some of which are covered in whole or in part by insurance. We believe
that the ultimate resolution of our pending litigation, individually and in the
aggregate will not have a materially adverse impact on our financial position or
results of operations. Various legal actions have arisen in the ordinary course
of business, the most significant of which are discussed below.

     State of Texas Royalty Suit. We were served on November 9, 1995 with a
petition styled The State of Texas, et al. vs. Amerada Hess Corporation, et al.
The matter was filed in District Court in Lee County, Texas, Case No. 10,652,
and involves several major and independent oil companies and marketers as
defendants. The plaintiffs are attempting to put together a class action lawsuit
alleging that the defendants acted in concert to buy oil owned by members of the
plaintiff class in Lee County, Texas, and elsewhere in Texas, at "posted"
prices, which the plaintiffs allege were lower than true market prices. There is
not sufficient information in the petition to fully quantify the allegations set
forth in the petition, but we believe any such claims against us will prove to
be without merit. There has been no activity on this matter in several years.

     The State of Texas, et al. vs. Amerada Hess Corporation, et al., Cause No.
97-12040; In the 53rd Judicial District Court of Travis County, Texas ("Common
Purchaser Act Suit"). This case was filed on October 23, 1997 in Austin by the
Texas Attorney General's office and involves several major and independent oil
companies and marketers as defendants. We were served on November 18, 1997. The
petition states that the State of Texas brought this action in its sovereign
capacity to collect statutory penalties recoverable under the Texas Common
Purchaser Act, arising from defendants' alleged willful breach of statutory
duties owed to royalty, overriding royalty and working interest owners of crude
oil sold to defendants, as well as alleged breach of defendants' common law and
contractual duties. The plaintiffs also allege the defendants have engaged in
discriminatory pricing of crude oil. This case appears to be similar to the
State of Texas Royalty Suit filed by the State of Texas on November 9, 1995. We
recorded a $0.4 million litigation reserve related to this suit in 1998. We, and
several of the defendants, reached a settlement with the State of Texas in a
settlement agreement, dated August 5, 1999. The settlement was funded to an
escrow account in July 1999. Settlement amounts for each defendant were
confidential. The parties are considering options to have the case fully
dismissed. This settlement disposed of any claims the State of Texas may have in
the State of Texas Royalty Suit, discussed above, but did not dismiss that case.
Also, any severance tax claims the State of Texas may have were specifically
excluded from this settlement. However, no severance tax claims were asserted in
the petition filed by the plaintiffs. There has been no activity on this matter
for several years.

     McMahon Foundation and J. Tom Poyner vs. Amerada Hess Corporation, et al.
(Including EOTT Energy Operating Limited Partnership), Civil Action No.
H-96-1155; United States District Court, Southern District of Texas, Houston
Division ("Texas Federal Anti-Trust Suit"). This suit was filed on April 10,
1996 as a class action complaint for violation of the federal antitrust laws and
involves several major and independent oil companies and marketers as
defendants. The relevant area is the entire continental United States, except
for Alaska, New York, Ohio, Pennsylvania, West Virginia and the Wilmington Field
at Long Beach, California. The plaintiffs claim that there is a combination and
conspiracy among the defendant oil companies to fix, depress, stabilize and
maintain at artificially low levels the price paid for the first purchase of
lease production oil sold from leases in which the class members own interests.
This was allegedly accomplished by agreement of the defendants to routinely pay
for first purchases at posted prices rather than competitive market prices and
maintain them in a range below competitive market prices through an undisclosed
scheme of using posted prices in buy/sell transactions among themselves to
create the illusion that posted prices are genuine market prices. The plaintiffs
allege violations from October of 1986 forward. No money amounts were claimed.
See Summary below for current status.


                                       24
<PAGE>


     Randolph Energy, Inc., et al. vs. Amerada Hess Corporation, et al., Civil
Action No. 2:97CV273PG; In the United States District Court for the Southern
District of Mississippi, Jackson Division ("Mississippi Federal Anti-Trust
Suit"). We received a summons in this matter on August 18, 1997. The case was
filed on August 5, 1997 and is a class action complaint for alleged violation of
the federal antitrust laws, which involves several major and independent oil
companies and marketers as defendants. The plaintiffs claim that this litigation
arises out of a combination and conspiracy of the defendant oil companies to
fix, depress, stabilize and maintain at artificially low levels the prices paid
for the first purchase of lease production oil sold from leases in which the
class members own interests. The issues appear to be a duplication of the issues
in the Texas Federal Anti-Trust Suit previously discussed above. No money
amounts were claimed. This suit was dismissed with prejudice on March 29, 2002.
See Summary below for current status.

     Cameron Parish School Board, et al. vs. Texaco, Inc., et al.; Civil Action
No. C-98-111; In the United States District Court for the Western District of
Louisiana, Lake Charles Division ("Louisiana Federal Anti-Trust Suit"). This
case was originally filed as a state law claim in Louisiana. When the case was
removed to federal court, the anti-trust claims were added, similar to the
claims made in the Texas Federal Anti-Trust Suit and the Mississippi Federal
Anti-Trust Suit. The plaintiffs claim that this litigation arises out of a
combination and conspiracy of the defendant oil companies to fix, depress,
stabilize and maintain at artificially low levels the prices paid for the first
purchase of lease production oil sold from leases in which the class members own
interests. The issues appear to be a duplication of the issues in the Texas
Federal Anti-Trust Suit and the Mississippi Federal Anti-Trust Suit, both
previously discussed above. On October 22, 1998, the judge granted the
plaintiffs' motion to amend the petition and add additional defendants. We,
along with our General Partner, were added to the case as defendants at that
time. No money amounts were claimed. See Summary below for current status.

     Summary. The Texas Federal Anti-Trust Suit, the Mississippi Federal
Anti-Trust Suit, the Louisiana Federal Anti-Trust Suit and several other suits
to which we are not a party, were consolidated and transferred to the Southern
District of Texas by a transfer order, dated January 14, 1998. The Judicial
Panel on Multidistrict Litigation made this recommendation due to the similarity
of issues in the cases. We recorded a $1.0 million litigation reserve related to
these suits in 1998. We, along with our General Partner and a number of other
defendants, entered into a class-wide settlement, which was approved by the
court on April 7, 1999, with a final judgment entered on August 11, 1999.
Several appeals were subsequently filed and have now all been resolved. The
settlement was funded on November 27, 2001.

     Assessment for Crude Oil Production Tax from the Comptroller of Public
Accounts, State of Texas. We received a letter from the Comptroller's Office
dated October 9, 1998, assessing us for severance taxes the Comptroller's Office
alleges are due on a difference the Comptroller's Office believes to exist
between the market value of crude oil and the value reported on our crude oil
tax report for the period of September 1, 1994 through December 31, 1997. The
letter states that the action, based on a desk audit of our crude oil production
reports, is partly to preserve the statute of limitations where crude oil
severance tax may not have been paid on the true market price of the crude oil.
The letter further states that the Comptroller's position is similar to claims
made in several lawsuits, including the Texas Federal Anti-Trust Suit, in which
we are a defendant. The amount of the assessment, including penalty and
interest, is approximately $1.1 million. While the claim is still being
reviewed, we believe we should be without liability in this matter. There has
been no activity on this matter since early 1999.

     Export License with United States Department of Commerce. We have applied
for and maintained Export Licenses through the U.S. Department of Commerce
("DOC") since 1994. These licenses authorized us to export crude oil to Canada.
Each license provided an applicable license quantity and value of merchandise as
authorized by the DOC to be exported. The licenses generally covered either a
one or two-year period. In early 1999, as we were preparing a new license
application, we discovered we had exported more barrels and value than had been
authorized by the DOC under our current (and prior) license. Pursuant to Section
764.5 of the Export Administration Regulations, we filed a Voluntary Disclosure
with the DOC on February 5, 1999,


                                       25
<PAGE>


giving the DOC notice of these license overruns. The next formal stage of the
Voluntary Disclosure process will be for the DOC to issue a Charging Letter to
us regarding a proposed fine for the export license overruns. At this time, we
do not know the date when or for what amount the Charging Letter will be issued.
We are currently negotiating a monetary settlement with the DOC and we have
recorded an estimate of the potential settlement amount.

     John H. Roam, et al. vs. Texas-New Mexico Pipe Line Company and EOTT Energy
Pipeline Limited Partnership, Cause No. CV43296, In the District Court of
Midland County, Texas, 238th Judicial District ("Kniffen Estates Suit"). The
Kniffen Estates Suit was filed on March 2, 2001 by certain residents of the
Kniffen Estates, a residential subdivision located outside of Midland, Texas.
The allegations in the petition state that free crude oil products were
discovered in water wells in the Kniffen Estates area, on or about October 3,
2000. The plaintiffs claim the crude oil products are from a 1992 release from a
pipeline then owned by the Texas-New Mexico Pipe Line Company ("Tex-New Mex").
We purchased that pipeline from Tex-New Mex in 1999. The plaintiffs have alleged
Tex-New Mex was negligent, grossly negligent and malicious in failing to
accurately report and remediate the spill. With respect to us, the plaintiffs
are seeking damages arising from any contamination of the soil or groundwater
since we acquired the pipeline in question. No specific amount of money damages
was claimed, and it is not possible to determine any potential exposure to us at
this stage of the matter. In response to the Kniffen Estates Suit, we filed a
cross-claim against Tex-New Mex. In the cross-claim, we claim that, in relation
to the matters alleged by the plaintiffs, Tex-New Mex breached the purchase and
sale agreement between the parties dated May 1, 1999, by failing to disclose the
1992 release and by failing to undertake the defense and handling of the toxic
tort claims, fair market value claims, and remediation claims arising from the
release. Additionally, we are asserting claims of gross negligence, fraud and
specific performance. On April 5, 2002, we filed an amended cross-claim, which
alleges that Tex-New Mex defrauded us in Tex-New Mex's sale of pipeline systems
to us in 1999. The amended cross-claim also alleges that various practices
employed by Tex-New Mex in the operation of its pipelines constitute gross
negligence and willful misconduct and void our obligation to indemnify Tex-New
Mex for remediation of releases that occurred prior to May 1, 1999. Due to the
early stages of the proceedings, it is not possible at this time for us to
determine the possible outcome of this matter.

     Jimmie B. Cooper and Shryl S. Cooper v. Texas-New Mexico Pipe Line Company,
Inc., EOTT Energy Pipeline Limited Partnership and Amerada Hess Corporation,
Case No. CIV 01-1321 M/JHG, In the United States District Court for the District
of New Mexico. Plaintiffs in this lawsuit, filed on October 5, 2001, are surface
interest owners of certain property located in Lea County, New Mexico. The
plaintiffs allege that aquifers underlying their property and water wells
located on their property have been contaminated as a result of spills and leaks
from a pipeline running across their property that is or was owned by Tex-New
Mex and us. The plaintiffs also allege that oil and gas operations conducted by
Amerada Hess Corporation resulted in leaks or spills of pollutants that
ultimately contaminated the plaintiffs' aquifers and water wells. Our initial
investigation of this matter indicated that the alleged contamination of the
aquifers underlying the plaintiffs' property was not caused by leaks from the
pipeline now owned by us that traverses the plaintiffs' property. Although no
assurance can be made that we will successfully defend this lawsuit, we believe
that the ultimate resolution of this lawsuit will not have a materially adverse
impact on our financial position or results of operations.

     Richard D. Warden and Nancy J. Warden v. EOTT Energy Pipeline Limited
Partnership and EOTT Energy Corp., Case No. CIV-02-370 L, In the United States
District Court for the Western District of Oklahoma. In this lawsuit, filed on
February 28, 2002, the plaintiffs are landowners, seeking damages allegedly
arising from a release of crude oil from a pipeline owned by us. Although we
undertook extensive remediation efforts with respect to the crude oil release
that is the subject of this lawsuit, plaintiffs allege that we did not properly
remediate the crude oil release and claim causes of action for negligence, gross
negligence, unjust enrichment, and nuisance. Due to the early stages of the
proceeding it is not possible for us


                                       26
<PAGE>


to speculate on the possible outcome of this matter. We believe that the
ultimate resolution of this matter, however, will not have a materially adverse
impact on our financial position or results of operations.

     David A. Huettner, et al. v. EOTT Energy Partners, L.P., et al, Case No.
1:02 CV-917, In the United States District Court, Northern District of Ohio,
Eastern Division ("Securities Suit"). This lawsuit was filed on May 15, 2002 for
alleged violations of the Securities and Exchange Act of 1934 and common law
fraud. The suit was brought by three of our former unitholders who claim that
Enron, our General Partner, certain of the officers and directors of Enron and
our General Partner and our independent accountants were aware of material
misstatements or omissions of information within various press releases, SEC
filings and other public statements, and failed to correct the alleged material
misstatements or omissions. Plaintiffs maintain that they were misled by our
press releases, SEC filings and other public statements when purchasing our
common units and were financially damaged thereby. Due to the recent filing of
this lawsuit, we have been unable to thoroughly investigate the validity of the
Plaintiffs' allegations, but based on management's current knowledge, we believe
the allegations are without merit. We can provide no assurances regarding the
outcome of this lawsuit, but will continue to gather and analyze new information
as it becomes available.

     EPA Section 308 Request. Enron received a request for information from EPA
under Section 308 of the Clean Water Act, requesting information regarding
certain discharges and releases from oil pipelines owned or operated by Enron
and its affiliated companies for the time period July 1, 1998 to July 11, 2001.
Because we are the only Enron affiliated entity with domestic crude oil
pipelines operated by Enron, Enron responded for itself and on behalf of us to
the EPA's request on January 29, 2002. At this time, we are not able to predict
what the outcome will be of the response made to the EPA's Section 308 request.
Further, no assurance can be given as to the amount or timing of future
expenditures for environmental remediation or compliance, and actual future
expenditures may be different from the amounts currently anticipated. In the
event of future increases in costs, we may be unable to pass on those increases
to our customers.

     We are subject to extensive federal, state and local laws and regulations
covering the discharge of materials into the environment, or otherwise relating
to the protection of the environment. See "Business - Environmental Matters"
above.


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

     There were no matters submitted to a vote of security holders during the
fourth quarter of 2001.



                                       27
<PAGE>



                                     PART II


ITEM 5.  MARKET FOR REGISTRANT'S COMMON 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
Composite Tape, and the amount of cash distributions paid per common unit.

<Table>
<Caption>

                                                    Price Range
                                               ---------------------       Cash
                                                  High         Low    Distributions(1)
                                               ---------   ---------  ---------------
<S>                                            <C>         <C>        <C>
2001
      First Quarter ........................   $   17.24   $   14.24     $   0.475
      Second Quarter .......................       18.98       15.77         0.475
      Third Quarter ........................       23.50       17.90         0.475
      Fourth Quarter .......................       22.01        7.40         0.475


2000
      First Quarter ........................   $  14.250   $  11.125     $   0.475
      Second Quarter .......................      15.000      13.188         0.475
      Third Quarter ........................      16.125      13.063         0.475
      Fourth Quarter .......................      17.000      14.250         0.475

</Table>

     (1) Distributions are shown in the quarter paid to common unitholders and
are based on the prior quarter's earnings.

     As of February 15, 2002, there were approximately 395 record holders of our
common units, and there were an estimated 23,000 beneficial owners of our common
units held in a street name. Two holders hold our subordinated units. There is
no established public trading market for these subordinated units.

     Under the MLP's amended and restated agreement of limited partnership and
amendments thereto (the "Partnership Agreement"), it is intended that we
distribute 100% of our Available Cash, as defined in the Partnership Agreement,
within 45 days after the end of each quarter to unitholders of record and to our
General Partner. Available Cash consists generally of all of our cash receipts
adjusted for our cash disbursements and net changes to reserves. The full
definition of Available Cash is set forth in the Partnership Agreement, forms of
which have been filed previously as exhibits with the SEC.  From Available Cash,
we are required to make a minimum quarterly distribution to the General Partner
and the holders of our common units. The minimum quarterly distribution is
currently measured at $0.475 per common unit, distributed 98.02% to the holders
of our common units and 1.98% to our General Partner. If we fail to make the
entire minimum distribution in any quarter, the part of distribution not made is
accounted for as an "arrearage." If, in any quarter, we have Available Cash in
excess of the minimum quarterly distribution, we are required to make the
minimum quarterly distribution and then repay the arrearage to holders of our
common units, before making a distribution to the holders of the subordinated
units or the APIs.


                                       28
<PAGE>


     As discussed further in Note 10 to the Consolidated Financial Statements,
Enron increased its cash distribution support to us in February 1999 to $29.1
million. Under a support agreement with Enron, which expired December 31, 2001,
Enron was obligated to provide cash distribution support to us for any shortfall
in available cash necessary to pay the minimum quarterly distribution, with
respect to quarters ending on or before December 31, 2001, in an amount up to an
aggregate of $29.1 million. Enron purchased $2.5 million of APIs in connection
with the distribution for the first quarter of 1999 and $6.8 million of APIs in
connection with the distribution for the fourth quarter of 1999.

     Because of the bankruptcy of Enron and certain of its subsidiaries and the
resulting uncertainty related to our term financing and working capital
facilities, along with the continued weakness in the crude markets, projected
expenditure requirements related to scheduled turnaround costs for our MTBE
Plant and certain capital expansion projects currently underway, our
distribution for the fourth quarter of 2001 was $0.25 per common unit, which is
lower than the intended minimum quarterly distribution amount of $0.475 per
common unit. Although Enron was obligated under the support agreement to provide
cash distribution support to us for any shortfall in available cash for the
fourth quarter of 2001 below the minimum quarterly distribution amount, Enron
did not pay the fourth quarter cash distribution shortfall of $0.225 per common
unit. We expect to submit a claim for such distribution support amount through
Enron's bankruptcy proceedings. No assurance, however, can be made that we will
recover any such distribution support amount from Enron to cover this shortfall.

     Effective April 23, 2002, we amended and extended our credit facility with
Standard Chartered. Under the terms of the credit facility, distributions to
unitholders cannot be made until all of the following occur: (i) we permanently
reduce our aggregate obligations to Standard Chartered and SCTS to an amount not
exceeding $300 million; (ii) our consolidated net worth is $10 million greater
than our consolidated net worth as of January 31, 2002, excluding any asset
write-downs incurred after January 31, 2002; and (iii) we resolve certain claims
(trade and other payables) of Enron and its affiliates against us related to
Enron's bankruptcy proceedings. On April 3, 2002, we announced that we would not
make a distribution for the first quarter of 2002 and we do not expect to pay
distributions to our unitholders prior to the fourth quarter of 2002. See
further discussion in Note 8 to the Consolidated Financial Statements, Item 7.
"Management's Discussion and Analysis of Financial Condition and Results of
Operations - Impact of the Bankruptcy of Enron and Certain of Its Subsidiaries,
and Related Events - Distributions to Our Common Unitholders" and "Liquidity and
Capital Resources - Working Capital and Credit Resources."


                                       29
<PAGE>


ITEM 6.    SELECTED FINANCIAL DATA (UNAUDITED)

     The following table sets forth selected income, balance sheet and operating
data for the years ended December 31, 2001, 2000, 1999, 1998, and 1997. We have
restated our financial results for the years 1998 and 1999 as more fully
discussed in Note 3 to the Consolidated Financial Statements. The restatement is
related to losses incurred in connection with the theft of NGL product,
concealment of commercial activities and other unauthorized activities by a
former employee. As a result of the restatement, reported net income for the
year 1998 is decreased by $1.0 million and reported net income for the year 1999
is increased by $1.0 million.

     On February 5, 2002, Andersen withdrew as our independent accountant. We
were informed that Andersen's withdrawal related to Andersen's professional
standards concerns, including auditor independence issues, related to events
involving Enron. The restatement of our financial statements for the years 1998
and 1999, and the quarterly periods in 1999 and 2000, requires the issuance of
an updated audit opinion covering the years 1999 and 2000 from Andersen or the
issuance of a new audit opinion covering those years by a new independent
accountant. Since Andersen has advised us they will not issue an updated opinion
due to the independence issues related to their resignation, and
PricewaterhouseCoopers' engagement for purposes of this Annual Report is
presently limited to an audit of 2001, we are filing unaudited financial
statements for the years 1999 and 2000 with this Annual Report. We have
requested PWC to consider auditing the affected periods and they are reviewing
our request. We will consider alternatives for obtaining an audit of the
affected periods as necessary. We can make no assurances that we will be able to
obtain an audit of the affected periods. The independent auditors' reports of
Andersen on our financial statements during 1999 and 2000 did not contain an
adverse opinion or a disclaimer of opinion, and were not qualified or modified
as to uncertainty, audit scope or accounting principles. However, the restated
financial statements for 1999 and 2000 contained in this Annual Report are not
covered by an audit report or opinion of any kind. See Note 3 to the
Consolidated Financial Statements.


                                       30
<PAGE>


<Table>
<Caption>


           (In Thousands, Except Per Unit and Operating Data)

                                                                               Year Ended December 31,
                                                     ----------------------------------------------------------------------------
                                                      2001(1)(3)        2000(3)      1999(1)(2)(3)    1998(1)(2)        1997(3)
                                                     ------------    ------------    ------------    ------------    ------------
                                                                                      (Restated)      (Restated)
<S>                                                  <C>             <C>             <C>             <C>             <C>
INCOME DATA:
Revenue ..........................................   $  8,608,972    $ 11,614,005    $  8,664,401    $  5,294,697    $  7,646,099

Cost of sales ....................................      8,346,206      11,374,090       8,451,057       5,163,121       7,533,054
Operating expenses ...............................        130,063         113,412         107,725          62,384          50,242
Depreciation and amortization -operating .........         32,995          31,357          31,385          19,121          14,444
                                                     ------------    ------------    ------------    ------------    ------------
Gross profit .....................................         99,708          95,146          74,234          50,071          48,359
                                                     ------------    ------------    ------------    ------------    ------------

Selling, general and administrative expenses .....         49,103          47,678          45,469          42,041          45,916
Depreciation & amortization-corp. & other ........          3,083           2,511           1,751           1,830           2,074
Other (income) expense ...........................            210            (282)           (989)            750            (722)

Impairment of assets .............................         29,057              --              --              --           7,961
                                                     ------------    ------------    ------------    ------------    ------------
Operating income .................................         18,255          45,239          28,003           5,450          (6,870)
                                                     ------------    ------------    ------------    ------------    ------------
Interest and related charges, net ................        (34,044)        (28,780)        (28,942)         (9,491)         (6,041)

Other, net .......................................           (517)         (2,626)           (247)         (1,055)         (1,488)
                                                     ------------    ------------    ------------    ------------    ------------
Income (loss) before cumulative
   effect of accounting change ...................   $    (16,306)   $     13,833    $     (1,186)   $     (5,096)   $    (14,399)
                                                     ============    ============    ============    ============    ============
Net income (loss)(4) .............................   $    (15,233)   $     13,833    $        561    $     (5,096)   $    (14,399)
                                                     ============    ============    ============    ============    ============

Basic income (loss) per Unit:
   Common ........................................   $      (0.54)   $       0.49    $      (0.01)   $      (0.23)   $      (0.75)
                                                     ============    ============    ============    ============    ============
   Subordinated ..................................   $      (0.54)   $       0.49    $       0.07    $      (0.31)   $      (0.75)
                                                     ============    ============    ============    ============    ============
Diluted income (loss) per Unit ...................   $      (0.54)   $       0.49    $       0.02    $      (0.26)   $      (0.75)
                                                     ============    ============    ============    ============    ============
Cash distributions per Common Unit ...............   $       1.90    $       1.90    $       1.90    $       1.90    $       1.90
                                                     ============    ============    ============    ============    ============

BALANCE SHEET DATA (AT END OF PERIOD):
Total assets .....................................   $  1,100,510    $  1,491,020    $  1,558,661    $    965,820    $    782,921
Total debt .......................................        417,500         235,000         309,055         328,313         109,300
Partners' capital(5) .............................         37,968          96,364         120,117          74,553          62,093
Additional Partnership Interests(6) ..............          9,318           9,318           2,547          21,928          12,775
Capital expenditures(7) ..........................        153,228          14,270          58,729         266,569          22,837
Cash distributions ...............................         43,163          37,586          30,380          22,842          29,681

OPERATING DATA:
North American Crude Oil - East of
  Rockies Operations:
   Total lease volumes (thousand bpd) ............          361.0           408.2           408.8           285.6           282.4
Pipeline Operations:
   Average volumes (thousand bpd) ................          511.1           561.5           513.7           188.3           142.3
Liquids Operations:
   Volumes processed (thousand bpd) ..............           15.8              --              --              --              --
</Table>

----------

(1)  1998 includes one month of results of operations associated with the assets
     acquired from Koch Pipeline Company, L.P. on December 1, 1998. 1999
     includes seven months of results of operations associated with the assets
     acquired from Texas-New Mexico Pipe Line Company. 2001 includes six months
     of results of operations associated with the Liquids assets acquired from
     Enron and State Street Bank on June 30, 2001.

(2)  1999 and 1998 amounts have been restated for certain unauthorized
     mid-continent NGL trading activities. As a result of the restatement,
     reported net income for the year 1998 decreased by $1.0 million and
     reported net income for the year 1999 increased by $1.0 million. See
     further discussion in Note 3 to the Consolidated Financial Statements.


                                       31
<PAGE>


(3)  1997 includes nonrecurring charges of $8.0 million related to asset
     impairments and $2.0 million of severance costs related to the exit of the
     East of Rockies refined products business and corporate realignment. 1999
     includes nonrecurring charges of $6.8 million of costs related to
     mid-continent NGL activity and $2.0 million of severance costs for
     reduction of workforce. 2000 includes nonrecurring income of $0.6 million
     related to an insurance recovery related to the theft of NGL product in
     1999 partially offset by charges related to mid-continent NGL activity and
     severance costs related to a former officer of the General Partner. See
     additional discussion in Note 7 to the Consolidated Financial Statements.
     2001 includes the impairment of the ten-year Toll Conversion and Storage
     Agreements with EGLI. See further discussion in Note 5 to the Consolidated
     Financial Statements.

(4)  1999 includes the cumulative effect of adopting Emerging Issues Task Force
     Issue 98-10 "Accounting for Contracts Involved in Energy Trading
     Activities." 2001 includes the cumulative effect of adopting Statement of
     Financial Accounting Standards No. 133 "Accounting for Derivative
     Instruments and Hedging Activities" and the change in the method of valuing
     inventories used in our energy trading activities. See Notes 2 and 4 to the
     Consolidated Financial Statements.

(5)  Partners' Capital includes the issuance of 3,500,000 Common Units to the
     public in September 1999. See additional discussion in Note 9 to the
     Consolidated Financial Statements.

(6)  In February 1999, Enron contributed $21.9 million in Additional Partnership
     Interests to the Partnership pursuant to its commitment made in connection
     with the Support Agreement. See additional discussion in Note 10 to the
     Consolidated Financial Statements. In May 1999 and February 2000, Enron
     paid $2.5 million and $6.8 million, respectively, in support of EOTT's
     first and fourth quarter 1999 distributions to its Common Unitholders in
     exchange for Additional Partnership Interests.

(7)  1997 includes $12 million for the purchase of crude gathering and pipeline
     assets in Arkansas, Louisiana and Texas. 1998 includes $258.1 million for
     the purchase of crude oil gathering and transportation assets in multiple
     states. 1999 includes $38.4 million for the purchase of crude oil
     transportation and storage assets in New Mexico and Texas. 2001 includes
     $117 million for the purchase of certain liquids processing, storage and
     transportation assets in the Texas Gulf Coast region. See additional
     discussion in Note 5 to the Consolidated Financial Statements.


                                       32
<PAGE>



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

INFORMATION REGARDING FORWARD-LOOKING INFORMATION

     The statements in this Annual Report on Form 10-K that are not historical
information are 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. Such forward-looking statements include the discussions in "Management's
Discussion and Analysis of Financial Condition and Results of Operations." Any
forward-looking statements are not guarantees of future performance and involve
significant risks and uncertainties, and actual results may vary materially from
those in the forward-looking statements as a result of various factors. See Item
1. "Business - Information Regarding Forward-Looking Information" and in this
section, "Impact of the Bankruptcy of Enron and Certain of Its Subsidiaries, and
Related Events," "Risk Factors," and "Liquidity and Capital Resources" for
statements regarding important factors that could cause actual results to differ
materially from those in the forward-looking statements herein. Although we
believe that our expectations regarding future events are based on reasonable
assumptions, we can give no assurance that these are all the factors that could
cause actual results to vary materially or that our expectations regarding
future developments will prove to be correct.

IMPACT OF THE BANKRUPTCY OF ENRON AND CERTAIN OF ITS SUBSIDIARIES, AND RELATED
EVENTS

     We are managed by our General Partner, EOTT Energy Corp., which is a
wholly-owned subsidiary of Enron. See Item 1. "Business." Beginning on December
2, 2001, Enron and certain subsidiaries of Enron filed voluntary petitions for
relief under Chapter 11 of Title 11 of the United States Code with the United
States Bankruptcy Court for the Southern District of New York. Neither our
General Partner nor we are included in the bankruptcy. However, because of our
contractual relationships with Enron and certain of its subsidiaries at the time
of the filing of the bankruptcy petition, the bankruptcy has impacted us in
various ways, discussed below.

Audit Committee

     The Board of Directors of our General Partner established an audit
committee consisting of three individuals who are neither officers nor employees
of our General Partner or an affiliate of our General Partner ("Independent
Directors"). On November 28, 2001, two of the three Independent Directors
resigned from the Board of Directors of our General Partner, citing personal
reasons. On December 5, 2001, the third Independent Director of the Board of
Directors of our General Partner also resigned, citing personal reasons. As a
result of these resignations, there were no Independent Directors to sit on the
audit committee. On April 10, 2002, Messrs. Matthews, Tidwell and Lovett were
elected as new Independent Directors of the Board of Directors of our General
Partner. Mr. Tidwell now serves as chairman of the audit committee. The same
three independent directors also comprise our Compensation Committee and our new
Restructuring Committee.

Change in Our Independent Accountants and Certain Directors

     Andersen withdrew as our independent accountants on February 5, 2002,
citing professional concerns, including auditor independence issues, relating to
the recent events involving Enron. On March 25, 2002, the Board of Directors of
our General Partner authorized the engagement of PricewaterhouseCoopers LLP
("PWC") as our independent accountants to replace Andersen. For further details,
see Item 9. "Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure." Because of the withdrawal of Andersen, the time necessary
to select PWC as our new independent accountants, and the time required for
completion of our audit for 2001, we filed a "Notification of Late Filing" on
Form 12B-25 with the U.S. Securities


                                       33
<PAGE>


and Exchange Commission on April 2, 2002, disclosing that we were unable to
timely file this Form 10-K Annual Report for the period ending December 31,
2001, on April 1, 2002.

New York Stock Exchange Requirements and Impact

     The New York Stock Exchange ("NYSE") requires listed companies to timely
file its Form 10-K. The NYSE has the option to evaluate the circumstances
surrounding any delay in filing a Form 10-K and to evaluate the continued
listing of the company. Although we have been in contact with the NYSE, and the
NYSE has not taken action with regard to our delay in filing our Annual Report
on Form 10-K, we cannot give any assurance that the NYSE will not take action
against us in the future.

Availability of Credit

     The Enron credit facility in the amount of $1.0 billion provided us credit
support in the form of guarantees, letters of credit, and up to $100 million for
working capital loans. As a result of Enron's financial deterioration and
subsequent bankruptcy filings, the Enron credit facility, scheduled to expire on
December 31, 2001, ceased to be available to us. On November 30, 2001, we
entered into an interim credit facility with Standard Chartered, our primary
lender, for the purpose of supplying letters of credit previously provided under
the credit facility with Enron. This interim credit facility provided for
issuance through March 2002 of up to $150 million of letters of credit, which
was subsequently increased to $300 million in December 2001. The interim
facilities executed during the fourth quarter of 2001, and the amended term
facilities closed in April 2002, have resulted in significantly higher credit
costs than we have previously experienced. For further details see "Liquidity
and Capital Resources" below and Item 13. "Certain Relationships and Related
Transactions."

     In addition, we financed the purchase price of our liquids processing,
storage and transportation assets through borrowings from SCTS under short-term
inventory and receivables financing facilities. Any refinancing of these assets
on a longer-term basis will likely be at higher interest rates than would have
been incurred prior to the Enron bankruptcy.

     Because of the Enron bankruptcy and in part as a result of the increase in
crude oil prices, our trade creditors have been less willing to extend credit to
us on an unsecured basis, and the amount of letters of credit we have been
required to post for our North American Crude Oil - East of Rockies business
segment increased from approximately $150 million in September 2001 to $196
million in December 2001, and to $243 million in March 2002.

Termination of Recapitalization Plan

     On September 6, 2001, we announced a recapitalization plan that included a
recapitalization agreement with Enron, our General Partner, and Koch Petroleum
Group, L.P., to convert all outstanding subordinated units and Additional
Partnership Interests ("APIs") into common units and the implementation of a
refinancing plan. Due to events involving Enron, the recapitalization agreement
terminated under its own terms as the transaction was not closed before December
31, 2001 and the refinancing plans were terminated.

Distributions to Our Common Unitholders

     Our distribution for the fourth quarter of 2001 was $0.25 per common unit,
which is lower than the minimum quarterly distribution amount of $0.475 per
common unit intended under our MLP Partnership Agreement. Enron was obligated
under a support agreement to provide cash distribution support to us for any
shortfall in available cash for the fourth quarter of 2001 below the minimum
quarterly distribution amount. As a result of Enron's financial deterioration
and bankruptcy, however, Enron did not pay the fourth quarter cash distribution
shortfall of $0.225 per common unit. We expect to submit a claim for such
distribution support


                                       34
<PAGE>


amount in Enron's bankruptcy proceedings. However, no assurance can be made that
we will recover any amount of such distribution support on behalf of our
unitholders from Enron.

     Additionally, on April 3, 2002, we announced that we would not make a
distribution to our common unitholders for the first quarter of 2002. Under our
amended credit facility, effective April 23, 2002, distributions to unitholders
cannot be made unless certain conditions are met. See "Liquidity and Capital
Resources" below.

Rejection of Certain Agreements with Enron's Subsidiary

     We have also been impacted as a result of the inclusion of EGLI, a
wholly-owned subsidiary of Enron, in Enron's bankruptcy. As discussed above in
Item 1. "Business - Liquid Operations - Toll Conversion and Storage Agreements,"
we had in place ten-year Toll Conversion and Storage Agreements with EGLI. On
April 2, 2002, the Bankruptcy Court entered a stipulation and order rejecting
the Toll Conversion and Storage Agreements (the "Stipulation"), which became
final and non-appealable on April 12, 2002. As a result of EGLI's
non-performance under these agreements, we recognized a non-cash impairment of
approximately $29.1 million in the fourth quarter of 2001 for the write-down of
our Toll Conversion and Storage Agreements.

     Additionally, we have a monetary damage claim against EGLI and Enron as a
result of the rejection of the agreements under the Stipulation, which has been
filed in the Enron bankruptcy proceedings. The final amount of our claim
resulting from the rejection of the two agreements has not yet been fully
determined or calculated. Additionally, we cannot predict when such claims will
be resolved. We believe that any delay in collecting or failure to collect will
not have a material adverse effect on our financial condition.

     We might also incur losses in the event that Enron fails to indemnify us
for certain ad valorem taxes, possible environmental expenditures and title
defects relating to the MTBE Plant and the Mont Belvieu Facility. Such indemnity
obligations include agreements to indemnify us (i) for any and all costs and
expenses incurred in defending the pending litigation and an administrative
claim by the City of Morgan's Point, Texas, relating to ad valorem taxes on the
MTBE Plant; (ii) for ad valorem taxes assessed, settled or attributable in
excess of any valuations of the MTBE Plant over $27 million for the years 2001,
2002, 2003, 2004 and one half of the ad valorem taxes on such excess in 2005;
(iii) for expenditures incurred under certain circumstances to modify the MTBE
Plant if and when required to comply with the Nitrogen Oxide Emissions
provisions of the Federal and Texas Clear Air Acts or other environmental laws;
(iv) for certain environmental conditions associated with Enron or certain Enron
affiliates' ownership or operation prior to June 30, 2001; and (v) for certain
title defects in certain real property, easements, rights-of-way, and personal
property. The total indemnity amount provided for under the purchase and sale
agreement is up to $25 million. We do not believe these indemnities have any
value; however, we intend to make appropriate claims as a result of such
indemnity obligations through Enron's bankruptcy proceedings. For further
details concerning the June 2001 purchase of the MTBE Plant and the Mont Belvieu
Facility and the Toll Conversion and Storage Agreements, see also Item 1.
"Business - Liquids Operations" and Note 5 to the Consolidated Financial
Statements.

Claims Against Enron's Bankruptcy Estate

     We have several potential claims against Enron and certain of its
subsidiaries bankruptcy estates and have retained outside counsel to evaluate
such claims. See Note 10 to the Consolidated Financial Statements. These claims
will likely be deemed to be unsecured claims against certain of the Enron
entities involved in the Enron bankruptcy filings. We have also filed a claim
for rejection damages in excess of $500 million against Enron and certain of its
subsidiaries in the Enron bankruptcy proceedings. We are uncertain regarding the
ultimate amount of damages for breach of contract or other claims that we will
be able to establish in the bankruptcy proceeding and we cannot predict the
amounts, if any, that we will collect or the timing of any such collection.


                                       35
<PAGE>


Certain Conflicts of Interest

     Our General Partner owns an approximate 1.98% general partner interest in
the MLP. Based upon information provided by Enron, Enron beneficially owns
approximately 18% of our outstanding common units, 78% of our outstanding
subordinated units and 37% of our total units outstanding because it retains
voting power and shared investment power over the securities. The members of the
Board of Directors of our General Partner are elected by Enron. Our interests
could conflict, especially with regard to the recent bankruptcy filing by Enron
and certain of its subsidiaries, with interests of Enron and its affiliates,
including our General Partner, and in such case our General Partner will
generally have a fiduciary duty to resolve the conflicts in a manner that is in
our best interest.

     On May 22, 2002, two of our directors, Stanley C. Horton and Roderick
Hayslett, who have current Enron affiliations, advised us they would not, on the
advice of legal counsel for Enron, be able to sign this Annual Report. Their
reason stated for such decision was that their positions with Enron or its
affiliates might be interpreted by third parties as constituting endorsement of
or evidence of the validity of certain claims among us, Enron or Enron's
respective affiliates, as such claims may be disclosed in this Annual Report.
Because Messrs. Horton and Hayslett are the only directors on our current Board
of Directors who were directors during the entire year ending December 31, 2001
covered by this Annual Report, the absence of their signatures on this report
means that the directors with the greatest knowledge of our operations during
2001 have not formally acknowledged the accuracy and completeness of this
report. Neither of them has, however, advised us that this document is either
inaccurate or incomplete.

     The General Partner of the MLP restructured its Board of Directors to
reduce the number of directors from seven to five, so that independent directors
now constitute a majority of the Board of Directors. Nevertheless, Enron as the
sole shareholder of our General Partner may elect and remove directors. In
addition to the board restructuring, our General Partner created a restructuring
committee (the "Restructuring Committee"). The Restructuring Committee has
powers and authority of the Board of Directors with respect to any restructuring
transactions concerning the General Partner or the MLP or any of its affiliates.
Any proposed agreement or action involving a potential conflict, however, must
first be submitted to the audit committee and the audit committee must determine
that the proposed agreement or transaction is fair and reasonable to us or our
General Partner, as the case may be.

     Unless otherwise provided for in our Partnership Agreement, the laws of
Delaware and Texas generally require a general partner of a partnership to
adhere to fiduciary duty standards, under which it owes its partners the highest
duties of good faith, fairness and loyalty. Our Partnership Agreement contains
provisions that modify certain of these fiduciary duties of our General Partner.
For example, our Partnership Agreement provides that whenever a potential
conflict of interest exists or arises between our General Partner or any of its
affiliates, on the one hand, and the Partnership, our operating partnerships or
any partner, on the other hand, any resolution or course of action with respect
to such conflict of interest shall be permitted and deemed approved by all
partners, and shall not constitute a breach of our Partnership Agreement if the
course of action is deemed to be fair and reasonable to us. Our General Partner
is authorized, but not required, in connection with a conflict of interest, to
seek special approval by the audit committee of a resolution of such a conflict
of interest. Upon such approval, any conflict of interest and resolution thereof
is conclusively deemed to be fair and reasonable to the Partnership. Our
Partnership Agreement does not require our General Partner, including the audit
committee, to consider the interests of any person other than the MLP. Under
certain circumstances, however, our Partnership Agreement provides that where
our General Partner is permitted or required to make a decision in its sole
discretion, our General Partner is entitled to consider only such interests and
factors as it desires and has no duty to give any consideration to any interest
of, or factors affecting the MLP, our operating partnerships or any limited
partner. We are required to indemnify our General Partner, its affiliates and
their respective officers, directors, employees, agents and trustees to the
fullest extent permitted by law against liabilities, costs and expenses incurred
by any of them who acted, as determined by our General Partner, in good faith
and in a manner which they believed to be in,


                                       36
<PAGE>


or not opposed to, our best interests and, with respect to any criminal
proceedings, had no reasonable cause to believe their conduct was unlawful.

     Under our Partnership Agreement, with some limited exceptions, affiliates
of our General Partner are not restricted from engaging in any business
activities, including those in competition with us. As a result, other conflicts
of interest may arise between affiliates of our General Partner and us. Our
Partnership Agreement provides that, subject to limited exceptions, it shall not
constitute a breach of our General Partner's fiduciary duties to our unitholders
or to us for any affiliate of our General Partner to engage in direct
competition with us, including, without limitation, the gathering, transporting
and marketing of crude oil and refined petroleum products, and processing
liquids hydrocarbons.

Performance Collateral from Enron

     Enron guaranteed payments by EGLI under the Toll Conversion and Storage
Agreements; however, such guaranty was limited to $50 million under the Toll
Conversion Agreement and $25 million under the Storage Agreement. On May 10,
2002, we filed a claim under this guaranty in the Enron bankruptcy proceeding.
We, however, cannot predict the amounts, if any, that we will collect or the
timing of any such collection. Additionally, EGLI owed us approximately $9
million under the Toll Conversion and Storage Agreements prior to filing for
bankruptcy. Pursuant to these agreements, on November 27, 2001, we requested
that EGLI post two $25 million letters of credit. In lieu of posting letters of
credit, we received $25 million from EGLI/Enron, against which we recouped $9
million of outstanding invoices to EGLI. We currently intend to apply the
remaining sum, approximately $16 million, to recoup against or seek offset of a
portion of our damages resulting from EGLI's rejection of the Toll Conversion
and Storage Agreements. We also have outstanding accounts payable to EGLI in the
amount of approximately $2 million for butane and methanol feedstock we acquired
prior to EGLI filing for bankruptcy. We are exploring the possibility of
offsetting this $2 million payable against a portion of the damages resulting
from EGLI's rejection of the Toll Conversion and Storage Agreements. We are
uncertain, however, as to how these issues will be resolved.

Our General Partner's Operation and General Administration of the Partnership

     As is commonly the case with publicly traded partnerships, we do not
directly employ any persons responsible for managing or operating us or for
providing services relating to day-to-day business affairs. Our General Partner
provides such services or obtains such services from third parties, and the
Partnership is responsible for reimbursement of substantially all of its direct
and indirect costs and expenses. Our General Partner provides services to us,
including liability and casualty insurance and certain data processing services.
We reimburse the General Partner for these direct and indirect costs. Such costs
were $2.5 million, $3.6 million and $3.8 million for the years ended December
31, 2001, 2000 and 1999, respectively and are included in operating expense. As
of December 31, 2001 and 2000, we owe approximately $12.2 million and $14.1
million, respectively, with respect to these services.

     Our General Partner entered into an agreement with Enron Pipeline Services
Company ("EPSC"), a wholly-owned subsidiary of Enron that is currently not in
bankruptcy, to provide certain operating and administrative services to our
General Partner, effective October 1, 2000. These services were previously
performed directly by our General Partner. The agreement provides that our
General Partner will reimburse EPSC for its costs and expenses in rendering the
services. In turn, we have a corresponding obligation to our General Partner.
The costs incurred for these services for the year ended December 31, 2001 and
for the three months ended December 31, 2000 were $56.7 million and $6.3
million, respectively. As of December 31, 2001 and 2000, we owe $11.5 and $4.8
million, respectively, with respect to these services. The General Partner
anticipates taking these services over in 2002.


                                       37
<PAGE>


     In connection with the acquisition of the liquids assets in June 2001, our
General Partner entered into an agreement with EGP Fuels Company ("EGP Fuels")
to provide transition services through December 31, 2001 for the processing of
invoices and payments to third parties related to the MTBE Plant and Mont
Belvieu Facility. The agreement provides that the General Partner will reimburse
EGP Fuels for these direct costs and we will reimburse the General Partner.
Costs related to these services were $12.3 million for the six months ended
December 31, 2001 and were still outstanding at December 2001.

     We have recorded liabilities of approximately $36.0 million to Enron and
its affiliates, including the General Partner, under various agreements,
discussed above. We are exploring possibilities of recouping and/or seeking
offset against certain of our claims in the bankruptcy proceeding against our
liabilities to Enron and its affiliates, including the General Partner. At this
point, however, it is uncertain how these issues will be resolved. See Note 10
to our Consolidated Financial Statements.

General Partner Alternatives

     Although neither our General Partner nor we have filed for Chapter 11
bankruptcy protection, it is possible that Enron could attempt to take action to
cause our General Partner to file for bankruptcy protection. If our General
Partner were to file for bankruptcy relief, the filing would be an "Event of
Withdrawal" under our Partnership Agreement and our General Partner will be
deemed to have withdrawn. Upon the occurrence of an Event of Withdrawal, our
General Partner is required to give notice to our limited partners within 30
days after such occurrence. An Event of Withdrawal triggers dissolution and
winding up of the affairs of the Partnership unless (i) a successor General
Partner is elected and admitted to the Partnership within 180 days, (ii) a
written opinion of counsel is issued that such withdrawal would not result in
the loss of the limited liability of any limited partner or of the limited
partner of any of our operating limited partnerships or cause the Partnership or
any of our operating limited partnerships to be taxed as a corporation, and
(iii) the new general partner executes a new partnership agreement and executes
and files a new certificate of limited partnership. Election of a successor
General Partner requires a vote of a majority of the outstanding units to
reconstitute the Partnership and approve the successor general partner. Upon the
election of a new general partner, the General Partner's interest will be
converted to common units. Despite the provisions of our Partnership Agreement
discussed in this section, if our General Partner were to file for bankruptcy
protection, the bankruptcy court may refuse to enforce these provisions or may
require different or additional procedures and consideration to allow these
provisions to be followed.

     Enron has to date, however, chosen not to take action to cause the
inclusion of our General Partner in its bankruptcy proceedings, which were
commenced on December 2, 2001. Neither Enron, the General Partner, nor any other
Enron affiliate has advised us of any intention of Enron, any Enron affiliates
or our General Partner to place our General Partner into bankruptcy. Because the
bankruptcy of Enron and certain of its affiliates created conflicts of interest
between EOTT and Enron and certain of its affiliates (for example, with respect
to the EGLI contracts, now rejected), the General Partner and Enron established
a Restructuring Committee to consider (among other things) all matters involving
a possible restructuring of our relationship with Enron. This committee is
comprised of our three solely independent, non-Enron related directors. This
committee was also granted the power, through amendments to our charter and
by-laws, to place our General Partner into bankruptcy.

     We have retained UBS Warburg as our financial adviser to help us evaluate a
number of strategic alternatives for our business in light of the Enron
bankruptcy. Although no assurance can be made that we will enter into any
transaction, we intend to continue to evaluate and pursue all alternatives.
Further, these alternatives may require the approval of either our unitholders
or the Bankruptcy Court, neither of which is guaranteed.


                                       38
<PAGE>


Pension Plan Underfunding Issues

     The MLP does not have any employees on its payroll, and does not sponsor
any pension plans. However, the MLP and its operating limited partnerships use
the services of employees of our General Partner, a wholly-owned subsidiary of
Enron. Our General Partner provides the services of these employees to the MLP
under the terms of the Partnership Agreement and provides the services of these
employees to EOTT Energy General Partner, LLC under the terms of an
administrative services agreement. Our General Partner is a participating
employer in a defined benefit pension plan known as the Enron Corp. Cash Balance
Plan (the "Cash Balance Plan"). It is our understanding, based on information
provided by Enron, that the assets of the Cash Balance Plan are currently less
than the present value of all accrued benefits on both an SFAS No. 87
(Employers' Accounting for Pensions) basis and a plan termination basis by
approximately $90 million, with approximately 48 percent of that amount
attributable to members of the Enron "controlled group" that are not in
bankruptcy.

     The Enron administrative committee for the Cash Balance Plan was recently
replaced by an independent fiduciary, the State Street Bank and Trust Company of
Boston, Massachusetts. This replacement, which was made at the request of the
U.S. Department of Labor ("DOL"), occurred as part of an agreement reached
between the DOL and Enron.

     A federal government corporation known as the Pension Benefit Guaranty
Corporation ("the PBGC") has the power to terminate underfunded pension plans in
certain situations, after receiving the permission either of the employer or of
a court. When such a termination occurs, the PBGC uses a method of calculating
liability for underfunding of the pension plan that, under current interest
rates and assumptions, usually results in a much higher liability figure than
the liability figure that results from liability calculated on an on-going,
rather than a termination, basis. Should such termination occur, liability for
any underfunding of the plan, calculated on a termination basis, may be imposed
jointly and severally on all members of the employer's "controlled group," which
is a defined term under the Employment Retirement Income Security Act ("ERISA")
and the United States Internal Revenue Code.

     In the event of termination of the Cash Balance Plan, the PBGC could impose
such "controlled group" liability on our General Partner. The PBGC could demand
that our General Partner pay the underfunded amount, calculated on a termination
basis. If our General Partner failed to pay such claim, the PBGC could move to
perfect against our General Partner's property a lien that automatically
attaches against the assets of each member of the "controlled group" in an
amount equal to the lesser of the underfunding or 30% of the aggregate net worth
of the "controlled group." Further, if Enron failed to make minimum funding
payments exceeding in the aggregate $1 million, a lien would automatically
attach to assets of Enron "controlled group" and "affiliated service group"
members. It is our understanding that Enron is not presently delinquent in
making on-going contributions to its pension plan. However, any such lien would
be subordinate to any then-existing, perfected liens against our General
Partner's property.

     Under these circumstances, our General Partner would exercise all its
rights to defend against such a claim, and, in the event the PBGC had not
already pursued and collected from solvent members of the "controlled group,"
would assert its rights to recover contribution from such members. At this time,
we cannot predict whether either the PBGC or Enron will seek to terminate the
Cash Balance Plan. Any claim paid by the General Partner would become our
responsibility under the provisions of the MLP's Partnership Agreement, subject
to any claims of indemnity, offset, recoupment or any counterclaims we might
have against our General Partner or any of its affiliates.

Other Effects

     Enron's bankruptcy filing has also had a number of other impacts on our
business and management. Our senior notes have been downgraded, our
recapitalization plan proposed in 2001 was terminated, the value of our common
units has declined significantly, which has restricted our access to the capital
markets, and Enron's bankruptcy has caused us to lose market share in our crude
oil marketing, gathering and pipeline


                                       39
<PAGE>


operations. Additionally, we have been included in requests for documents
related to Congressional and regulatory investigations as a result of Enron's
bankruptcy and are fully cooperating with such requests. For further information
concerning our relationships and related transactions with Enron and its
affiliates, see Note 10 to our Consolidated Financial Statements. While it is
not feasible to predict the final outcome of the events surrounding Enron's
bankruptcy, we could be materially and adversely affected by such events.

OVERVIEW

     Through our four operating limited partnerships, EOTT Energy Operating
Limited Partnership, EOTT Energy Canada Limited Partnership, EOTT Energy
Pipeline Limited Partnership, and EOTT Energy Liquids, L.P., we purchase,
gather, transport, store, process and resell crude oil, refined petroleum
products, natural gas liquids and other related products. Our principal business
segments are our North American Crude Oil - East of Rockies Operations, our
Pipeline Operations, our Liquids Operations and our West Coast Operations. See
Note 15 to our Consolidated Financial Statements for certain financial
information by business segment.

Gathering, Marketing and Trading Operations

     Gross profit from gathering, marketing and trading operations varies from
period-to-period, depending to a significant extent upon changes in the supply
and demand of crude oil and the resulting changes in United States crude oil
inventory levels. The gross profit from gathering and marketing operations is
generated by the difference between the price of crude oil at the point of
purchase and the price of crude oil at the point of sale, minus the associated
costs of gathering and transportation, field operating costs and depreciation
and amortization. In addition to purchasing crude oil at field gathering
locations, we purchase crude oil in bulk at major pipeline terminal points and
major marketing points and enter into exchange transactions with third parties.
These bulk and exchange transactions are characterized by large volume and
narrow profit margins on purchase and sale transactions, and the absolute price
levels for crude oil do not necessarily bear a relationship to gross profit,
although such price levels significantly impact revenues and cost of sales.
Because period-to-period variations in revenues and cost of sales are not
generally meaningful in analyzing the variation in gross profit for gathering
and marketing operations, such changes are not addressed in the following
discussion.

     Our operating results are sensitive to a number of factors including:
grades or types of crude oil, variability in lease crude oil barrels produced,
individual refinery demand for specific grades of crude oil, area market price
structures for the different grades of crude oil, location of customers,
availability of transportation facilities, and timing and costs (including
storage) involved in delivering crude oil to the appropriate customer.

     In general, as we purchase crude oil, we establish a margin by selling
crude oil for physical delivery to third party users, such as independent
refiners or major oil companies, or by entering into future delivery obligations
with respect to futures contracts on the NYMEX, thereby minimizing or reducing
exposure to price fluctuations. Through these transactions, we seek to maintain
positions that are substantially balanced between crude oil purchases and sales
or future delivery obligations. However, depending on market conditions,
positions may be taken subject to established price risk management position
limits. As a result, changes in the absolute price level for crude oil do not
necessarily impact the margin from gathering and marketing.

     Throughout the marketing process, we seek to maintain a substantially
balanced risk position. We do have certain risks that cannot be completely
hedged, such as a portion of certain basis risks. Basis risk arises when crude
oil is acquired by a purchase or exchange that does not meet the specifications
of the crude oil we are contractually obligated to deliver, whether in terms of
geographic location, grade or delivery schedule. In accordance with our risk
management policy, we seek to limit price risk and maintain margins through a
combination of physical sales, NYMEX hedging activities and exchanges of crude
oil with third parties.


                                       40
<PAGE>


     We operate the business differently as market conditions change. During
periods when the demand for crude oil is weak, the market for crude oil is often
in "contango," meaning that the price of crude oil in a given month is less than
the price of crude oil in a subsequent month. In a contango market, storing
crude oil is favorable, because storage owners at major trading locations can
simultaneously purchase production at low current prices for storage and sell at
higher prices for future delivery. When there is a higher demand than supply of
crude oil in the near term, the market is "backwardated," meaning that the price
of crude oil in a given month exceeds the price of crude oil in a subsequent
month. A backwardated market has a positive impact on marketing margins because
crude oil gatherers can capture a premium for prompt deliveries.

Pipeline Operations

     Pipeline revenues and gross profit are primarily a function of the level of
throughput and storage activity and are generated by the difference between the
regulated published tariff and the fixed and variable costs of operating the
pipeline. Transporting crude oil at published pipeline tariffs for our North
American Crude Oil - East of Rockies business segment, generates a majority of
our pipeline revenues. Approximately 80% of the revenues of our Pipeline
Operations business segment for the twelve months ended December 31, 2001 were
generated from tariffs charged to our North American Crude Oil - East of Rockies
business segment and sales of crude oil inventory to our North American Crude
Oil - East of Rockies business segment. Changes in revenues and pipeline
operating costs are relevant to the analysis of financial results of the
Pipeline Operations business segment and are addressed in the following
discussions of the Pipeline Operations business segment.

Liquids Operations, Toll Conversion and Storage Agreements

     Gross profit for our Liquids Operations, prior to Enron's bankruptcy, was
determined by the provisions of the ten-year Toll Conversion and Storage
Agreements, which included the processing fee for converting feedstocks into
products at the MTBE Plant; storage and transportation fees related to our Mont
Belvieu Facility; the fixed and variable costs of operating these facilities;
and the depreciation and amortization related to these facilities. Revenues from
the processing operations were based upon a fixed fee received for certain
minimum quantities of product converted on a take-or-pay basis. Revenues from
the storage and transportation operations were based upon a fixed rate for
certain minimum capacity levels and actual volumes stored and transported.

     On April 2, 2002, the Bankruptcy Court entered the Stipulation rejecting
the Toll Conversion and Storage Agreements, which became final and
non-appealable on April 12, 2002. Since the Enron bankruptcy and the filing of
the Stipulation, we are exploring various alternatives for these facilities. See
Item 1. "Business - Liquid Operations - Toll Conversion and Storage Agreements,"
and "Impact of the Bankruptcy of Enron and Certain of Its Subsidiaries, and
Related Events - Rejection of Certain Agreements with Enron's Subsidiary" above.

     Subsequent to the filing of EGLI's bankruptcy, we began conducting
commercial supply and marketing activities of the MTBE Plant. Under a merchant
operation, gross profit from the Liquids Operations includes the difference
between the purchase price of feedstocks and the price of MTBE at the point of
sale minus any transportation costs, fixed and variable costs of operating the
facility and the depreciation and amortization related to the facility. Until
the Storage Agreement was rejected, we could not enter into any third party
storage contracts. As a result, we could only charge a daily administrative fee
to EGLI for the use of the Mont Belvieu Facility, until April 12, 2002.


                                       41
<PAGE>


ACQUISITIONS AND DISPOSITIONS

     In June 2001, we purchased certain liquids processing, storage and
transportation assets located in the Texas Gulf Coast region through our newly
created, wholly-owned subsidiary, EOTT Energy Liquids, L.P. and concurrently
entered into ten-year Toll Conversion and Storage Agreements. We paid $117
million in cash to Enron and State Street Bank and Trust Company of Connecticut,
National Association, Trustee. The assets owned by the Trustee were held under a
lease financing arrangement with Enron. Immediately prior to the acquisition,
all of the assets were operated by EGP Fuels Company, a wholly-owned subsidiary
of Enron. We acquired these facilities pursuant to the terms of a purchase and
sale agreement with Enron, effective June 30, 2001. We financed the purchase
price through short-term borrowings from SCTS under short-term inventory and
receivable financing facilities. For further details see "Liquidity and Capital
Resources" below.

     Effective June 30, 2001, we sold our West Coast crude oil gathering and
blending operations to Pacific Marketing and Transportation LLC ("Pacific") for
$14.3 million. We could be required to repay up to $1.5 million of the sale
price, subject to a two-year look-back provision regarding average operating
results during the period July 1, 2001 through June 30, 2003. Such amount is
reflected in Other Long-Term Liabilities in the Consolidated Balance Sheet at
December 31, 2001.

     On May 1, 1999, we acquired crude oil transportation and storage assets in
West Texas and New Mexico from Texas-New Mexico Pipe Line Company ("Tex-New
Mex"), which included approximately 1,800 miles of common carrier crude oil
pipelines. We paid $33.0 million in cash and recorded a $4 million liability
related to assumed environmental obligations.

OTHER

     Due to changes in market conditions, we modified a 15-year contract between
Koch Petroleum Group, L.P., now Koch Supply & Trading, L.P. ("Koch Petroleum")
and us, which began December 1, 1998, whereby we supply crude oil to Koch
Petroleum at market based prices. We amended the supply volume price for six
months, beginning September 1, 2000. In February 2001, we extended the term of
the amendment for an additional six months, beginning March 1, 2001, and further
extended the amendment effective December 1, 2001 for an additional six months,
then month to month thereafter.

RESULTS OF OPERATIONS

     The following review of our results of operations and financial condition
should be read in conjunction with our Consolidated Financial Statements and
Notes thereto. The results of operations for the twelve months ended December
31, 2001, 2000, and 1999, and the financial condition at December 31, 2001 and
2000, reflect our activities.

     We have made certain reclassifications and revisions to our income
statement presentation. We now reflect as a component of "gross profit", all
costs associated with the production of revenues (including costs of sales,
operating expenses and applicable depreciation and amortization). This contrasts
with prior year presentations that included the cost of products and associated
transportation costs as components of "gross margin". Additionally, certain
other income and expenses (including gains and losses on assets sales and income
or expense related to litigation settlements) which were previously classified
as "Other, net" have been reclassified and are reflected as a component of
"Operating Income". These reclassifications had no effect on reported net
income.

     Additionally, we have restated our financial results for the years 1998 and
1999 as more fully discussed in Note 3 to the Consolidated Financial Statements.
The restatement is related to losses incurred in connection with the theft of
NGL product, concealment of commercial activities and other unauthorized
activities by a former


                                       42
<PAGE>


employee. As a result of the restatement, reported net income for the year 1998
is decreased by $1.0 million and reported net income for the year 1999 is
increased by $1.0 million.

     On February 5, 2002, Andersen withdrew as our independent accountant. We
were informed that Andersen's withdrawal related to Andersen's professional
standards concerns, including auditor independence issues, related to events
involving Enron. The restatement of our financial statements for the years 1998
and 1999, and the quarterly periods in 1999 and 2000, requires the issuance of
an updated audit opinion covering the years 1999 and 2000 from Andersen or the
issuance of a new audit opinion covering those years by a new independent
accountant. Since Andersen has advised us they will not issue an updated opinion
due to the independence issues related to their resignation, and PWC's
engagement for purposes of this Annual Report is presently limited to an audit
of 2001, we are filing unaudited financial statements for the years 1999 and
2000 with this Annual Report. We have requested PWC to consider auditing the
affected periods and they are reviewing our request. We will consider
alternatives for obtaining an audit of the affected periods as necessary. We can
make no assurances that we will be able to obtain an audit of the affected
periods. The independent auditors' reports of Andersen on our financial
statements during 1999 and 2000 did not contain an adverse opinion or a
disclaimer of opinion, and were not qualified or modified as to uncertainty,
audit scope or accounting principles. However, the restated financial statements
for 1999 and 2000 contained in this annual report are not covered by an audit
report or opinion of any kind. See Item 6. Selected Financial Data (Unaudited).

     We adopted Statement of Financial Accounting Standards ("SFAS") No. 133, as
amended, and changed the method of valuing inventory used in our energy trading
activities from average cost to fair value effective January 1, 2001 (see Notes
2 and 4 to the Consolidated Financial Statements.) The net cumulative effect of
adopting these accounting changes was $1.1 million and is reflected as an
increase in net income in the Consolidated Statement of Operations.

     We reported a net loss of $15.2 million or $0.54 per diluted unit for 2001
(which includes a $29.1 million loss related to the impairment of the Toll
Conversion Agreement and the Storage Agreement with EGLI), net income of $13.8
million or $0.49 per diluted unit for 2000, and restated net income of $0.6
million or $0.02 per diluted unit for 1999. Excluding the impairment charge and
nonrecurring items, we reported net income of $13.8 million in 2001, net income
of $13.2 million in 2000 and net income of $9.3 million in 1999. The primary
factors increasing net income in 2001 were the operating results attributable to
our Liquids Operations acquired in June 2001, favorable crude oil market
conditions in the first half of 2001, elimination of certain low margin lease
volumes and sales of linefill inventory previously held in a third party
pipeline in our North American Crude Oil - East of Rockies business segment.
These increases were offset by an increase in environmental expenses and lower
volumes being transported in our Pipeline Operations and the write-off of costs
incurred in connection with the proposed recapitalization plan. In addition,
financing costs have increased due to the financing of the Liquids acquisition
in June 2001 and increased letter of credit and facility costs under the interim
credit facility with Standard Chartered.

     The $29.1 million impairment charge in the fourth quarter of 2001 resulted
from EGLI's non-performance under the Toll Conversion and Storage Agreements and
represented our total remaining investment in the agreements. Nonrecurring
income of $0.6 million in 2000 included income of $2.5 million resulting from an
insurance settlement related to the theft of NGL product in 1999, offset by
nonrecurring charges of $1.9 million, which are primarily related to severance
charges for a former officer and the closing of the remaining contract for
mid-continent NGL activities. The nonrecurring loss of $8.8 million in 1999
included a $5.2 million charge for the theft of NGL product, concealment of
commercial activities and other unauthorized actions by a former employee, $1.6
million related to realized gains and losses on liquidated contracts in the
fourth quarter of 1999 and the change in unrealized gains and losses on forward
energy trading contracts related to the mid-continent NGL activity, as well as a
$2 million severance charge for workforce reductions. Selected financial data
for our business segments are summarized below, in millions:


                                       43
<PAGE>


<Table>
<Caption>


                                                      Year Ended December 31,
                                                -----------------------------------
                                                  2001          2000         1999
                                                ---------    ---------    ---------
Revenues: ....................................                            (Restated)
<S>                                             <C>          <C>          <C>
      N. A. Crude Oil - East of Rockies ......  $ 8,112.3    $10,710.2    $ 8,042.8
      Pipeline Operations ....................      127.5        140.3        118.5
      Liquids Operations .....................       48.7           --           --
      West Coast Operations ..................      491.1        893.3        654.0
      Intersegment eliminations ..............     (170.7)      (129.8)      (150.9)
                                                ---------    ---------    ---------
        Total ................................  $ 8,608.9    $11,614.0    $ 8,664.4
                                                =========    =========    =========

Gross Profit:

      N. A. Crude Oil - East of Rockies(1) ...  $    25.2    $    18.5    $    16.3
      Pipeline Operations ....................       56.7         73.6         55.6
      Liquids Operations .....................       18.3           --           --
      West Coast Operations ..................       (0.5)         3.0          2.3
                                                ---------    ---------    ---------
        Total ................................  $    99.7    $    95.1    $    74.2
                                                =========    =========    =========

Operating Income (Loss):
      N. A. Crude Oil - East of Rockies ......  $     9.8    $     2.1    $    (1.8)
      Pipeline Operations ....................       50.0         66.3         51.0
      Liquids Operations(2) ..................      (11.9)          --           --
      West Coast Operations ..................       (4.7)        (0.4)        (1.2)
      Corporate and Other ....................      (24.9)       (22.8)       (20.0)
                                                ---------    ---------    ---------
        Total ................................  $    18.3    $    45.2    $    28.0
                                                =========    =========    =========
</Table>

     (1) Includes intersegment transportation costs from our Pipeline Operations
         segment for the transport of crude oil at published pipeline tariffs
         and purchases of crude oil inventory from our Pipeline Operations
         segment. Intersegment transportation costs and purchases of crude oil
         inventory from our Pipeline Operations segment were $103.5 million,
         $119.3 million and $89.9 million for the twelve months ended December
         31, 2001, 2000 and 1999, respectively.

     (2) Includes a $29.1 million impairment loss related to the agreements with
         EGLI.

TWELVE MONTHS ENDED DECEMBER 31, 2001 COMPARED WITH TWELVE MONTHS ENDED DECEMBER
31, 2000

     North American Crude Oil - East of Rockies. Operating income from our North
American Crude Oil - East of Rockies segment increased $7.7 million to $9.8
million in 2001 compared to operating income of $2.1 million in 2000. Gross
profit increased $6.7 million to $25.2 million due primarily to improved market
conditions in the first half of 2001, the elimination of certain low margin
crude oil lease volumes, sales of line-fill inventory previously held in a third
party pipeline which was taken out of service, lower repairs and maintenance
costs related to our fleet operations and lower depreciation. Intersegment costs
charged by our Pipeline Operations segment were $103.5 million and $119.3
million for the years ended December 31, 2001 and 2000, respectively. Lease
crude oil purchases averaged 361,000 barrels per day ("bpd") for 2001, compared
to an average of 408,200 bpd in 2000.

     Pipeline Operations. Operating income from our Pipeline Operations declined
$16.3 million to $50.0 million in 2001 compared to $66.3 million in 2000,
reflecting declines in revenues on lower volumes transported and higher
operating expenses, primarily related to environmental remediation. Revenues
decreased $12.8 million to $127.5 million in 2001 due primarily to a decline in
volumes transported to 511,100 bpd in 2001 compared to 561,500 bpd in 2000. The
decline in volumes is primarily associated with the elimination of low margin
lease volumes in the North American Crude Oil - East of Rockies business
segment. Approximately $103.5 million or 81% and $119.3 million or 85% of
revenues for the years ended December 31, 2001 and 2000, respectively, were


                                       44
<PAGE>


generated from tariffs charged to our North American Crude Oil segment and sales
of crude oil inventory to our North American Crude Oil segment. Operating
expenses of $68.2 million in 2001 were $5.1 million higher than in 2000 due
primarily to higher environmental expenses related to the EPA 308 information
request and revised estimates to complete existing remediation plans based on
information currently available, partially offset by lower ad valorem taxes.

     Liquids Operations. Our Liquids Operations, acquired in June 2001,
generated $18.3 million of gross profit and operating income of $17.2 million in
2001, excluding the $29.1 million impairment resulting from EGLI's
non-performance under the Toll Conversion and Storage Agreements. The contract
impairment represents our remaining investment in these contracts. Revenues for
the six months ended December 31, 2001 include $37.5 million of processing and
storage fees from the Toll Conversion Agreement and the Storage Agreement. As a
result of the EGLI bankruptcy, we took over commercial operations of the MTBE
Plant; however, until the Storage Agreement was rejected we could not enter into
any third party storage contracts. As a result, we could only charge an
administrative fee to EGLI of approximately $0.5 million for December 2001
related to the Storage Agreement. For the six months ended December 31, 2001,
the MTBE Plant volumes averaged 15,773 bpd and the Mont Belvieu Facility moved
an average of 140,900 bpd.

     West Coast Operations. Our West Coast Operations had an operating loss of
$4.7 million in 2001 compared to an operating loss of $0.4 million in 2000. Our
West Coast Operations had nonrecurring income of $1.3 million for 2000 which
includes $2.5 million attributable to reimbursements received in the second
quarter of 2000 in connection with an insurance claim related to the theft of
NGL product in 1999 by a former employee offset by charges of $1.2 million
related to the remaining contracts for the NGL activity. The significant decline
in gross profit, excluding nonrecurring items, is due to the sale of the crude
oil gathering assets in June 2001, strong market conditions for the marketing of
refined products and the fractionation of natural gas liquids in 2000 offset by
lower operating expenses in 2001 due primarily to the sale of the crude oil
gathering and marketing assets.

     Corporate and Other. Our Corporate and other costs of $24.9 million for
2001 were $2.1 million higher compared to 2000 due primarily to the write-off of
costs incurred related to our proposed recapitalization plan, which was
terminated as a result of the Enron bankruptcy, and costs incurred to close the
interim credit facility. Interest and related charges, net for 2001 were $34.0
million compared to $28.8 million in 2000 due to higher short-term borrowings to
finance crude oil stored as a result of the market being in contango, the
financing of the Liquids assets in June 2001 and higher letter of credit costs
and facility fees under the new interim credit facility. Other income (expense),
net, consisting primarily of discount fees on the sale of receivables, and gains
(losses) on transactions denominated in foreign currency, decreased $2.1 million
to an expense of $0.5 million in 2001 primarily due to a change in the
accounting for transfers of certain receivables. Prior to March 31, 2001, such
transfers were accounted for as sales under the provisions of SFAS No. 125 and
the related costs were reflected in other income (expense), net. Subsequent to
that date, the transfers are being accounted for as financings under the
provisions of SFAS No. 140 with the related costs being included in interest
expense.

TWELVE MONTHS ENDED DECEMBER 31, 2000 COMPARED WITH TWELVE MONTHS ENDED DECEMBER
31, 1999

     North American Crude Oil - East of Rockies. Our North American Crude Oil -
East of Rockies segment had operating income of $2.1 million in 2000 compared to
an operating loss of $1.8 million in 1999. Gross profit increased $2.2 million
to $18.5 million due primarily to the improved market conditions, continued
optimization of crude oil bulk sales activities, the elimination of certain low
margin crude oil lease volumes and lower employee related costs and amortization
expense. These increases were partially offset by increased gasoline and diesel
costs. Intersegment costs charged by our Pipeline Operations segment were $119.3
million and $89.9 million for the years ended December 31, 2000 and 1999,
respectively. Lease crude oil purchases averaged 408,200 bpd for 2000,
substantially unchanged from the annual average of 408,800 bpd in 1999.


                                       45
<PAGE>


     Pipeline Operations. Our Pipeline Operations had operating income of $66.3
million in 2000 compared to $51.0 million in 1999. Revenues increased $21.8
million to $140.3 million in 2000 due primarily to increased activity related to
the acquisition of pipelines from Tex-New Mex. Approximately $119.3 million or
85% and $89.9 million or 76% of revenues for the years ended December 31, 2000
and 1999, respectively, were generated from tariffs charged to our North
American Crude Oil segment and sales of crude oil inventory to our North
American Crude Oil segment. Pipeline volumes were 561,500 bpd in 2000 compared
to 513,700 bpd in 1999. Operating expenses of $63.1 million in 2000 were $3.0
million higher than 1999 due primarily to owning the assets acquired from
Tex-New Mex for a full year, as well as higher energy and environmental costs.

     West Coast Operations. Our West Coast Operations had an operating loss of
$0.4 million in 2000 compared to an operating loss of $1.2 million in 1999.
Excluding nonrecurring items, our West Coast Operations had an operating loss of
$1.7 million in 2000 compared to recurring operating income of $5.6 million for
1999. Nonrecurring income for 2000 includes $2.5 million attributable to
reimbursements received in the second quarter of 2000 in connection with an
insurance claim related to the theft of NGL product in 1999 by a former employee
offset by charges of $1.2 million related to the remaining contracts for the
mid-continent NGL activity. Nonrecurring charges for 1999 reflect a $5.2 million
charge for the theft of NGL product, concealment of commercial activities and
other unauthorized actions by a former employee and $1.6 million related to
realized gains and losses on liquidated contracts in the fourth quarter of 1999
and the change in unrealized gains and losses on forward energy trading
contracts for the mid-continent NGL activity. The mid-continent NGL activity
originally served as a supply source for the West Coast crude oil blend
operations prior to the acquisition of assets from Koch. The significant decline
in gross profit, excluding nonrecurring items, is due to the limited
availability of blend stock for the crude oil operations as a result of the high
prices for natural gas during 2000 and higher third party truck transportation
costs and plant fuel costs.

     Corporate and Other. Our corporate and other costs of $22.8 million for
2000 were $2.8 million higher compared to 1999 due primarily to higher employee
related costs and depreciation partially offset by lower system operating costs.
Interest and related charges, net for 2000 were $28.8 million compared to $28.9
million in 1999. Other income (expense), net, consisting primarily of discount
fees on the sale of receivables and gains (losses) on transactions denominated
in foreign currency, decreased $2.4 million to an expense of $2.6 million in
2000 primarily due to higher discount fees on the sale of receivables incurred
in 2000 and losses on transactions denominated in foreign currency.

LIQUIDITY AND CAPITAL RESOURCES

General

     We anticipate that our cash requirements, including sustaining capital
expenditures for the foreseeable future, will be funded primarily by cash
generated from operations. Additionally, we anticipate that short-term liquidity
and working capital requirements will be supported by our credit facility,
inventory repurchase agreement and receivables agreement, as amended and
extended in April 2002. The bankruptcy of Enron and certain of its subsidiaries
has had a significant impact on our financing alternatives. For further detail,
see "Working Capital and Credit Resources" below.

Cash Flows From Operating Activities

     Net cash used in operating activities totaled $54.6 million in 2001
compared to $154.2 million provided by operating activities in 2000. A portion
of the decrease in cash from operations in 2001 reflects the change in
accounting for the transfer of certain receivables under a receivables
agreement. Prior to March 31, 2001, such transfers were accounted for as sales
under the provisions of SFAS No. 125. Transfers after March 31, 2001, are
accounted for as financings under the provisions of SFAS No. 140. As a result of
this change, cash flows from operations in 2001 reflect a $45.0 million
reduction in cash (reflecting receivables transferred at December 31, 2001) and
cash flows from financing activities reflect a $42.5 million increase in cash
(reflecting receivables transferred at


                                       46
<PAGE>


December 31, 2001). The remaining decrease in operating cash flow is primarily
attributable to a decline in trade and other accounts payable and an increase in
margin deposits with commodity brokers.

Cash Flows From Investing Activities

     Net cash used in investing activities totaled $136.0 million in 2001
compared to $12.6 million in 2000. Cash paid for acquisitions of $117.0 million
relates to the acquisitions of the liquids assets in June 2001. Cash additions
to property, plant, and equipment of $36.2 million in 2001 primarily include
$30.1 million for pipeline, storage tank and related facility improvements, $1.6
million related to the MTBE Plant, and $1.5 million for information systems
hardware and software. Proceeds from asset sales were $17.2 million in 2001
compared to $1.6 million in 2000. The increase is primarily due to the sale of
the West Coast crude oil gathering and marketing operations.

     We estimate that capital expenditures necessary to maintain the existing
asset base at current operating levels will be approximately $10 million to $14
million each year. Additionally, during 2002, we anticipate that we will spend
approximately $20 million on currently committed expansion capital projects and
$8 million on a major plant turn-around at our MTBE Plant. The level of
additional capital expenditures by us will vary depending upon cash from
operations, availability of financing, prevailing energy markets, general
economic conditions and the current regulatory environment.

Cash Flows From Financing Activities

     Net cash provided by financing activities totaled $139.3 million in 2001
compared to $104.9 million used in financing activities in 2000. The 2001 amount
represents an increase in repurchase agreements outstanding primarily to finance
the acquisition of liquids assets, and the change in reporting our receivable
financings as discussed above, partially offset by distributions paid to
unitholders for the period October 1, 2000 through September 30, 2001.

     Cash distributions paid to unitholders were $43.2 million and $37.6 million
for 2001 and 2000, respectively. The increase of distributions paid to
unitholders in 2001 is due to cash distributions of $0.20 per unit paid to all
subordinated unitholders for the period October 1, 2000 through September 30,
2001.

Contractual Obligations

     The table below summarizes our non-cancelable long-term contractual
obligations at December 31, 2001:


                                  Payments Due

<Table>
<Caption>

                                                                                                After
                              Total       2002      2003       2004       2005       2006       2006
<S>                         <C>        <C>        <C>        <C>        <C>        <C>        <C>
11% Senior Notes            $235,000   $     --   $     --   $     --   $     --   $     --   $235,000
Operating Leases              20,756      5,602      4,719      3,705      3,209      2,577        944
                            --------   --------   --------   --------   --------   --------   --------
                            $255,756   $  5,602   $  4,719   $  3,705   $  3,209   $  2,577   $235,944
                            ========   ========   ========   ========   ========   ========   ========
</Table>



                                       47
<PAGE>


Working Capital and Credit Resources

     The Partnership had a credit facility with Enron to provide credit support
in the form of guarantees, letters of credit and working capital loans through
December 31, 2001. The total amount of the Enron facility was $1.0 billion, and
it contained sublimits of $100 million for working capital loans and $900
million for guarantees and letters of credit. Letter of credit fees were based
on actual charges by the banks which range from .20% to .375% per annum.
Interest on outstanding loans was charged at LIBOR plus 250 basis points per
annum.

     On November 30, 2001, we entered into an interim credit facility with
Standard Chartered, our primary lender, for the purpose of replacing our
existing credit facility with Enron. This interim facility provided for the
issuance through March 2002 of up to $150 million of letters of credit. On
December 21, 2001, we increased this interim credit facility ("Credit Facility")
to $300 million, which includes a $40 million limit for working capital loans,
and the facility was extended to April 30, 2002. The Credit Facility was amended
and extended as discussed below.

     The Credit Facility was subject to defined borrowing base limitations and
included provisions restricting distributions to unitholders. The Credit
Facility was secured by a security interest in all of our unencumbered current
and fixed assets. Letter of credit fees were 1.5% per annum. Interest on
outstanding loans was charged at LIBOR plus 3%.

     In addition, we have an agreement with SCTS, which provides for the
financing of purchases of crude oil inventory utilizing forward commodity
repurchase agreements ("Inventory Repurchase Agreement"). At December 31, 2001,
we had outstanding repurchase agreements of approximately $100 million. Pursuant
to the agreements, which had terms of thirty-three days, EOTT repurchased the
crude oil inventory on January 23, 2002 for approximately $100.2 million. At
December 31, 2000, there were no repurchase agreements outstanding.

     We also have an agreement with SCTS which provides for the transfer of up
to an aggregate amount of $100 million of certain trade receivables
("Receivables Agreement") outstanding at any one time. As of December 31, 2001
and 2000, $42.5 million, and $45.0 million, respectively, of receivables had
been transferred under this agreement. In 2000, we accounted for these
transactions as sales under the provisions of SFAS No. 125. These transactions
did not qualify as sales under SFAS No. 140 and therefore are accounted for as
financings at December 31, 2001.

     In connection with the June 2001 acquisition of certain liquids assets, the
Inventory Repurchase Agreement and Receivable Agreement were increased to an
aggregate amount of $300 million on an interim basis until long-term financing
could be obtained. In connection with the extension of these agreements in
February 2002 discussed below, the aggregate amount under these facilities was
reduced to the combined original amount of $200 million. We have not been able
to refinance these liquids assets on a longer-term basis and any refinancing
will be at higher interest rates than we would have incurred prior to the Enron
bankruptcy.

     In February 2002, we received a commitment from Standard Chartered and SCTS
to amend and extend our Credit Facility as well as our Inventory Repurchase
Agreement and Receivables Agreement to February 2003 (collectively, "the
Facilities"). The extension of the Facilities was effective April 23, 2002. The
arrangement fee will be 2% of the Facilities. The amended Inventory Repurchase
Agreement and Receivables Agreement bear interest at LIBOR plus 3%.

     The Credit Facility, as amended, is subject to defined borrowing base
limitations. The borrowing base is the sum of cash and equivalents, specified
percentages of eligible receivables, inventory, products contracted for or
delivered but not billed and a specified percentage of eligible fixed assets.
Letter of credit fees will be up to 3% per annum. The commitment fee will be
0.5% per annum of the unused portion of the Credit Facility. We may elect that
loans under the Credit Facility bear an interest at a rate per annum equal to
the alternative base rate, as


                                       48
<PAGE>


defined in the amended Credit Facility or LIBOR plus 3%. The alternative base
rate is defined in the amended Credit Facility to mean 3% per annum plus the
higher of (a) the annual rate of interest announced from time to time by
Standard Chartered as its base rate or (b) 1/2 of 1% above the overnight Federal
Funds rate, as published by the Federal Reserve Bank of New York.

     The Credit Facility includes covenants and restrictions primarily related
to distributions to unitholders, amount of permitted expansion capital and
specified quarterly amounts for earnings before interest, depreciation and
amortization, net income and tangible net worth. Distributions to unitholders
cannot be made until all of the following occur: (i) we permanently reduce our
aggregate obligations to Standard Chartered and SCTS to an amount not exceeding
$300 million; (ii) our consolidated net worth is $10 million greater than our
consolidated net worth as of January 31, 2002, excluding any non-cash asset
write-downs incurred after January 31, 2002; and (iii) we resolve certain claims
(trade and other payables) by Enron and its affiliates against us related to
Enron's bankruptcy proceedings.

     At December 31, 2001, we had $196.1 million in letters of credit
outstanding under the Credit Facility. At December 31, 2000, we had $103.3
million in letters of credit outstanding under the Enron facility. In addition,
guarantees outstanding as of December 31, 2000 totaled $537.5 million.

     On September 29, 1999, we issued 3,500,000 common units to the public, with
net proceeds to EOTT of $52.9 million. On October 1, 1999, we issued to the
public $235 million of 11% senior notes. The senior notes are due October 1,
2009, and interest is paid semiannually on April 1 and October 1. The senior
notes are fully and unconditionally guaranteed by all of our operating limited
partnerships. On or after October 1, 2004, we may redeem the notes, and prior to
October 1, 2002, we may redeem up to 35% of the notes with proceeds of public or
private sales of equity at specified redemption prices. Provisions of the senior
notes could limit additional borrowings, sale and lease back transactions,
affiliate transactions, distributions to unitholders or merger, consolidation or
sale of assets if certain financial performance ratios are not met. The net
proceeds from the issuance of the 11% senior notes and the issuance of the
common units were used to repay loans and short-term borrowings from Enron.

     Prior to the Enron bankruptcy, we believed that the Credit Facility,
Inventory Repurchase Agreement and Receivables Agreement would have been
sufficient to support the Partnership's purchasing activities and working
capital and liquidity requirements had the recapitalization plan been
consummated. However, as a result of Enron's bankruptcy and in part as a result
of the increase in crude oil prices, some of our trade creditors have been less
willing than before the Enron bankruptcy to extend credit to us on an unsecured
basis, and the amount of letters of credit we have been required to post
increased from $196.1 million at December 31, 2001 to $243.5 million at March
31, 2002. Subsequent to year-end, due to the impacts of the Enron bankruptcy as
well as the rise in crude oil prices, we have had to reduce our marketing
activities due to the lack of sufficient credit support available under the
Credit Facility.

     Our ability to obtain letters of credit to support our purchases of crude
oil or other petroleum products is fundamental to our gathering and marketing
activities. Additionally, we have a significant need for working capital due to
the large dollar volume of our marketing transactions. No assurance can be given
that we will not be required to further reduce or restrict our gathering and
marketing activities because of limitations on our ability to obtain credit
support and financing for our working capital needs. Any significant decrease in
our financial strength, regardless of the reason for such decrease, may also
increase the number of transactions requiring letters of credit or other
financial support, may make it more difficult for us to obtain such letters of
credit, and/or may increase the cost of obtaining them in the future. This could
in turn adversely affect our ability to maintain or increase our level of
purchasing and marketing activities or otherwise adversely affect our
profitability and Available Cash, as defined in the MLP's Partnership Agreement
and amendments thereto and thus, our ability to meet the conditions necessary to
make distributions.


                                       49
<PAGE>


     Under the Partnership Agreement, it is intended that we distribute 100% of
our Available Cash, as defined in the Partnership Agreement, within 45 days
after the end of each quarter to unitholders of record and to the General
Partner. Available Cash consists generally of all of our cash receipts adjusted
for our cash disbursements and net changes to reserves. The full definition of
Available Cash is set forth in the Partnership Agreement and amendments thereto,
forms of which have been previously filed with the SEC. From Available Cash, we
are required to make a minimum quarterly distribution to the General Partner and
the holders of our common units. The minimum quarterly distribution is currently
measured at $0.475 per common unit, distributed 98.02% to the holders of our
common units and 1.98% to our General Partner. If we fail to make the entire
minimum distribution in any quarter, the part of distribution not made is
accounted for as an "arrearage." If, in any quarter, we have Available Cash in
excess of the minimum quarterly distribution, we are required to make the
minimum quarterly distribution and then repay the arrearage to holders of our
common units, before making a distribution to the holders of the subordinated
units or the APIs.

     Under a support agreement with Enron, Enron committed to provide total cash
distribution support in an amount necessary to pay minimum quarterly
distributions, with respect to quarters ending on or before December 31, 2001,
in an amount up to an aggregate of $29.1 million in exchange for additional
partnership interests ("APIs"). Because of the bankruptcy of Enron and certain
of its subsidiaries and the resulting uncertainty related to our term financing
and working capital facilities, along with the continued weakness in the crude
markets, projected expenditure requirements related to scheduled turnaround
costs for our MTBE Plant and certain capital expansion projects currently
underway, the distribution for the fourth quarter of 2001 of $0.25 per common
unit was lower than the minimum quarterly distribution amount of $0.475 per
common unit. Enron did not pay the fourth quarter distribution shortfall of
$0.225 per common unit. We expect to submit a claim for the distribution support
amount of $4.2 million through the bankruptcy proceedings, though we can make no
assurances we will recover any of such amount. See further discussion in Note 10
to the Consolidated Financial Statements.

     On April 3, 2002, we suspended the distribution to limited partners for the
first quarter of 2002. The decision to not pay a distribution for the first
quarter of 2002 was based on cash flow from operations for the first quarter of
2002, impact of the scheduled turnaround of the MTBE Plant and our need to
preserve financial resources to finance previously committed capital
expenditures given our current situation, which has made third party financing
difficult to obtain on reasonable terms.

     As previously discussed, under the Credit Facility, our ability to pay
distributions to our limited partners is restricted. In any event, we do not
expect to make any distributions to our unitholders prior to the fourth quarter
of 2002.

Summarized Financial Information Concerning our General Partner

     EOTT Energy Corp., a wholly-owned subsidiary of Enron that is not in
bankruptcy, serves as our General Partner. Prior to filing its bankruptcy
petition, Enron was a publicly traded company listed on the New York Stock
Exchange. As a result of the bankruptcy, Enron's stock was suspended from
trading on the New York Stock Exchange and is currently traded in the National
Quotation Bureau, LLC "Pink Sheets." Beginning on December 2, 2001, Enron and
certain other subsidiaries of Enron each filed voluntary petitions for relief
under Chapter 11 of Title 11 of the United States Code with the Bankruptcy
Court. As stated by Enron in a Form 8-K filed with the U.S. Securities and
Exchange Commission on February 12, 2002, in connection with Enron's
restructuring, Enron believes that the total amount of the liquidated,
undisputed claims against Enron and its subsidiaries exceeds and will exceed the
current fair market value of the consolidated operations and assets of Enron and
its subsidiaries. Enron further stated that it believes the existing equity of
Enron has and will have no value and that any Chapter 11 plan confirmed by the
Bankruptcy Court will not provide Enron's existing equity with any interest in
the reorganized debtor. Numerous shareholder and employee class action lawsuits
have been filed against Enron, its former independent accountants, legal
advisors, present and former executives, and present and former board members.
Investigations of Enron have also been commenced by several Congressional
committees and state and


                                       50
<PAGE>


federal regulators, including FERC. Additionally, Enron and certain of its
subsidiaries and several former officers were suspended in March 2002 by the
General Services Administration from contracting with the Federal government.
Information about Enron can be obtained from its filings with the U.S.
Securities and Exchange Commission pursuant to the Securities Exchange Act of
1934 and the Bankruptcy Court and from its website, www.enron.com.

     Currently, our General Partner is not a party to the Chapter 11 filings by
Enron and certain of its subsidiaries. No assurances, however, can be made that
our General Partner will not be included in the Chapter 11 filings. Inclusion of
our General Partner in Enron's Chapter 11 filings would have a materially
adverse effect on us. For further information concerning the impact of Enron's
bankruptcy, see "Impact of the Bankruptcy of Enron and Certain of Its
Subsidiaries, and Related Events."

     Based upon information provided by Enron, summary unaudited financial
information of the General Partner for 2001 and 2000 is shown below, in
thousands:


<Table>
<Caption>

                                                            Year Ended December 31,
                                                            -----------------------
                                                              2001(2)       2000
                                                            ----------   ----------
<S>                                                         <C>          <C>
Balance Sheet Data (at end of period)(1)
  Total assets .............................................   $43,657   $60,328
  Total liabilities ........................................   $42,775   $ 9,979
  Shareholder's equity .....................................   $   882   $50,349

Income Statement Data:
  Net income ...............................................   $ 7,106   $ 1,159
</Table>

(1) Total receivables of $56.2 million due to the General Partner from Enron at
December 31, 2001, have been classified by the General Partner as an offset
against shareholder's equity as a result of Enron's bankruptcy.

(2) During 2001, Enron, which owns 100% of the General Partner, effected a
transfer of substantially all of the General Partner's investment (7 million
subordinated units) in the Partnership.

NEW ACCOUNTING STANDARDS

     In July 2001, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (SFAS) No. 142, "Goodwill and Other
Intangible Assets." SFAS No. 142, which must be applied to fiscal years
beginning after December 15, 2001, modifies the accounting and reporting of
goodwill and intangible assets. The pronouncement requires entities to
discontinue the amortization of goodwill, reallocate all existing goodwill among
its reporting segments based on criteria set by SFAS No. 142 and perform initial
impairment tests by applying a fair value-based analysis on the goodwill in each
reporting segment. Any impairment at the initial adoption date shall be
recognized as the effect of a change in accounting principle. Subsequent to the
initial adoption, goodwill shall be tested for impairment annually or more
frequently if circumstances indicate a possible impairment. Under SFAS No. 142,
entities are required to determine the useful life of other intangible assets
and amortize the value over the useful life. If the useful life is determined to
be indefinite, no amortization will be recorded. For intangible assets
recognized prior to the adoption of SFAS No. 142, the useful life should be
reassessed. Other intangible assets are required to be tested for impairment in
a manner similar to goodwill. While we do not expect the adoption of SFAS No.
142 to have a material impact on our results of operations, we have not yet
completed our initial impairment tests. At December 31, 2001, we had $7.4
million of net goodwill in Other Assets. Goodwill amortization totaled $1.1
million, $1.1 million and $2.0 million for the years 2001, 2000 and 1999,
respectively.


                                       51
<PAGE>


     In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations." This statement requires entities to record the fair
value of a liability for legal obligations associated with the retirement
obligations of tangible long-lived assets in the period in which it is incurred.
When the liability is initially recorded, a corresponding increase in the
carrying amount of the related long-lived asset would be recorded. Over time,
accretion of the liability is recognized each period, and the capitalized cost
is depreciated over the useful life of the related asset. Upon settlement of the
liability, an entity either settles the obligation for its recorded amount or
incurs a gain or loss on settlement. The standard is effective for fiscal years
beginning after June 15, 2002, with earlier application encouraged. We are
currently evaluating the effect on our financial statements of adopting SFAS No.
143 and plan to adopt the statement effective January 1, 2003.

     In August 2001, the FASB issued SFAS No. 144, "Accounting for Impairment or
Disposal of Long-Lived Assets." This statement clarified the financial
accounting and reporting for the impairment or disposal of long-lived assets.
Impairment is required to be recognized if the carrying amount of a long-lived
asset is not recoverable from its undiscounted cash flows. The impairment loss
to be recognized is the difference between the carrying amount and the fair
value of the asset. The standard also provides guidance on the accounting for
the long-lived assets that are held for disposal. This standard is effective for
the Partnership beginning January 1, 2002. The adoption of SFAS No. 144 did not
have a material impact on our results of operations or financial condition.

     In April 2002, the FASB issued SFAS No. 145 "Rescission of FASB Statements
No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical
Corrections." SFAS No. 145 rescinds SFAS No. 4, "Reporting Gains and Losses from
Extinguishments of Debt," SFAS No. 64 "Extinguishments of Debt made to Satisfy
Sinking Fund Requirements" and SFAS No. 44, "Accounting for Intangible Assets of
Motor Carriers." The statement also amends SFAS No. 13, "Accounting For Leases"
to eliminate certain inconsistencies within that statement. SFAS 145 also makes
certain technical corrections or clarifications to other authoritative
pronouncements. Certain provisions of SFAS No. 145 are effective for
transactions occurring after or financial statements issued after May 15, 2002.
The adoption of SFAS 145 did not have a material impact on our results of
operations.

ENVIRONMENTAL MATTERS

     We are subject to federal, state and local laws and regulations governing
the discharge of materials into the environment or otherwise relating to
environmental protection. At the federal level, such laws include, among others,
the Clean Air Act, the Clean Water Act, the Oil Pollution Act, the Resource
Conservation and Recovery Act, the Comprehensive Environmental Response,
Compensation and Liability Act, and the National Environmental Policy Act, as
each may be amended from time to time. Failure to comply with these laws and
regulations may result in the assessment of administrative, civil, and criminal
penalties or the imposition of an injunctive relief. Moreover, compliance with
such laws and regulations in the future could prove to be costly, and there can
be no assurance that we will not incur such costs in material amounts.
Environmental laws and regulations have changed substantially and rapidly over
the last 20 years, and we anticipate that there will be continuing changes. The
clear trend in environmental regulation is to place more restrictions and
limitations on activities that may impact the environment, such as emissions of
pollutants, generation and disposal of wastes and use and handling of chemical
substances. Increasingly strict environmental restrictions and limitations have
resulted in increased operating costs for us and other businesses throughout the
United States, and 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.

     Enron received a request for information from the EPA under Section 308 of
the Clean Water Act requesting information regarding certain discharges and
releases from oil pipelines owned or operated by


                                       52
<PAGE>
Enron and its affiliates for the time period July 1, 1998 to July 11, 2001.
Because we are the only Enron affiliated entity with domestic crude oil
pipelines operated by Enron, Enron responded for itself and on behalf of us to
the EPA's request on January 29, 2002. At this time, we are not able to predict
the outcome of the response made to the EPA's Section 308 request.

     In connection with extensive asset purchases in 1998 and 1999, we
instituted a pipeline integrity management program in 1999. This program was
expanded in December of 2001 with a pipeline integrity assurance program to
comply with certain regulatory and legislative changes. Under this program, the
integrity of a pipeline is evaluated to avoid operating a pipeline that poses
significant risk of crude oil spills. Our written EOTT Pipeline Integrity
Program, which was intended to comply with the new OPS Integrity Management
regulations was formally implemented in January 2002. Anticipated operating
expenses and capital expenditures to comply with that program are budgeted
annually; however, actual future expenditures may be different from the amounts
currently anticipated.

     In 2001, expenses incurred for spill clean up and remediation costs related
to the assets purchased from Tex-New Mex increased significantly. Based on our
experience with these assets, we filed an amended cross-claim against Tex-New
Mex, as previously discussed, alleging contingent claims for potential
remediation issues not yet known to us. We allege that Tex-New Mex failed to
report spills, underreported spills, failed to properly respond to leaks in the
pipeline and engaged in other activities with regard to the pipeline that may
result in future remediation liabilities. We obtained $20 million in insurance
coverage in connection with the acquisition from Tex-New Mex believing that
amount would be sufficient to cover remediation requirements along the pipeline
for a ten-year period. Through December 31, 2001, approximately $14 million of
environmental costs have been recognized under the insurance policy. We have
accrued current estimates for future remediation costs on all environmental
spills or releases which occurred prior to December 31, 2001; however, actual
future expenditures may be different than amounts currently anticipated. See
further discussion of the estimated environmental liability recorded at December
31, 2001 in Note 2 to the Consolidated Financial Statements.

     The U.S. House of Representatives and the U.S. Senate introduced
legislation in February 2001 with the goal of eliminating the use of MTBE in
gasoline three years from the date of enactment. Provisions are included within
the proposed Energy Policy Act of 2002 that would ban the use of MTBE four years
post enactment. However, the proposed Energy Policy Act of 2002 also includes
provisions that would provide monetary assistance to domestic MTBE producers to
be used to defray the costs associated with the transition of current MTBE
production facilities into facilities producing MTBE substitutes. The Bush
Administration has made statements in favor of conversion for MTBE substitutes
to the use of ethanol as an alternative to MTBE. If MTBE were to be restricted
or banned in Texas or throughout the United States, we could modify the MTBE
Plant to produce other products. We believe that modifying our existing MTBE
Plant to produce other gasoline blendstocks such as alkylates could require a
substantial capital investment. We cannot be certain that we would have the
resources available to effect such a conversion or that such conversion would be
economically viable. Further, we cannot predict whether the proposed Energy
Policy Act of 2002 or other similar legislation may be passed or whether the
federal government will take steps to reverse California's ban on the use of
MTBE as a gasoline component, or if the federal government will provide monetary
assistance for conversion. If the proposed federal legislation is enacted, the
ban in California becomes effective, or Texas bans the use of MTBE, we would
expect such ban to materially reduce MTBE demand, which would have a material
adverse effect on our financial results.

     We may experience future releases of crude oil, MTBE or other substances
into the environment or discover releases that were previously unidentified.
While an inspection program is maintained on our pipelines to prevent and detect
such releases, and operational safeguards and contingency plans are in place for
the operation of our processing facilities, damages and liabilities incurred due
to any future environmental releases could affect our business. We believe that
our operations and facilities are in substantial compliance


                                       53
<PAGE>


with applicable environmental laws and regulations and that there are no
outstanding potential liabilities or claims relating to safety and environmental
matters the resolution of which, individually or in the aggregate, would have a
materially adverse effect on our financial position or results of operations.
Our environmental expenditures include amounts spent on permitting, compliance
and response plans, monitoring and spill cleanup and other remediation costs. In
addition, we could be required to spend substantial sums to ensure the integrity
of and upgrade our pipeline systems, and in some cases, we may take pipelines
out of service if we believe the cost of upgrades will exceed the value of the
pipeline in our business.

     No assurance can be given as to the ultimate amount or timing of future
expenditures for environmental remediation or compliance, and actual future
expenditures may be different from the amounts currently anticipated. In the
event of future increases in costs, we may be unable to pass on those increases
to our customers. For further details concerning important environmental matters
see "Environmental Matters" above.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

     The preparation of financial statements in conformity with accounting
principles generally accepted in the United States of America ("GAAP") requires
management to make estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of contingent assets and liabilities at
the date of the financial statements and the reported amounts of actual revenues
and expenses during the reporting period. Although we believe these estimates
are reasonable, actual results could differ from those estimates. Our
significant accounting policies are summarized in Note 2 to the Consolidated
Financial Statements included elsewhere in this report. The critical accounting
policies that we have identified are discussed below.

Revenue and Expenses

     We routinely make accruals for both revenues and expenses due to the timing
of receipt of information from third parties, reconciliation of our records with
those of third parties, claims that have been incurred but not processed and
costs that accrue over time under benefit and incentive plans. In addition,
substantially all of our crude oil and refined products gathering, marketing and
trading operations are marked to fair value pursuant to Emerging Issues Task
Force ("EITF") Issue 98-10 or SFAS No. 133. Certain estimates were made in
determining the fair value of contracts and inventory. We have determined these
estimates using available market data and valuation methodologies. We believe
our estimates for these items are reasonable, but there is no assurance that
actual amounts will not vary from estimated amounts.

Depreciation and Amortization

     We calculate our depreciation and amortization based on estimated useful
lives and salvage values of our assets. When assets are put into service, we
make estimates with respect to useful lives that we believe are reasonable.
However, factors such as competition, regulation or environmental matters could
cause us to change our estimates, thus impacting the future calculation of
depreciation and amortization.

Impairment of Assets

     We evaluate impairment of our long-lived assets in accordance with SFAS No.
121 "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of", and effective January 1, 2002 SFAS No. 144, and would
recognize an impairment when estimated future cash flows associated with an
asset or group of assets are less than the asset carrying amount. Certain assets
included in Property, Plant & Equipment ("PP&E"), primarily pipelines and the
MTBE Plant, are subject to factors which could affect future cash flows. These
factors include competition, regulation, environmental matters, consolidation in
the industry, refinery demand for specific grades of crude oil, area market
price structures and continued


                                       54
<PAGE>


developmental drilling in certain areas of the United States. We continuously
monitor these factors and pursue alternative strategies to maintain or enhance
cash flows associated with these assets; however, no assurances can be given
that we can mitigate the effects, if any, on future cash flows related to any
changes in these factors.

Contingencies

     We accrue reserves for contingent liabilities, which include environmental
remediation and potential legal claims. A loss contingency is accrued when our
assessment indicates that it is probable that a liability has been incurred and
the amount of the liability can be reasonably estimated. Our estimates are based
upon currently available facts, existing technology and presently enacted laws
and regulations. These estimated liabilities are subject to revision in future
periods based on actual costs or new information.

RISK FACTORS

     Although we believe that our expectations regarding future events are based
on reasonable assumptions, we cannot assure you that such expectations regarding
future developments will be realized. In addition to other factors and matters
discussed elsewhere in this report and although new factors emerge from time to
time and it is not possible for us to predict all such factors, the following
risk factors could cause actual results or outcomes to differ materially:

     o   Matters relating to the bankruptcy of Enron and certain of its
         subsidiaries, including without limitation the matters discussed above
         in "Impact of the Bankruptcy of Enron and Certain of Its Subsidiaries,
         and Related Events."

     o   Economic and industry factors beyond our control can adversely affect
         our gross profits. Such factors include, without limitation, production
         levels of crude oil; the performance of the U.S. and world economies;
         volumes of crude oil produced in the areas we serve; demand for oil by
         refineries and other customers; prices for crude oil at various lease
         locations; prices for crude oil futures contracts on the New York
         Mercantile Exchange; the competitive position of alternative energy
         sources; the availability of pipeline and other transportation
         facilities that may make crude oil production from other producing
         areas competitive with crude oil production that we purchase at the
         lease; and with respect to our MTBE Plant, commodity price risk, demand
         for oxygenated and reformulated gasoline and the possible enactment of
         legislation banning the use of MTBE.

     o   If we cannot maintain our volumes of crude oil purchased at the lease,
         our ability to pay cash distributions and service our debt obligations
         will be adversely affected.

     o   Our ability to maintain or increase our gross profits is dependent on
         the success of our price risk management strategies. See Item 1.
         "Business - Risk Management/Derivatives."

     o   Our performance depends on our ability to minimize bad debts and legal
         liability when extending credit to operators and customers.

     o   Our financial resources are a major consideration for parties that
         enter into transactions with us, and because of the large dollar volume
         of the marketing transactions in which we engage, we have a significant
         need for working capital. While we believe that our new credit facility
         is sufficient to support our working capital needs, any significant
         decrease in our financial strength, regardless of the reason for the
         decrease, may increase the number of transactions requiring letters of
         credit or other financial support; make it more difficult for us to
         obtain letters of credit upon expiration of our credit facility or in
         an amount greater than currently permitted by our revolving credit
         facility; make it more


                                       55
<PAGE>


         difficult to renew our credit facility upon its expiration; or increase
         the cost of obtaining letters of credit.

     o   If we do experience a further decrease in financial strength, we may be
         unable to maintain the level of our purchasing and marketing
         activities. We cannot assure you that our new credit facility will be
         adequate or that we will not be required to reduce our market
         activities because of limitations on our ability to obtain financing
         for our working capital needs.

     o   Environmental and other regulatory costs and liabilities could affect
         our cash flow. Our business is heavily regulated by federal, state and
         local agencies with respect to environmental, safety and other
         regulatory matters. This regulation increases our cost of doing
         business. We may be subject to substantial penalties if we fail to
         comply with any regulation. We cannot assure you that changes enacted
         by regulatory agencies that have jurisdiction over us will not increase
         our cost of conducting business or otherwise negatively impact our
         profitability, cash flow and financial condition. If an accidental leak
         or spill occurs in one of our pipelines, at a storage facility or from
         one of our operating units, we may have to pay a significant amount to
         clean up the leak or spill. The resulting costs and liabilities could
         negatively affect the level of cash available to pay amounts due on our
         debt and for distributions to unitholders. Although we believe that we
         are in compliance in all material respects with all applicable
         environmental laws and regulations, we could be adversely affected by
         environmental costs and liabilities that may be incurred or increased
         costs resulting from failure to obtain all required regulatory consents
         and approvals. As to all of our properties, we cannot assure you that
         past operating practices, including those that were state of the art at
         the time employed, will not result in significant future environmental
         liabilities. See Item 1. "Business - Environmental Matters" and
         "Regulation."

     o   September 11, 2001 related events may adversely affect our business. We
         are currently unable to measure the ultimate impact of the terrorist
         attacks of September 11, 2001 and the United States' military action in
         Afghanistan in response to these attacks on our industry and the United
         States economy as a whole. The uncertainty and risk of future terrorist
         activity may impact our results of operations and financial condition
         in unpredictable ways. These developments have resulted in adverse
         changes in the insurance markets and insurance premiums could be
         increased further or coverages may be unavailable in the future. These
         developments could also result in disruptions of financial, power and
         fuel markets and certain of our facilities could be directly or
         indirectly harmed by future terrorist activity. Instability in the
         financial markets may also adversely affect our ability to access
         capital. These developments could also lead to increased volatility in
         prices for crude oil, natural gas, and certain feedstocks.

     o   Cash distributions to our unitholders are not guaranteed and may
         fluctuate. We are also now subject to certain restrictions under our
         credit facility on our ability to make distributions. See Item 5.
         "Market for Registrant's Common Units and Related Security Holder
         Matters."

     o   We are a limited partnership, operated under the direction of our
         General Partner. This structure affects our common unitholders in
         various ways, including the following: the voting rights of common
         unitholders are more limited than those of holders of capital stock in
         a corporation; our common unitholders have no right to participate in
         our management and have no right to elect our General Partner or
         members of its Board of Directors; our Partnership Agreement contains
         provisions making it difficult to replace our General Partner; and our
         General Partner and its affiliates may have conflicts of interest with
         our common unitholders and with us. See "Impact of the Bankruptcy of
         Enron and Certain of Its Subsidiaries, and Related Events - Certain
         Conflicts of Interest" above.


                                       56
<PAGE>


     o   We do not have the same flexibility as corporations to accumulate cash
         and equity to protect against illiquidity in the future since under the
         Partnership Agreement, we are required to distribute 100% of our
         Available Cash.

     o   We could be treated as a corporation for United States income tax
         purposes. Our treatment as a corporation would substantially reduce the
         cash distributions on our common units. The anticipated benefit of an
         investment in our common units depends largely on the treatment of us
         as a partnership for income tax purposes. Current law may change so as
         to cause us to be treated as a corporation for United States income tax
         purposes.

ITEM 7a.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     We enter into forwards, futures and other contracts primarily for the
purpose of hedging the impact of market fluctuations on assets, liabilities or
other contractual commitments. The use of financial instruments may expose us to
market and credit risks resulting from adverse changes in commodity prices,
interest rates and foreign exchange rates. The major market risks are discussed
below.

     Commodity Price Risk. Commodity price risk is a consequence of gathering
crude oil at the lease and marketing the crude oil to refineries or other trade
partners. We use forwards, futures, swaps and options to mitigate price exposure
and manage this risk on a portfolio basis.

     Interest Rate Risk. Interest rate risk is the result of having variable
rate debt obligations, as changing interest rates impact the discounted value of
future cash flows and having fixed rate debt obligations which impact the change
in fair value.

     Foreign Currency Exchange Rate Risk. Foreign currency exchange rate risk is
the result of our Canadian operations. The primary purpose of our foreign
currency hedging activities is to protect against the volatility associated with
foreign currency purchase and sale transactions.

COMMODITY PRICE RISK

     We have performed a value at risk analysis of our financial derivative
commodity instruments. Value at risk incorporates numerous variables that could
impact the fair value of our investments, including commodity prices, as well as
correlation within and across these variables. We estimate value at risk
commodity exposures using a model based on Monte Carlo simulation of delta/gamma
positions, which captures a significant portion of the exposure related to open
futures contracts. The value at risk method utilizes a one-day holding period
and a 95% confidence level. Cross-commodity correlations are used as
appropriate. The use of the value at risk model allows management to aggregate
risks across our operations, compare risk on a consistent basis and identify the
drivers of risk.


                                       57
<PAGE>


     The following table illustrates the value at risk for commodity price risk
(in millions):

<Table>
<Caption>

                                                           Year Ended December 31,
                                                           -----------------------
                                                            2001             2000
                                                           ------           ------
<S>                                                        <C>              <C>
        Commodity price(1)...............................  $  1.3           $ 0.2
</Table>

     (1) The above value at risk amount represents financial derivative
         commodity instruments, primarily commodity futures contracts, entered
         into to hedge future physical crude oil purchase commitments. The
         commitments to purchase physical crude oil have not been included in
         the above value at risk computation.

     (2) At December 31, 2001, we had crude oil future contracts to purchase 2.6
         million barrels of crude oil and to sell 3.8 million barrels of crude
         oil, with the majority of these contracts maturing in the first quarter
         of 2002. At December 31, 2000, we had crude oil future contracts to
         purchase 8.8 million barrels of crude oil and to sell 8.6 million
         barrels of crude oil, with the majority of these contracts maturing in
         2001.

INTEREST RATE RISK

     Our exposure to changes in interest rates primarily results from our
short-term and long-term debt with both fixed and floating interest rates. The
Enron facility expired as of December 31, 2001. As of December 31, 2001,
short-term debt of $182.5 million was outstanding under our interim credit
facility with Standard Chartered. For further detail see Item 7. "Management's
Discussion and Analysis of Financial Condition and Results of Operations -
Liquidity and Capital Resources - Working Capital and Credit Resources."

     In October 1999, we issued $235 million of 11% senior notes due in 2009.
These notes are held publicly, but trade infrequently. The fair value of these
notes based upon market quotes approximated $255.3 million and $253.7 million as
of December 31, 2001 and 2000, respectively.

ACCOUNTING POLICIES

     Our accounting policies for price risk management and hedging activities
are described in Note 2 to the Consolidated Financial Statements.

ENERGY TRADING AND DERIVATIVE TRANSACTIONS ACCOUNTED FOR AT FAIR VALUE

     Generally as we purchase crude oil, we enter into corresponding sales
transactions involving physical delivery of crude oil to third party users or
corresponding sales transactions on the New York Mercantile Exchange (NYMEX).
This process enables us to minimize our exposure to price risk until we take
physical delivery of the crude oil. Substantially all of our crude oil and
refined products marketing and trading operations are accounted for on a fair
value basis pursuant to SFAS No. 133 or Emerging Issues Task Force ("EITF")
Issue 98-10. In addition, we account for inventories used in our energy trading
activities at fair value. See further discussion of our accounting policies in
Note 2 to the Consolidated Financial Statements.


                                       58
<PAGE>


     The following table indicates fair values and changes in fair value for the
year ended December 31, 2001 (in thousands):

<Table>


<S>                                                                    <C>
Fair value of contracts at December 31, 2000                           $  (470)
Change in realized and unrealized value                                   (702)
Fair value of new contracts entered into during 2001                    (4,425)
                                                                       -------
Fair value of contracts at December 31, 2001                           $(5,597)*
                                                                       -------
</Table>

*Approximately $2.6 million of the fair value loss at December 31, 2001 relates
to physical sales transactions or sales transactions on the NYMEX entered into
to hedge physical inventory. The fair value of inventory is not included in the
table above.

FAIR VALUE OF CONTRACTS AT DECEMBER 31, 2001

<Table>
<Caption>

                                                                    Maturity greater than
                                                 Maturity of 90     90 days but less than
         Source of Fair Value                     days or less             one year             Total Fair Value
         --------------------                    --------------    ----------------------       ----------------
<S>                                              <C>               <C>                          <C>
     Prices Actively Quoted                        $(3,613)                 $  (876)                $(4,489)

     *Prices Provided by other
     External Source                                  (765)                    (343)                 (1,108)
                                                   -------                  -------                 -------
     Total                                         $(4,378)                  (1,219)                $(5,597)
                                                   =======                  =======                 =======

</Table>

*In determining the fair value of certain contracts, adjustments may be made to
published posting data, for location differentials and quality basis
adjustments.

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

     The information required hereunder is included in this report as set forth
in the "Index to Financial Statements" on page F-1.

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

     As previously set forth in a Form 8-K filed with the SEC on February 11,
2002, Andersen withdrew as our independent accountant on February 5, 2002. We
have been informed that Andersen's withdrawal relates to Andersen's professional
standards concerns, including auditor independence issues, relating to events
involving Enron. The independent auditor's reports of Andersen on our financial
statements during the two most recent fiscal years did not contain an adverse
opinion or a disclaimer of opinion, and were not qualified or modified as to
uncertainty, audit scope or accounting principles. Andersen has indicated that
they have not withdrawn any of their opinions expressed in their auditor's
reports for any periods for which they conducted our audits.

     As discussed in Note 3 to the Consolidated Financial Statements, in
response to certain SEC comments, we are restating prior year financial results.
The restatement of our financial statements for the years 1998 and 1999, and the
quarterly periods in 1999 and 2000, requires the issuance of an updated audit
opinion covering the years 1999 and 2000 from Andersen or the issuance of a new
audit opinion covering those years by a new


                                       59
<PAGE>


independent accountant. Andersen has advised us that they will not issue an
updated opinion due to the independence issues related to their resignation.

     During our two most recent fiscal years and through the date of Andersen's
withdrawal, we did not have any disagreements with Andersen on any matter of
accounting principles or practices, financial statement disclosure, or auditing
scope or procedure, which if not resolved to the satisfaction of Andersen, would
have caused Andersen to make reference to the subject matter thereof in
connection with its independent auditors report.

     Except to the extent discussed below, during the two most recent fiscal
years and through the date of Andersen's withdrawal, there were no "reportable
events" within the meaning of Item 304(a)(1)(v) of Regulation S-K.

     SEC rules applicable to the withdrawal of Andersen as our independent
auditor require the reporting of certain events. In this case, such an event
occurred in the first quarter of 2000 and was previously disclosed in our first
quarter 10-Q/A for 2000 and Form 10-K for 2000. At that time, we identified
certain systems integration issues related to the implementation of our new
computerized marketing and accounting system and immediately commenced an
extensive review and analysis of the implementation of the system. As a result
of the review, we implemented additional control processes and procedures that
we believed were sufficient to permit the preparation of timely and accurate
financial information, including additional preventative and monitoring controls
to ensure the integrity and reliability of financial information generated by
the system as well as additional system training for users. Related to
Andersen's audit for the year ended December 31, 2000, Andersen believed these
issues to be material weaknesses in the internal controls necessary for us to
develop accurate financial statements. These matters were considered by Andersen
during their audit and did not modify the opinion expressed in their auditor's
report to us dated March 2, 2001. During that audit, Andersen developed and
performed testing procedures to support our assertion that the material
weaknesses had been addressed. The results of those testing procedures
corroborated our assertions that all of the previously identified material
weaknesses had been mitigated. The audit committee of the Board of Directors of
our General Partner discussed these matters with Andersen, but there was no
difference of opinion with Andersen regarding these issues.

     As required by Item 304(a)(3) of Regulation S-K, we furnished Andersen with
the disclosure contained in Item 4 of the Form 8-K filed with the SEC on
February 11, 2002 and requested that Andersen furnish us with a letter addressed
to the SEC stating that it agrees with the statements made therein by us. A copy
of Andersen's letter dated February 11, 2002, is included as Exhibit 16.1 to the
Form 8-K and is incorporated by reference herein.

     On March 25, 2002, the Board of Directors of our General Partner authorized
the engagement of PWC as our independent accountant to replace Andersen. PWC
began its audit of our 2001 results immediately; however, PWC's engagement was
dependent on our reconstitution of an independent audit committee. On April 10,
2002, Messrs. Matthews, Lovett and Tidwell were elected to the Board of
Directors of our General Partner and as independent directors for the audit
committee. The members of the reconstituted independent audit committee were
considered acceptable by PWC's engagement acceptance process, and the audit
committee formally engaged PWC.

     We did not consult with PWC with regard to (i) any matter concerning the
application of accounting principles to any specific transactions, either
completed or proposed, or the type of audit opinion that might be rendered with
respect to our financial statements; or (ii) any matter that was either the
subject of a "disagreement," as that term is defined in Item 304 of Regulation
S-K and the related instructions applicable to Item 304 of Regulation S-K, or a
"reportable event," as that term is defined in Item 304(a)(1)(v) of Regulation
S-K.



                                       60
<PAGE>



                                    PART III

ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

     We do not directly employ any persons responsible for managing or operating
the Partnership or for providing services relating to our day-to-day business
affairs. Our General Partner provides such services or obtains such services
from third parties or its affiliates. We are responsible for reimbursing our
General Partner for all of its direct and indirect costs and expenses including
compensation and benefit costs related to the Partnership.

     The Board of Directors of our General Partner established a committee (the
"Audit Committee") consisting of three individuals who are neither officers nor
employees of our General Partner or any affiliate of our General Partner (the
"Independent Directors"). The Audit Committee has the authority to review, at
the request of our General Partner, 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 is fair and reasonable to us. In addition, the
Audit Committee has the authority and responsibility for selecting our
independent public accountants, reviewing our annual audit and resolving
accounting policy questions.

     On November 28, 2001, two of the three Independent Directors of the Board
of Directors of our General Partner, Mr. Edward O. Gaylord and Mr. Dee S.
Osborne, resigned from the Board of Directors of our General Partner. On
December 5, 2001, Mr. Daniel P. Whitty resigned as an Independent Director of
the Board of Directors of our General Partner. In addition, Mr. John M. Duncan,
an interlocking director with Enron, resigned from the Board of Directors of our
General Partner on February 13, 2002.

     On April 10, 2002, Mr. Thomas M. Matthews, Mr. H. Malcolm Lovett, Jr., and
Mr. James M. Tidwell joined the Board of Directors of our General Partner as
Independent Directors. Messrs. Matthews, Lovett, and Tidwell will comprise all
of the members of the Audit Committee, the Compensation Committee and our new
Restructuring Committee. In addition, our General Partner restructured its Board
of Directors from seven members to five, three of which must be Independent
Directors.


                                       61
<PAGE>


DIRECTORS AND EXECUTIVE OFFICERS OF THE GENERAL PARTNER

     Set forth below is certain information concerning the directors and
executive officers of our General Partner. All directors of the General Partner
are elected annually by and may be removed by Enron, as the sole shareholder of
our General Partner. All executive officers serve at the discretion of the Board
of Directors of our General Partner.

<Table>
<Caption>

                                                  Years Employed
                                                    by Enron or
                Name                     Age     its Subsidiaries              Position
                ----                     ---     ----------------              --------
<S>                                      <C>     <C>                    <C>
    Thomas M. Matthews..............     58             --              Chairman of the Board
    H. Malcolm Lovett, Jr...........     56             --              Director
    James M. Tidwell................     55             --              Director
    Stanley C. Horton...............     51             28              Director
    Roderick Hayslett ..............     57             24              Director
    Dana R. Gibbs ..................     42              9              Chief Executive Officer, President, and Chief
                                                                        Operating Officer
    Lawrence Clayton, Jr. ..........     48              1              Senior Vice President and Chief Financial Officer
    Mary Ellen Coombe...............     51             21              Vice President, Human Resources and Administration
    Molly M. Sample.................     46             10              Vice President and General Counsel
    Lori L. Maddox..................     37              5              Vice President and Controller
</Table>

     Thomas M. Matthews was elected to the EOTT Energy Corp. Board of Directors
and Chairman of the Board and Chairman of the Restructuring Committee in April
2002. Mr. Matthews provides consulting services to various groups. He served as
the Chief Executive Office of Avista Corp. from July 1998 to January 2001. Mr.
Matthews served as President of Dynegy, Inc. from November 1996 to June 1998. In
addition, Mr. Matthews serves on the boards of Environmental Power Corporation
and Global Water Technologies.

     H. Malcolm Lovett, Jr. was elected to the EOTT Energy Corp. Board of
Directors and Chairman of the Compensation Committee in April 2002. Mr. Lovett
has served as Chairman and Chief Executive Officer of Strategic Capital
Corporation since 1996. He served as a private financial advisor and consultant
from 1990 to 1995. Mr. Lovett founded Lovett Mitchell Webb & Garrison, Inc. and
served as its Chairman and Chief Executive Officer from 1981 until 1987 before
it was sold to the Kemper Insurance Companies.

     James M. Tidwell was elected to the EOTT Energy Corp. Board of Directors
and Chairman of the Audit Committee in April 2002. Mr. Tidwell has served as
Vice President, Finance and Chief Financial Officer of WEDGE Group Incorporated
since January 2000. Mr. Tidwell served as President of Daniel Measurement &
Control from June 1999 to January 2000, and as Executive Vice President and
Chief Financial Officer of Daniel Industries, Inc. from August 1996 to June
1999, before its acquisition by Emerson Electric. In addition, Mr. Tidwell
serves on the boards of Pioneer Drilling Company and T3 Energy Services.

     Stanley C. Horton was elected to the EOTT Energy Corp. Board of Directors
in May 1998. He served as Chairman of the Board of EOTT Energy Corp. from May
2000 until April 2002. Mr. Horton served as Chief Executive Officer of EOTT
Energy Corp. from June 2000 to January 2002. Mr. Horton is the Chairman and
Chief Executive Officer of Enron Global Services and has held that position
since August 2001. From January 1997 to August 2001, he was Chairman and Chief
Executive Officer of Enron Transportation Services Company. Mr. Horton was
appointed to the Partnership Policy Committee and Management Committee of
Northern Border Partners, L.P. in December 1998. Mr. Horton serves on the Board
of Directors of the Interstate Natural Gas Association of America and is
Chairman of the Natural Gas Council. Mr. Horton held the indicated position(s)
with the following companies that filed for Chapter 11 bankruptcy protection
beginning on December 2, 2001: Enron (Chairman and Chief Executive Officer of
Enron Gas Pipeline


                                       62
<PAGE>


Group); Calypso Pipeline, L.L.C. (Director); Enron Transportation Services
Company (Chairman, President and Chief Executive Officer and Director); Enron
Wind Corp. (Chairman, Director); Enron Wind Systems, Inc. (Director); Enron Wind
Energy Systems Corp. (Chairman, Director); Enron Wind Maintenance Corp.
(Chairman, Director); Enron Wind Constructions Corp. (Chairman, Director).
Although, Mr. Horton has not been elected as an officer of Enron, he is
considered to be an executive officer of Enron solely for purposes of Securities
and Exchange Commission Rule 16 disclosure.

     Roderick Hayslett was elected to the EOTT Energy Corp. Board of Directors
in May 2001. Mr. Hayslett is the Managing Director of Finance and Accounting of
Enron Transportation Services Company and has held that position since October
1999. From June 1998 to October 1999, he was the Senior Vice President Finance
and Accounting of Enron's Gas Pipeline Group. Mr. Hayslett served as Vice
President and Chief Financial Officer of Citrus Corp., a joint venture of Enron
and El Paso Corp., from August 1995 to May 1998. Mr. Hayslett has also served as
a director of Citrus Corp. since July 1990.

     Dana R. Gibbs was appointed Chief Executive Officer of EOTT Energy Corp. in
January 2002 in addition to his role as President and Chief Operating Officer.
He joined EOTT Energy Corp. as Executive Vice President in April 1999 and became
President and Chief Operating Officer in June 2000. Mr. Gibbs was elected to the
EOTT Energy Corp. Board of Directors in June 2000 and served until April 2002.
He served as Vice President of Enron North America Corp. from 1992 to 1999.

     Lawrence Clayton, Jr. has served as Senior Vice President and Chief
Financial Officer since September 2000. Prior to joining EOTT Energy Corp., Mr.
Clayton was Senior Vice President and Chief Financial Officer at Aquila Energy
Corp., a subsidiary of Utilicorp United, Inc. from 1994 to 2000.

     Mary Ellen Coombe has served as Vice President, Human Resources and
Administration of EOTT Energy Corp. since December 1992. Ms. Coombe served in
various Human Resources and Administration positions within Enron since joining
Enron in September 1980.

     Molly M. Sample has served as Vice President and General Counsel since
February 2001. She served as General Counsel from September 2000 to January
2001. Ms. Sample served in various legal positions since joining Enron in
April 1991.

     Lori L. Maddox has served as Vice President and Controller since February
2001 and Chief Accounting Officer since October 1996. Prior to joining EOTT
Energy Corp., Ms. Maddox was associated with Arthur Andersen LLP where she
became a Senior Manager and served in the Energy Group for ten years.

     Employees of Enron or its affiliates or of EOTT Energy Corp. will not
receive additional compensation for serving EOTT Energy Corp. as members of the
Board of Directors or any of its committees. Each director who is not an
employee of EOTT Energy Corp. or Enron or its affiliates received an annual fee
of $16,000 for serving as a director during 2001, which was increased to
$25,000, effective March 1, 2002. Non-employee directors are paid a fee of
$2,000 for each director's meeting attended and $1,000 for each committee
meeting attended. In addition, each non-employee audit committee member was paid
an annual fee of $4,000 during 2001. This fee was eliminated in 2002, and
currently each committee chairperson is paid a fee of $4,000 annually.

SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE

     Section 16(a) of the Securities Exchange Act of 1934 requires certain
executive officers and all directors of our General Partner and persons who own
more than ten percent of a registered class of our equity securities to file
reports of ownership and changes in ownership with the SEC and the New York
Stock Exchange and to furnish EOTT Energy Corp. with copies of all Section 16(a)
forms they file. Based solely on our review of the


                                       63
<PAGE>


copies of such reports received by us, or written representations from certain
reporting persons that no Form 5's were required for those persons, we believe
that during 2001 our reporting persons complied with all applicable filing
requirements in a timely manner, except Lawrence Clayton, Jr. and Dee S. Osborne
each did not timely file one report covering one transaction.



                                       64
<PAGE>


ITEM 11.  EXECUTIVE COMPENSATION

     The following table summarizes certain information regarding compensation
paid or accrued by our General Partner, during each of the last three fiscal
years to the Chief Executive Officer and each of our General Partner's four
other most highly compensated executive officers (the "Named Officers"):

<Table>
<Caption>

                           SUMMARY COMPENSATION TABLE


                                              Annual Compensation                Long-Term Compensation
                                        -------------------------------    -------------------------------------
                                                                                                      Securities
                                                           Other Annual    Restricted    Underlying      LTIP        All Other
                                         Salary    Bonus   Compensation   Stock Awards  Options/SARs    Payouts     Compensation
Name and Principal Position      Year    ($)(1)     ($)       ($)(2)          ($)        (#'s)           ($)          ($)(3)
---------------------------      ----   -------   -------  ------------   ------------  ------------  ----------    ------------
<S>                              <C>    <C>       <C>      <C>            <C>           <C>           <C>           <C>
Stanley C. Horton                2001   180,000        --      --              --            --          --               --
Chief Executive Officer          2000    80,126        --      --              --            --          --               --
                                 1999        --        --      --              --            --          --               --

Dana R. Gibbs                    2001   265,000   125,000      --              --         6,441          --          101,054
President and Chief              2000   225,004   250,000      --              --         5,050          --          111,192
Operating Officer                1999   150,000        --      --              --            --          --            4,998

Lawrence Clayton, Jr             2001   225,000    75,000      --              --         6,306          --               42
Senior Vice President            2000    93,750   100,000      --              --         5,000          --               --
And Chief Financial Officer

Mary Ellen Coombe                2001   170,000    55,000      --              --           570          --           12,557
Vice President, Human            2000   160,000    60,000      --              --         5,050          --           14,022
Resource and Administration      1999   160,000    40,000      --              --            --          --            6,838

Lori L. Maddox                   2001   160,000    55,000      --              --           535          --              288
Vice President & Controller      2000   150,000    50,000      --              --         5,050          --            3,938
                                 1999   150,000    35,000      --              --            --          --           53,063
</Table>

----------

(1)  Mr. Horton served as Chief Executive Officer of Enron Transportation
     Services until August 2001 and has served as Chief Executive Officer of
     Enron Global Services since August 2001, as well as Chief Executive Officer
     for EOTT Energy Corp. from June 2000 until January 2002. He served as
     Chairman of the Board of Directors for EOTT Energy Corp. from June 2000
     until April 2002. The compensation reported is his compensation for all
     duties for EOTT Energy Corp. for twelve months in the year 2001. Enron
     bears full cost for all payments, except for a fixed amount of $180,000
     annually, which is paid by EOTT Energy Corp., and reimbursed by us. His
     cumulative compensation for all duties for Enron for the year 2001 is
     $520,000 salary; $1.2 million bonus; $19,540 other annual compensation;
     $2,500,083 restricted stock awards; 150,625 Securities Underlying
     Options/SARs; $650,000 LTIP Payout and $301 in Other Compensation. We paid
     no compensation expenses for Mr. Horton in the year 1999.

(2)  Includes perquisites and other personal benefits if value is greater than
     the lesser of $50,000 or 10% of reported salary and bonus. Also, Enron
     maintains three deferral plans for key employees under which payment of
     base salary, annual bonus and long-term incentive awards may be deferred to
     a later specified date. Mr. Horton is a participant under the 1985 Deferral
     Plan and Mr. Horton and Mr. Gibbs are participants in the 1994 Deferral
     Plan. Under the 1985 Deferral Plan, interest is credited on amounts
     deferred based on 150% of Moody's seasoned corporate bond yield index with
     a minimum rate of 12%, which for 1999, 2000 and 2001 was the minimum rate
     of 12%. No interest has been reported as Other Annual Compensation under
     the 1985 Deferral Plan for Mr. Horton because the crediting rates during
     1999, 2000, and 2001 did not exceed 120% of the long-term Applicable
     Federal Rate ("AFR") of 14.38% in effect at the time the 1985 Deferral Plan
     was implemented. Beginning January of 1996, the 1994 Deferral Plan credits
     interest based on fund elections chosen by participants. Since earnings on
     deferred compensation invested in third-party investment vehicles,
     comparable to mutual funds, need not be reported, no interest has been
     reported as Other Annual Compensation under the 1994 Deferral Plan during
     1999, 2000 and 2001.

(3)  The amounts shown include the value as of year end 1999, 2000 and 2001 of
     Enron Common Stock allocated during those years to employees' special
     subaccounts under the Enron Corp. Employee Stock Ownership Plan ("ESOP")
     and 1999, 2000 and 2001 matching contributions on employees' Enron Corp.
     Savings Plan account.


                                       65
<PAGE>

Stock Option Grants During 2001

     The following table sets forth information with respect to grants of
options to the Named Officers reflected in the Summary Compensation Table and
all employee optionees as a group. No unit options were granted during 2001
under the EOTT Energy Corp. Unit Option Plan. Stock options were granted during
2001 under Enron's 1994 Stock Plan ("1994 Plan"). No stock appreciation rights
("SAR") units were granted during 2001, and none are outstanding.

<Table>
<Caption>

                                                              INDIVIDUAL GRANTS
                                      -------------------------------------------------------------

                                            NUMBER OF                                                 POTENTIAL REALIZABLE VALUE AT
                                      SECURITIES UNDERLYING    % OF TOTAL                                ASSUMED ANNUAL RATES OF
                                            OPTIONS/          OPTIONS/SARS   EXERCISE                   STOCK PRICE APPRECIATION
                                              SARS             GRANTED TO     OF BASE                       FOR OPTION TERM(1)
                                             GRANTED          EMPLOYEES IN     PRICE     EXPIRATION   -----------------------------
NAME                                         (#)(2)            FISCAL YEAR    ($/SH)        DATE       0%(3)       5%         10%
----                                  ---------------------   ------------   --------    ----------   ------     --------  --------
<S>                      <C>          <C>                     <C>            <C>         <C>          <C>        <C>       <C>
S. Horton                EOTT                  --                  --            --            --     $  --      $   --    $  --
                         Enron Corp.       43,480(4)             0.24%       $75.06      01/22/06     $  --      $   --    $  --
                                          107,145(5)             0.60%       $36.25      08/20/06     $  --      $   --    $  --

D. Gibbs                 EOTT                  --                  --            --            --     $  --      $   --    $  --
                         Enron Corp.          885(6)             0.00%       $36.88      08/21/06     $  --      $   --    $  --
                                            5,556(7)             0.03%       $53.04      06/01/06     $  --      $   --    $  --

Lawrence Clayton, Jr.    EOTT                  --                  --            --            --     $  --      $   --    $  --
                         Enron Corp.        5,556(7)             0.03%       $29.15      10/01/06     $  --      $   --    $  --
                                              750(6)             0.00%       $36.88      08/21/06     $  --      $   --    $  --

M.E. Coombe              EOTT                  --                  --            --            --     $  --      $   --    $  --
                         Enron Corp.          570(6)             0.00%       $36.88      08/21/06     $  --      $   --    $  --

L. Maddox                EOTT                  --                  --            --            --     $  --      $   --    $  --
                         Enron Corp.          535(6)             0.00%       $36.88      08/21/06     $  --      $   --    $  --

All Employee and         EOTT                  --                  --            --            --     $  --      $   --    $  --
  Director Optionees     Enron Corp.   17,804,508                 100%       $55.87(8)        N/A     $  --      $   --    $  --

All Stock / Unitholders  EOTT                  --                  --            --            --     $  --      $   --    $  --
                         Enron Corp.          N/A                 N/A           N/A           N/A     $  --      $   --    $  --

Optionee Gain as % of    EOTT                 N/A                 N/A           N/A           N/A        --          --       --
  all Unitholders Gain   Enron Corp.          N/A                 N/A           N/A           N/A        --          --       --
</Table>


(1)  The dollar amounts under these columns represent the potential realizable
     value of each grant of options assuming that the market price on Enron
     Common Stock appreciates in value from the date of grant at the 5% and 10%
     annual rates prescribed by the SEC and therefore are not intended to
     forecast possible future appreciation, if any, of the price of Enron Common
     Stock.

(2)  For Mr. Horton, if a "change of control" (as defined in the Enron Corp.
     1991 Stock Plan) were to occur before the options become exercisable and
     are exercised, the vesting described below will be accelerated and all such
     outstanding options shall be surrendered and the optionee shall receive a
     cash payment by Enron in an amount equal to the value of the surrendered
     options (as defined in the 1991 Stock Plan). Enron stock options that were
     awarded during 2001 were under Enron's 1991 and/or 1994 Stock Plan(s).

(3)  An appreciation in stock price, which will benefit all shareholders, is
     required for optionees to receive any gain. A stock price appreciation of
     0% would render the option without value to the optionees.

(4)  Represents stock options awarded on January 22, 2001 under the Enron Corp.
     Long-Term Incentive Program. Awards vest 15% on the grant date and 15%
     every six months thereafter with the final vesting of 10% on January 31,
     2004. These options currently hold no value.

(5)  Options vest 33 1/4% on each August 20, 2002, 2003, and 2004. These options
     currently hold no value.

(6)  All eligible Enron employees received an option grant under the 2001
     Special Stock Option Grant. A grant of options equal to 5% of base annual
     salary as of August 13, 2001 was awarded on August 21, 2001. Options
     granted through the 2001 Special Stock Option Grant were 100% vested on the
     date of the grant. These options currently hold no value.

(7)  Options vest 25% on date of grant and 25% on each anniversary thereafter.
     These options currently hold no value.

(8)  Weighted average exercise price of all Enron stock options granted to
     employees in 2000.


                                       66
<PAGE>


AGGREGATED OPTIONS/SAR EXERCISES DURING 2001 AND OPTION/SAR
      VALUES AT DECEMBER 31, 2001

     The following table sets forth information with respect to the Named
Officers concerning the exercise of options under Enron's and our option plans
during the last fiscal year and unexercised options and SARs held as of the end
of the fiscal year:

<Table>
<Caption>

                                                                                                     Value of Unexercised
                                                                       Number of Securities               In-the-Money
                                                                      Underlying Unexercised            Options/SARs at
                                                                         Options/SARs at                December 31, 2001
                                     Shares                             December 31, 2001                   ($)(1)(2)
                                    Acquired        Value         ----------------------------     -----------------------------
                                       on         Realized
    Name                            Exercise         ($)           Exercisable   Unexercisable     Exercisable     Unexercisable
-----------                         --------     ------------     ------------   -------------     -----------     -------------
<S>                  <C>            <C>          <C>              <C>            <C>               <C>              <C>
S. Horton            EOTT                --      $        --            --            --           $        --      $        --
                     Enron Corp.     88,334      $ 3,695,819       260,740       193,224           $        --      $        --
                                                                                                                    -----------
                     Subtotal                                                                                       $        --

D. Gibbs             EOTT                --      $        --            --        80,000           $        --      $   758,400
                     Enron Corp.     44,000      $ 2,218,275        56,666        10,335           $        --      $        --
                                                                                                                    -----------
                     Subtotal                                                                                       $   758,400

L. Clayton           EOTT                --      $        --            --        80,000           $        --      $   758,400
                     Enron Corp.         --      $        --         2,417         8,889           $        --      $        --
                                                                                                                    -----------
                     Subtotal                                                                      $                $   758,400

M.E. Coombe          EOTT                --      $        --            --        60,000           $        --      $     3,000
                     Enron Corp.      6,000      $   444,192        55,096         2,524           $        --      $        --
                                                                                                                    -----------
                     Subtotal                                                                                       $     3,000

L. Maddox            EOTT                --      $        --            --            --           $        --      $        --
                     Enron Corp.         --      $        --        12,061         2,524           $        --      $        --
                                                                                                                    -----------
                     Subtotal                                                                                       $        --
</Table>

(1)  The dollar value for Mr. Gibbs and Mr. Clayton in this column for EOTT
     Options was calculated by assuming the subordinated unit option converts to
     a common unit option and determining the difference between the fair market
     value of the common units and the exercise value of the option at the end
     of the fiscal year. The value of our common units at year-end 2001 was
     $15.05 and the subordinated unit grant price is $5.57. These options on
     subordinated units are under Special Compensation Agreements between Mr.
     Gibbs and Mr. Clayton, each with Enron.

     The dollar value for Ms. Coombe in this column for EOTT Options was
     calculated by assuming the subordinated unit option converts to a common
     unit option and determining the difference between the fair t market value
     of the common units and the exercise value of the option at the end of the
     fiscal year. The value of EOTT Energy common units at year-end 2001 was
     $15.05 and the subordinated unit grant price is $15.00. These options were
     granted under the EOTT Energy Unit Option Plan.

(2)  The dollar value in this column for Enron stock options was calculated by
     determining the difference between the fair market value underlying the
     options as of December 31, 2001 ($0.60) and the grant price.



                                       67
<PAGE>




LONG TERM INCENTIVE PLAN AWARDS IN 2001

     In October 1997, the Board of Directors adopted the EOTT Energy Corp. Long
Term Incentive Plan ("Plan"). The Plan is intended to provide key employees with
Phantom Appreciation Rights ("PAR"), which are rights to receive cash based on
the performance of the Partnership prior to the time the PAR is redeemed. The
Plan has a five-year term beginning January 1, 1997 and PAR awards vest in 25%
increments over a four-year period following the grant year. The following table
provides information concerning awards of PARs under the Plan during 2001
pursuant to the Named Officers reflected in the Summary Compensation Table.

<Table>
<Caption>

                                                                                      Future Estimated
                                                   Performance                         Payments Under
                                       Number       or Other                      Non-Stock Based Plans(1)
                                     of Shares,    Period Until     -----------------------------------------------------
                                      Units or      Maturation
      Name                             Rights         Payout           Threshold $         Target $            Maximum $
----------------                     ----------   -------------     ----------------     -------------     ---------------
<S>                        <C>       <C>          <C>               <C>                  <C>               <C>
S. Horton                  EOTT            --            --           $        --         $        --        $        --
D. Gibbs                   EOTT        50,000            --           $        --         $   387,063        $   943,595
L. Clayton                 EOTT        20,000            --           $        --         $   154,825        $   377,438
M.E. Coombe                EOTT        10,000            --           $        --         $    77,413        $   188,719
L. Maddox                  EOTT        10,000            --           $        --         $    77,413        $   188,719
</Table>

(1)  Future estimated payments were based on a 10% targeted growth for each year
     of the 5 year performance period. Maximum payments were estimated at a 20%
     growth rate for the five-year performance period.

ENRON BENEFIT PLANS

     Like other employees of Enron and certain of its subsidiaries, the Named
Officers are eligible to participate in Enron-sponsored plans, including the
Enron Corp. Cash Balance Plan ("Cash Balance Plan") and the Enron Corp. Savings
Plan (a 401K plan). The Named Officers are also eligible to participate in the
Supplemental Retirement Plan ("SERP").

Defined Benefit Plans and Supplemental Retirement Plan

     The Cash Balance Plan is a noncontributory defined benefit pension plan to
provide retirement income for employees of Enron and its subsidiaries. This
pension plan has operated under a variety of benefit formulas in its history.
The plan initially began as a traditional final average pay plan, added an
offset by benefits under the Company's Employee Stock Ownership Plan (referred
to as a "floor-offset"). In 1995, the Plan was amended and became a cash balance
plan. None of the changes in benefit formula affected benefits accrued in prior
years. Thus, a person who worked for Enron under all three arrangements has a
defined benefit pension consisting of three separate components. Prior to July
1, 1986, benefits accrued are under insured contract(s) funded through
annuities. For service through December 31, 1994, participants in the Cash
Balance Plan were entitled to retirement benefits in the form of an annuity
based on a formula that uses a percentage of final average pay and years of
service. Benefits accrued by an employee during the period 1987 to 1994 were
offset by the amount of an annuity which (theoretically) could be acquired from
the proceeds of a sale of the ESOP shares in the employee's retirement
sub-account. In 1995, Enron's Board of Directors adopted an amendment to and
restatement of the plan, changing the plan's name from the Enron Corp.
Retirement Plan to the Enron Corp. Cash Balance Plan. The formula in place prior
to January 1, 1995, was suspended and replaced with a benefit accrual formula
with a "balance" determined from assumed contributions of 5% of annual base pay
beginning January 1, 1996. Under the Cash Balance Plan, each employee's accrued
benefit will also be credited with interest based on ten-year Treasury Bond
yields.


                                       68
<PAGE>


     The SERP is designed to restore retirement payments that are prohibited
under the Cash Balance Plan due to the benefit limitations under Internal
Revenue Code Section 415 and limitations on considering pay under Internal
Revenue Code Section 401(a)(17). The annual benefit payable under the SERP is
the excess, if any, of (1) the retirement income which the participant would
have been entitled to receive from the Cash Balance Plan if the limitations of
Sections 415 and 401(a)(17) of the Internal Revenue Code were not included in
such plan, less (2) the amount of retirement income he or she is projected to
receive from such plan. The SERP payment is also reduced by retirement income
benefits received from any similar company plans and is further reduced by any
amount received from the participant's ESOP retirement sub-account. As is common
with non-qualified benefits, the SERP is an unfunded plan, subject to the claims
of the employer's general creditors. Enron suspended payments under the SERP at
the time of its bankruptcy filing.

     The following table shows the estimated annual benefits that the Named
Officers would receive under the Cash Balance Plan and the SERP if they continue
to work at EOTT or Enron until they reached age 65, assuming current
remuneration levels without any salary projection. This table assumes that the
Named Officers will, upon retirement, receive payments under the SERP. However,
that assumption may prove invalid, as the bankruptcy could relieve Enron of any
obligation to make payments under the SERP.

<Table>
<Caption>

                                                              Estimated                 Current
                                        Current Credited    Credited Years            Compensation        Estimated Annual
                                            Years of         of Service at               Covered           Benefit Payable
                                           of Service         at Age 65                 by Plans           Upon Retirement
                                        ----------------    --------------            ------------        ---------------
<S>                                     <C>                 <C>                       <C>                 <C>
S. Horton ..........................       28.0                   41.1                  $520,000              $173,987
D. Gibbs ...........................        9.5                   32.0                  $180,000              $ 88,152
L. Clayton .........................        1.5                   17.5                  $225,000              $ 30,676
M.E. Coombe ........................       21.5                   35.4                  $170,000              $ 63,280
L. Maddox ..........................        5.3                   33.0                  $160,000              $ 74,520
</Table>

Note: The estimated annual benefits payable are based on the straight life
annuity form without adjustment for any offset applicable to a participant's
retirement subaccount in Enron's Employee Stock Ownership Plan. The estimated
benefit is not offset for Social Security.


EOTT ENERGY CORP. SEVERANCE PLAN

     The EOTT Energy Corp. Severance Pay Plan as amended provides for the
payment of benefits to employees who are terminated for failing to meet
performance objectives or standards, or who are terminated due to reorganization
or economic factors. The amount of benefits payable for performance related
terminations is based on length of service and may not exceed six weeks' pay in
the event such employee signs a waiver and release of claims agreement. For
those terminated as the result of reorganization or economic circumstances, the
benefit is based on length of service with one week's pay per year of service up
to an amount of a maximum payment of 26 weeks of base pay. If the employee signs
a waiver and release of claims agreement, the severance pay benefits are
doubled. The plan provides a grandfather provision for those employees whose
employment date is prior to January 1, 1993. This provision provides a severance
benefit equal to two weeks of base pay multiplied by the number of full or
partial years of service, plus two weeks of base pay for each $10,000 (or
portion of $10,000) included in the employee's annual base pay, provided the
employee signs a waiver and release of claims agreement. In the event of an
unapproved change of control of the Company, any employee who is involuntarily
terminated within two years following the change of control will be eligible for
severance benefits equal to two weeks of base pay multiplied by the number of
full or partial years of service, plus two weeks of base pay for each $10,000
(or portion of $10,000) included in the employee's annual base pay. Under no
circumstances will the total severance pay benefit exceed 52 weeks of pay.

     Severance arrangements for Mr. Gibbs, Mr. Clayton, Ms. Coombe, and Ms.
Maddox include an involuntary termination provision pursuant to the executive
officers' employment agreements. An involuntary


                                       69
<PAGE>


termination includes (a) termination without cause; (b) a termination within 90
days after the happening of one of the following events without the approval of
the executive officer: (i) a substantial and/or material reduction in the nature
or scope of the executive officer's duties and/or responsibilities, which
results in the executive officer no longer having an officer status and results
in an overall material and substantial reduction from the duties and stature of
the officer position he presently holds, which reduction remains in place and
uncorrected for 30 days following written notice of such breach to the General
Partner by the executive officer, (ii) a reduction in the executive officer's
base pay or an exclusion from a benefit plan or program (except the executive
officer may be subject to exclusion from a benefit plan or program as part of a
general cutback for all employees or officers) or (iii) a change in the location
for the primary performance of the executive officer's services under the
agreement to a city which is more than 100 miles away from such location; and
(c) a termination by the executive officer within one year after a change of
control of the General Partner if one of the events described in (b) has
occurred. The severance, "confidential information" and "noncompete" provisions
will continue for one year following the termination date.

EMPLOYMENT AGREEMENTS

     Mr. Gibbs entered into a new employment agreement with EOTT Energy Corp. on
July 1, 2000 for a term of three years. The agreement provides for an annual
base salary of not less than $250,000 and an annual incentive plan target of
100%. His annual bonus for calendar year 2000 was to be 100% of his annual base
salary if during the four quarters of the year 2000, all distributions to common
units are met without Additional Partnership Interests ("API") support from
Enron. Mr. Gibbs was also to receive an additional bonus opportunity of 100% of
his annual base salary if during any calendar year under the term of his
agreement, conversion requirements under the Partnership Agreement are met to
allow conversion of the subordinated units to common units. The agreement
further provides a retention bonus of $100,000 payable on January 31, 2001. The
agreement provides for post employment noncompete obligations in the event of
termination.

     Mr. Clayton entered into his employment agreement with EOTT Energy Corp. in
2000. Mr. Clayton's agreement is for a term of three years. The agreement
provides for an annual base salary of $225,000 and an annual incentive plan
target of 100%. His annual bonus for calendar year 2000, payable in the first
quarter of 2001, was to be a minimum amount of $75,000 provided Mr. Clayton met
the identified objectives of EOTT Energy Corp. Pursuant to the agreement, Mr.
Clayton received a grant of 30,000 EOTT Energy PAR Units under the EOTT Energy
Long Term Incentive Plan and 5,000 Enron options. Mr. Clayton's agreement
provides for severance benefits of one year's annual base salary if a voluntary
termination occurs within the first year of the term. In the event that the
involuntary termination occurs after the first year of the term, the severance
benefits are the greater of the remaining months of annual salary under the term
of the agreement or one year's annual base salary. Ms Maddox entered into her
employment agreement with EOTT Energy Corp. in 2001. Ms. Maddox's agreement is
for a term of two years. The agreement provides for an annual base salary of
$160,000. Ms. Maddox's agreement provides for severance benefits of two years'
base salary in the event of involuntary termination and includes confidentiality
and noncompete provisions for a period of one year following such termination. A
surviving provision of an expired employment agreement with Ms. Coombe provides
severance benefits of two years' base salary in the event of involuntary
termination and includes confidentiality and noncompete provisions for a period
of one year following such termination.

COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION

     The Board of Directors of our General Partner established a committee that
is responsible for developing and administering compensation policy (the
"Compensation Committee"). During 2001, Dee S. Osborne and Edward O. Gaylord
served on the Compensation Committee until they resigned from the Board of
Directors on November 28, 2001. Daniel P. Whitty served on the Compensation
Committee until his resignation from the Board of Directors on December 5, 2001.
John M. Duncan served on the Compensation Committee until his


                                       70
<PAGE>


resignation from the Board of Directors on February 13, 2002. None of these
directors had a relationship requiring disclosure under this caption,
"Compensation Committee Interlocks and Insider Participation."




                                       71
<PAGE>



ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     Our General Partner knows of no one who beneficially owns in excess of five
percent of the common units of the Partnership except as set forth in the table
below.

<Table>
<Caption>

                                                              Amount and Nature
                                 Name and Address          of Beneficial Ownership          Percent
       Title of Class           of Beneficial Owner        as of February 15, 2002          of Class
     ------------------       -------------------------   ------------------------          --------
<S>                           <C>                         <C>                               <C>
     Common Units             Enron Corp.                        3,276,811(1)                 17.74
     Subordinated Units       1400 Smith Street                  7,000,000(1)                 77.78
     APIs                     Houston, Texas 77002               9,318,213(1)(2)             100.00

     Subordinated Units       Flint Hills Resources, LP          2,000,000                    22.22
                              4111 East 37th Street N
                              Wichita, Kansas 67220
</Table>

----------

(1)  Based upon information provided by Enron Corp., these securities are held
     of record by Timber I, LLC, an entity whose managing member is an indirect
     subsidiary of Enron Corp. Enron Corp. retains the power to vote the
     securities. Enron Corp. cannot unilaterally dispose of these securities and
     therefore retains shared investment power over these securities under Rule
     13d-3 of the Securities Exchange Act of 1934.

(2)  The reporting of the APIs shall not be deemed to be a concession that such
     interest represents a security.



                                       72
<PAGE>


      The following table sets forth certain information as of February 15,
2002, regarding the beneficial ownership of (i) the common units and (ii) the
common stock of Enron, 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.

<Table>
<Caption>

                                                                               AMOUNT AND NATURE OF BENEFICIAL OWNERSHIP
                                                                 ----------------------------------------------------------------
                                                                    SOLE VOTING     SHARED VOTING       SOLE VOTING
                                                                  AND INVESTMENT   AND INVESTMENT      LIMITED OR NO    PERCENT
        TITLE OF CLASS                       NAME                   POWER(1)           POWER         INVESTMENT POWER   OF CLASS
-------------------------------   --------------------------     ----------------  -------------     -----------------  --------
<S>                               <C>                            <C>               <C>               <C>                <C>
EOTT Energy Partners, L.P.        Stanley C. Horton                     10,000             --                  --          *
Common Units                      Roderick J. Hayslett                      --             --                  --          *
                                  Dana R. Gibbs                          8,000             --                  --          *
                                  Lawrence Clayton, Jr.                 12,000             --                  --          *
                                  Mary Ellen Coombe                     60,000            500                  --          *
                                  Lori L. Maddox                            --             --                  --          *
                                  Molly M. Sample                          500             --                  --          *

                                  All directors and executive
                                  officers as a group
                                  (7 in number)                         90,500            500                  --          *

Enron Corp.                       Stanley C. Horton                    390,277          7,047(2)           62,328          *
Common Stock                      Roderick J. Hayslett                  69,818             --               5,334          *
                                  Dana R. Gibbs                         56,678             --               1,216          *
                                  Lawrence Clayton, Jr.                  2,417             --                 169          *
                                  Mary Ellen Coombe                     55,524             --                  --          *
                                  Lori L. Maddox                        12,073             --                 340          *
                                  Molly M. Sample                        7,817             --                 493          *

                                  All directors and executive
                                  officers as a group
                                  (7 in number)                        594,604          7,047              69,880          *
</Table>

* Less than 1 percent

(1)  The above table includes subordinated units of the Partnership which are
     subject to conversion into common units and which are presently vested: Ms.
     Coombe, 60,000 units; and all directors and executive officers as a group,
     60,000 units. The above table also includes shares of common stock of Enron
     which are subject to stock options exercisable within 60 days as follows:
     Mr. Clayton, 2,417 shares; Ms. Coombe, 55,108 shares; Mr. Gibbs, 56,678
     shares; Mr. Hayslett, 69,818 shares; Mr. Horton, 292,915 shares; Ms.
     Maddox, 12,073 shares; Ms. Sample, 7,038 shares and all directors and
     executive officers as a group, 496,047 shares.

(2)  Shares held by the spouse of Mr. Horton, for which he may be deemed to have
     shared voting and investment power.

The table also includes shares owned by certain members of the families of the
directors or executive officers, including shares in which pecuniary interest
may be disclaimed.



                                       73
<PAGE>




ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

     See Note 10 to the Consolidated Financial Statements for information
regarding certain transactions with Enron and its affiliates and related
parties.




                                       74
<PAGE>


                                     PART IV


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

     (a)(1) AND (2) FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULE

       See "Index to Financial Statements" set forth on page F-1.

     (a)(3) EXHIBITS

     3.1    --     Form of Partnership Agreement of EOTT Energy Partners, L.P.
                   (incorporated by reference to Exhibit 3.1 to Registration
                   Statement, File No. 33-73984)

     3.2    --     Amendment No. 1 dated as of August 8, 1995, to the Amended
                   and Restated Agreement of Limited Partnership of EOTT Energy
                   Partners, L.P. (incorporated by reference to Exhibit 3.2 to
                   Annual Report on Form 10-K for the Year Ended December 31,
                   1995)

     3.3    --     Amendment No. 2 dated as of July 16, 1996, to the Amended and
                   Restated Agreement of Limited Partnership of EOTT Energy
                   Partners, L.P. (incorporated by reference to Exhibit 3.3 to
                   Quarterly Report on Form 10-Q for the Quarter Ended June 30,
                   1996)

     3.4    --     Amendment No. 3 dated as of February 13, 1997, to the Amended
                   and Restated Agreement of Limited Partnership of EOTT Energy
                   Partners, L.P. (incorporated by reference to Exhibit 3.4 to
                   Annual Report on Form 10-K for the Year Ended December 31,
                   1996)

     3.5    --     Amendment No. 4 dated as of November 30, 1998, to the Amended
                   and Restated Agreement of Limited Partnership of EOTT Energy
                   Partners, L.P. (incorporated by reference to Exhibit 3.5 to
                   Annual Report on Form 10-K for the Year Ended December 31,
                   1998)

     3.6    --     Amendment No. 5 dated as of December 7, 1998, to the Amended
                   and Restated Agreement of Limited Partnership of EOTT Energy
                   Partners, L.P. (incorporated by reference to Exhibit 3.6 to
                   Annual Report on Form 10-K for the Year Ended December 31,
                   1998)

     3.7    --     Amendment No. 6 dated as of September 16, 1999 to the Amended
                   and Restated Agreement of Limited Partnership of EOTT Energy
                   Partners, L.P. (incorporated by reference to Exhibit 3.1 to
                   Current Report on Form 8-K dated September 29, 1999)

     3.8    --     Reorganization Agreement dated as of August 29, 2001, between
                   EOTT Energy Partners, L.P., EOTT Energy Operating Limited
                   Partnership, EOTT Energy Pipeline Limited Partnership, EOTT
                   Energy Canada Limited Partnership, EOTT Energy Corp., and
                   EOTT Energy General Partner (incorporated by reference to
                   Exhibit 3.8 to Current Report on Form 8-K/A dated August 30,
                   2001)

     3.9    --     Amendment No. 7 dated as of August 29, 2001 to the Amended
                   and Restated Agreement of Limited Partnership of EOTT Energy
                   Partners, L.P. (incorporated by reference to Exhibit 3.9 to
                   Current Report on Form 8-K/A dated August 30, 2001)

     3.10   --     Form of Amended and Restated Agreement of Limited Partnership
                   of EOTT Energy Operating Limited Partnership (incorporated by
                   reference to Exhibit 10.11 to Registration Statement, File
                   No. 33-73984)


                                       75
<PAGE>


     3.11   --     Amendment No. 1 dated as of September 1, 1999, to Amended and
                   Restated Agreement of Limited Partnership of EOTT Energy
                   Operating Limited Partnership (incorporated by reference to
                   Exhibit 3.2 to current report on Form 8-K dated September 29,
                   1999)

     3.12   --     Amendment No. 2 dated as of August 29, 2001, to Amended and
                   Restated Agreement of Limited Partnership of EOTT Energy
                   Operating Limited Partnership (incorporated by reference to
                   Exhibit 3.10 to Current Report on Form 8-K/A dated August 30,
                   2001)

     3.13   --     Form of Amended and Restated Agreement of Limited Partnership
                   of EOTT Energy Pipeline Limited Partnership (incorporated by
                   reference to Exhibit 3.8 to Registration Statement, File No.
                   33-82269)

     3.14   --     Amendment No. 1 dated as of September 1, 1999, to Amended and
                   Restated Agreement of Limited Partnership of EOTT Energy
                   Pipeline Limited Partnership (incorporated by reference to
                   Exhibit 3.3 to current report on Form 8-K dated September 29,
                   1999)

     3.15   --     Amendment No. 2 dated as of August 29, 2001, to Amended and
                   Restated Agreement of Limited Partnership of EOTT Energy
                   Pipeline Limited Partnership (incorporated by reference to
                   Exhibit 3.11 to Current Report on Form 8-K/A dated August 30,
                   2001)

     3.16   --     Amended and Restated Agreement of Limited Partnership of EOTT
                   Energy Canada Limited Partnership (incorporated by reference
                   to Exhibit 3.9 to Registration Statement, File No. 33-82269)

     3.17   --     Amendment No. 1 dated as of September 1, 1999, to Amended and
                   Restated Agreement of Limited Partnership of EOTT Energy
                   Canada Limited Partnership (incorporated by reference to
                   Exhibit 3.2 to current report on Form 8-K dated September 29,
                   1999)

     3.18   --     Amendment No. 2 dated as of August 29, 2001, to Amended and
                   Restated Agreement of Limited Partnership of EOTT Energy
                   Canada Limited Partnership (incorporated by reference to
                   Exhibit 3.12 to Current Report on Form 8-K/A dated August 30,
                   2001)

     3.19   --     Agreement of Limited Partnership dated as of June 28, 2001 of
                   EOTT Energy Liquids, L.P. (incorporated by reference to
                   Exhibit 3.13 to Quarterly Report on Form 10-Q for the Quarter
                   Ended September 30, 2001)

     3.20   --     Limited Liability Company Agreement dated as of June 27, 2001
                   of EOTT Energy General Partner, L.L.C. (incorporated by
                   reference to Exhibit 3.14 to Quarterly Report on Form 10-Q
                   for the Quarter Ended September 30, 2001)

     3.21   --     Amendment No. 1 dated as of August 29, 2001, to the Limited
                   Liability Company Agreement of EOTT Energy General Partner,
                   L.L.C. (incorporated by reference to Exhibit 3.15 to
                   Quarterly Report on Form 10-Q for the Quarter Ended September
                   30, 2001)

     4.1    --     Form of Indenture for Senior Debt Securities and Subordinated
                   Debt Securities (incorporated by reference to Exhibit 4.1 to
                   Registration Statement, File No. 333-82269)

    10.01   --     Form of Corporate Services Agreement between Enron Corp. and
                   EOTT Energy Corp. (incorporated by reference to Exhibit 10.08
                   to Registration Statement, File No. 33-73984)


                                       76
<PAGE>


    10.02   --     Form of Contribution and Closing Agreement between EOTT
                   Energy Corp. and EOTT Energy Partners, L.P. (incorporated by
                   reference to Exhibit 10.09 to Registration Statement, File
                   No. 33-73984)

    10.03   --     Form of Ancillary Agreement by and among Enron Corp., EOTT
                   Energy Partners, L.P., EOTT Energy Operating Limited
                   Partnership, EOTT Energy Pipeline Limited Partnership, EOTT
                   Energy Canada Limited Partnership, and EOTT Energy Corp.
                   (incorporated by reference to Exhibit 10.10 to Registration
                   Statement, File No. 33-73984)

    10.04   --     EOTT Energy Corp. Annual Incentive Plan (incorporated by
                   reference to Exhibit 10.14 to Registration Statement, File
                   No. 33-73984)

    10.05   --     EOTT Energy Corp. 1994 Unit Option Plan and the related
                   Option Agreement (incorporated by reference to Exhibit 10.15
                   to Registration Statement, File No. 33-73984)

    10.06   --     EOTT Energy Corp. Severance Pay Plan (incorporated by
                   reference to Exhibit 10.16 to Registration Statement, File
                   No. 33-73984)

    10.07   --     EOTT Energy Corp. Long Term Incentive Plan (incorporated by
                   reference to Exhibit 10.19 to Quarterly Report on Form 10-Q
                   for the Quarter Ended September 30, 1997)

    10.08   --     Support Agreement dated September 21, 1998 between EOTT
                   Energy Partners, L.P., EOTT Energy Operating Limited
                   Partnership and Enron Corp. (incorporated by reference to
                   Exhibit 10.22 to Quarterly Report on Form 10-Q for the
                   Quarter Ended September 30, 1998)

 ***10.09   --     Crude Oil Supply and Terminalling Agreement dated as of
                   December 1, 1998 between Koch Oil Company and EOTT Energy
                   Operating Limited Partnership (incorporated by reference to
                   Exhibit 10.23 to Annual Report on Form 10-K for the Year
                   Ended December 31, 1998)

    10.10   --     Amended and Restated Credit Agreement as of December 1, 1998
                   between EOTT Energy Operating Limited Partnership, as
                   Borrower, and Enron Corp., as Lender (incorporated by
                   reference to Exhibit 10.24 to Annual Report on Form 10-K for
                   the Year Ended December 31, 1998)

    10.11   --     Amendment dated March 17, 1999 to the Amended and Restated
                   Credit Agreement as of December 1, 1998 between EOTT Energy
                   Operating Limited Partnership, as Borrower, and Enron Corp.,
                   as Lender (incorporated by reference to Exhibit 10.26 to
                   Annual Report on Form 10-K for the Year Ended December 31,
                   1998)

 ***10.12   --     Amendment dated December 1, 1998 to the Crude Oil Supply and
                   Terminalling Agreement dated as of December 1, 1998 between
                   Koch Oil Company and EOTT Energy Operating Limited
                   Partnership (incorporated by reference to Exhibit 10.28 to
                   Annual Report on Form 10-K for the Year Ended December 31,
                   1998)

    10.13   --     Amendment dated August 11, 1999 to the Amended and Restated
                   Credit Agreement as of December 1, 1998 between EOTT Energy
                   Operating Limited Partnership, as Borrower, and Enron Corp.,
                   as Lender (incorporated by reference to Exhibit 10.30 to
                   Quarterly Report on Form 10-Q for the Period Ended June 30,
                   1999)

    10.14   --     Form of Executive Employment Agreement between EOTT Energy
                   Corp. and Dana R. Gibbs (incorporated by reference to Exhibit
                   10.32 to Quarterly Report on Form 10-Q for the Period Ended
                   September 30, 2000)


                                       77
<PAGE>


    10.15   --     Form of Executive Employment Agreement between EOTT Energy
                   Corp. and Lawrence Clayton, Jr. (incorporated by reference to
                   Exhibit 10.33 to Quarterly Report on Form 10-Q for the Period
                   Ended September 30, 2000)

 ***10.16   --     Letter Agreement dated September 14, 2000 amending Crude Oil
                   Supply and Terminalling Agreement (incorporated by reference
                   to Exhibit 10.34 to Quarterly Report on Form 10-Q for the
                   Period Ended September 30, 2000)

    10.17   --     Form of Executive Employment Agreement between EOTT Energy
                   Corp. and Molly Sample (incorporated by reference to Exhibit
                   10.35 to Annual Report on Form 10-K for the year ended
                   December 31, 2000)

    10.18   --     Form of Executive Employment Agreement between EOTT Energy
                   Corp. and Lori Maddox (incorporated by reference to Exhibit
                   10.36 to Annual Report on Form 10-K for the year ended
                   December 31, 2000)

 ***10.19   --     Letter Agreement dated February 6, 2001 amending Crude Oil
                   Supply and Terminalling Agreement dated December 1, 1998
                   (incorporated by reference to Exhibit 10.37 to Annual Report
                   on Form 10-K for the year ended December 31, 2000)

    10.20   --     Purchase and Sale Agreement between Enron Corp. and EOTT
                   Energy Partners, L.P., dated June 29, 2001, with list of
                   omitted schedules and agreement to furnish omitted schedules
                   supplementally to the Securities and Exchange Commission upon
                   request (incorporated by reference to Exhibit 10.38 to
                   Current Report on Form 8-K dated July 13, 2001)

 ***10.21   --     Mont Belvieu Storage Capacity Purchase Agreement Dated as of
                   June 29, 2001 between EOTT Energy Liquids, L.P. and Enron Gas
                   Liquids, Inc. (incorporated by reference to Exhibit 10.39 to
                   Quarterly Report on Form 10-Q for the period ended June 30,
                   2001)

 ***10.22   --     Toll Conversion Agreement dated as of June 29, 2001 between
                   EOTT Energy Liquids, L.P. and Enron Gas Liquids, Inc.
                   (incorporated by reference to Exhibit 10.40 to Quarterly
                   Report on Form 10-Q for the period ended June 30, 2001)

    10.23   --     Administrative Services Agreement dated as of June 29, 2001
                   between EOTT Energy Corp. and EOTT Energy General Partner,
                   L.L.C. (incorporated by reference to Exhibit 10.41 to
                   Quarterly Report on Form 10-Q for the period ended June 30,
                   2001)

 ** 10.24   --     Letter Agreement dated June 27, 2001, amending Crude Oil
                   Supply and Terminalling Agreement dated December 1, 1998

 ** 10.25   --     Letter Agreement dated August 23, 2001, amending Crude Oil
                   Supply and Terminalling Agreement dated December 1, 1998

 *  10.26   --     Letter Agreement dated December 18, 2001, amending Crude Oil
                   Supply and Terminalling Agreement dated December 1, 1998

 ** 10.27   --     Letter Agreement dated January 9, 2002, amending Crude Oil
                   Supply and Terminalling Agreement dated December 1, 1998


                                       78
<PAGE>


**  10.28   --     Commodity Repurchase Agreement, dated as of February 28,
                   1998, between EOTT Energy Operating Limited Partnership and
                   Standard Chartered Trade Service Corporation

**  10.29   --     Receivable(s) Purchase Agreement, dated as of October 19,
                   1999, between EOTT Energy Operating Limited Partnership and
                   Standard Chartered Trade Services Corporation.

*   10.30   --     First Amendment to the Receivable(s) Purchase Agreement,
                   dated as of January 12, 2000, by and between EOTT Energy
                   Operating Limited Partnership and Standard Chartered Trade
                   Services Corporation

**  10.31   --     Second Amended and Restated Reimbursement, Loan and Security
                   Agreement, dated as of April 23, 2002, by and between EOTT
                   Energy Operating Limited Partnership, et al. and Standard
                   Chartered Bank

*   10.32   --     Letter Agreement, dated as of April 23, 2002, regarding
                   Commodity Repurchase Agreement and Receivable(s) Purchase
                   Agreement

    18.1    --     Preferability Letter on Change in Accounting Principle
                   (incorporated by reference to Exhibit 18.1 to Quarterly
                   Report on Form 10-Q for the Period Ended March 31, 2001)

*   21.1    --     Subsidiaries of the Registrant

*   23.1    --     Consent of PricewaterhouseCoopers LLP


*   Filed herewith.

**  Filed herewith; however, confidential treatment has been requested with
    respect to certain portions of this exhibit.

*** Certain portions of this exhibit have been treated confidentially.

     (b)    Reports on Form 8-K


            Current Report on Form 8-K filed on February 11, 2002 pursuant to
            Item 4. Changes in Registrants Certifying Accountant regarding
            resignation of Arthur Andersen LLP.

            Current Report on Form 8-K filed on March 27, 2002 pursuant to Item
            4. Changes in Registrants Certifying Accountant regarding engagement
            of PricewaterhouseCoopers LLP.

            Current Report on Form 8-K filed on April 3, 2002 pursuant to Item
            5. Other Events regarding suspension of first quarter distributions.

            Current Report on Form 8-K filed on April 15, 2002 pursuant to Item
            5. Other Events regarding election of new Chairman and restructure
            of Board.

            Current Report on Form 8-K filed on April 16, 2002 pursuant to Item
            5. Other Events regarding extension of credit facility.

            Current Report on Form 8-K filed on April 17, 2002 pursuant to Item
            5. Other Events regarding our delay in filing our Annual Report on
            Form 10-K.

            Current Report on Form 8-K filed on May 1, 2002 pursuant to Item 5.
            Other Events regarding our press release dated April 24, 2002.

            Current Report on Form 8-K filed on May 17, 2002 pursuant to Item 5.
            Other Events regarding our press release dated May 16, 2002.



                                       79
<PAGE>


                                   SIGNATURES

     Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned thereunto duly authorized on the 30th day of May,
2002.

                                         EOTT ENERGY PARTNERS, L.P.
                                      (A Delaware Limited Partnership)

                                     By:   EOTT ENERGY CORP. as
                                              General Partner


                                     By:      /s/ DANA R. GIBBS
                                        ----------------------------------
                                                  Dana R. Gibbs
                                        Chief Executive Officer, President
                                           and Chief Operating Officer


     Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons in the capacities and on
the dates indicated.

<Table>
<Caption>

        Signature                    Title                            Date
        ---------                    -----                            ----
<S>                            <C>                                 <C>
/s/ THOMAS M. MATTHEWS         Chairman of the Board               May 30, 2002
--------------------------
    Thomas M. Matthews


/s/ H. MALCOLM LOVETT, JR.     Director                            May 30, 2002
--------------------------
    H. Malcolm Lovett, Jr.


/s/ JAMES M. TIDWELL           Director                            May 30, 2002
--------------------------
    James M. Tidwell


                               Director                            May   , 2002
--------------------------
    Stanley C. Horton


                               Director                            May   , 2002
--------------------------
    Roderick Hayslett


/s/ DANA R. GIBBS              Chief Executive Officer, President  May 30, 2002
--------------------------     and Chief Operating Officer
    Dana R. Gibbs


/s/ LAWRENCE CLAYTON, JR.      Senior Vice President and           May 30, 2002
--------------------------     Chief Financial Officer
    Lawrence Clayton, Jr.


/s/ LORI L. MADDOX             Vice President and Controller       May 30, 2002
--------------------------     (Chief Accounting Officer)
    Lori L. Maddox
</Table>


<PAGE>


                           EOTT ENERGY PARTNERS, L.P.
                          INDEX TO FINANCIAL STATEMENTS

<Table>
<Caption>

                                                                          Page
                                                                          ----
<S>   <C>                                                                 <C>
Financial Statements

      Report of Independent Accountants................................   F-2

      Consolidated Statements of Operations -
           Years Ended December 31, 2001, 2000 and 1999................   F-3

      Consolidated Balance Sheets - December 31, 2001 and 2000.........   F-4

      Consolidated Statements of Cash Flows -
           Years Ended December 31, 2001, 2000 and 1999................   F-5

      Consolidated Statements of Partners' Capital -
           Years Ended December 31, 2001, 2000 and 1999................   F-6

      Notes to Consolidated Financial Statements.......................   F-7

Supplemental Schedule

      Schedule II - Valuation and Qualifying Accounts and Reserves.....   S-1
</Table>





                                      F-1
<PAGE>

                        REPORT OF INDEPENDENT ACCOUNTANTS


To EOTT Energy Partners, L.P.:

In our opinion, the consolidated financial statements listed in the accompanying
index present fairly, in all material respects, the financial position of EOTT
Energy Partners, L.P. and its subsidiaries (the Partnership) at December 31,
2001, and the results of their operations and their cash flows for the year
ended December 31, 2001 in conformity with accounting principles generally
accepted in the United States of America. In addition, in our opinion, the
financial statement schedule listed in the accompanying index 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 the financial statement schedule are the responsibility of the
Partnership's management; our responsibility is to express an opinion on these
financial statements and the financial statement schedule based on our audit. We
conducted our audit 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 from 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 audit provides a reasonable basis for our opinion.

As discussed in Note 2 to the consolidated financial statements, the Partnership
changed its method of accounting for derivative instruments and hedging
activities in connection with its adoption of Statement of Financial Accounting
Standards No. 133 "Accounting for Derivative Instruments and Hedging
Activities", as amended effective January 1, 2001.

As discussed in Note 4 to the consolidated financial statements, the Partnership
changed its method of accounting for inventories used in its energy trading
activities from the average cost method to the fair value method.

As discussed in Note 10 to the consolidated financial statements, Enron, which
is the parent of EOTT Energy Corp., the Partnership's General Partner, has filed
for bankruptcy. See Note 10 to the consolidated financial statements for
management's discussion on the impact of the Enron bankruptcy on the Partnership
and its General Partner, EOTT Energy Corp.


PRICEWATERHOUSECOOPERS LLP


Houston, Texas
May 24, 2002




                                      F-2
<PAGE>

                           EOTT ENERGY PARTNERS, L.P.
                      CONSOLIDATED STATEMENTS OF OPERATIONS
                     (In Thousands, Except Per Unit Amounts)


<Table>
<Caption>

                                                                    YEAR ENDED DECEMBER 31,
                                                         --------------------------------------------
                                                            2001             2000             1999
                                                         ------------    ------------    ------------
                                                                          (UNAUDITED)     (UNAUDITED)
                                                                                          (RESTATED)
                                                                                           (NOTE 3)
<S>                                                      <C>             <C>             <C>
Revenue ..............................................   $  8,608,972    $ 11,614,005    $  8,664,401

Cost of Sales ........................................      8,346,206      11,374,090       8,451,057
Operating Expenses ...................................        130,063         113,412         107,725
Depreciation and Amortization- operating .............         32,995          31,357          31,385
                                                         ------------    ------------    ------------

Gross Profit .........................................         99,708          95,146          74,234
                                                         ------------    ------------    ------------

Selling, General and Administrative Expenses .........         49,103          47,678          45,469
Depreciation and Amortization- corporate & other .....          3,083           2,511           1,751
Other (Income) Expense ...............................            210            (282)           (989)
Impairment of Assets (Note 7) ........................         29,057              --              --
                                                         ------------    ------------    ------------

Operating Income .....................................         18,255          45,239          28,003
                                                         ------------    ------------    ------------

Interest Expense and Related Charges .................        (35,363)        (30,411)        (29,817)
Interest Income ......................................          1,319           1,631             875
Other, Net ...........................................           (517)         (2,626)           (247)
                                                         ------------    ------------    ------------

Net Income (Loss) Before Cumulative
   Effect of Accounting Change .......................        (16,306)         13,833          (1,186)
Cumulative Effect of Accounting Change (Notes 2 and 4)          1,073              --           1,747
                                                         ------------    ------------    ------------

Net Income (Loss) ....................................   $    (15,233)   $     13,833    $        561
                                                         ============    ============    ============


Basic Net Income (Loss) Per Unit (Note 6)
   Common ............................................   $      (0.54)   $       0.49    $      (0.01)
                                                         ============    ============    ============
   Subordinated ......................................   $      (0.54)   $       0.49    $       0.07
                                                         ============    ============    ============

Diluted Net Income (Loss) Per Unit (Note 6) ..........   $      (0.54)   $       0.49    $       0.02
                                                         ============    ============    ============
Distributions Per Common Unit ........................   $       1.90    $       1.90    $       1.90
                                                         ============    ============    ============

Average Units Outstanding for Diluted Computation ....         27,476          27,476          24,877
                                                         ============    ============    ============
</Table>



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




                                      F-3
<PAGE>



                           EOTT ENERGY PARTNERS, L.P.
                           CONSOLIDATED BALANCE SHEETS
                                 (In Thousands)

<Table>
<Caption>

                                                               DECEMBER 31,    DECEMBER 31,
                                                                   2001            2000
                                                               ------------    ------------
                                                                                (UNAUDITED)
                            ASSETS
<S>                                                            <C>             <C>
Current Assets
   Cash and cash equivalents ................................   $    2,941      $   54,230
   Trade and other receivables, net of allowance for doubtful
      accounts of $1,225 and $1,827, respectively ...........      495,896         915,775
   Inventories ..............................................       89,685          84,653
   Other ....................................................       31,650          26,208
                                                                ----------      ----------
      Total current assets ..................................      620,172       1,080,866
                                                                ----------      ----------

Property, Plant and Equipment, at cost ......................      656,993         562,393
   Less: Accumulated depreciation ...........................      191,118         168,460
                                                                ----------      ----------
      Net property, plant and equipment .....................      465,875         393,933
                                                                ----------      ----------

Other Assets, net of amortization ...........................       14,463          16,221
                                                                ----------      ----------

Total Assets ................................................   $1,100,510      $1,491,020
                                                                ==========      ==========

               LIABILITIES AND PARTNERS' CAPITAL

Current Liabilities
   Trade accounts payable ...................................   $  532,235      $1,080,217
   Accrued taxes payable ....................................        8,846          10,755
   Short-term borrowings ....................................       40,000              --
   Repurchase agreements ....................................      100,000              --
   Receivable financing .....................................       42,500              --
   Payable to Enron Corp. & affiliates, net .................       37,681          36,564
   Performance collateral from Enron Corp. ..................       15,829              --
   Other ....................................................       35,817          22,802
                                                                ----------      ----------
      Total current liabilities .............................      812,908       1,150,338
                                                                ----------      ----------

Long-Term Liabilities
   11% senior notes .........................................      235,000         235,000
   Other ....................................................        5,316              --
                                                                ----------      ----------
      Total long-term liabilities ...........................      240,316         235,000
                                                                ----------      ----------
Commitments and Contingencies (Notes 10 and 12)

Additional Partnership Interests (Note 10) ..................        9,318           9,318
                                                                ----------      ----------

Partners' Capital
   Common Unitholders .......................................        2,685          47,832
   Subordinated Unitholders .................................       29,155          41,247
   General Partner ..........................................        6,128           7,285
                                                                ----------      ----------
      Total Partners' Capital ...............................       37,968          96,364
                                                                ----------      ----------

Total Liabilities and Partners' Capital .....................   $1,100,510      $1,491,020
                                                                ==========      ==========
</Table>


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



                                      F-4
<PAGE>



                            EOTT ENERGY PARTNERS, L.P
                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                                 (In Thousands)
<Table>
<Caption>

                                                                    YEAR ENDED DECEMBER 31,
                                                              -----------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES                            2001          2000         1999
                                                              ---------    ---------    ---------
                                                                          (UNAUDITED)  (UNAUDITED)
                                                                                        (RESTATED)
                                                                                         (NOTE 3)
<S>                                                           <C>          <C>          <C>
Reconciliation of net income (loss) to net cash
   provided by (used in) operating activities
      Net income (loss) ...................................   $ (15,233)   $  13,833    $     561
      Depreciation ........................................      33,469       32,813       31,164
      Amortization of intangible assets ...................       2,609        1,055        1,972
      Impairment of assets ................................      29,057           --           --
      Net unrealized change in crude oil trading activities       2,053         (960)          --
      (Gains) losses on disposal of assets ................         229         (799)        (636)
      Changes in components of working capital -
        Receivables .......................................     423,467       30,228     (563,087)
        Inventories .......................................       1,548       35,653       17,239
        Other current assets ..............................      (1,780)       5,290        1,137
        Trade accounts payable ............................    (550,547)      42,011      577,336
        Accrued taxes payable .............................      (1,909)      (1,192)       6,755
        Other current liabilities .........................      17,462        4,593       (5,369)
      Other assets and liabilities ........................       4,968       (8,339)       2,216
                                                              ---------    ---------    ---------
   Net Cash Provided by (Used in) Operating Activities ....     (54,607)     154,186       69,288
                                                              ---------    ---------    ---------

CASH FLOWS FROM INVESTING ACTIVITIES
   Proceeds from sale of property, plant and equipment ....      17,209        1,630        1,407
   Acquisitions ...........................................    (117,000)          --      (33,000)
   Additions to property, plant and equipment .............     (36,228)     (14,270)     (21,728)
   Other, net .............................................          --           29           --
                                                              ---------    ---------    ---------
   Net Cash Used In Investing Activities ..................    (136,019)     (12,611)     (53,321)
                                                              ---------    ---------    ---------

CASH FLOWS FROM FINANCING ACTIVITIES
   Decrease in short-term borrowings - affiliate ..........          --           --      (28,297)
   Decrease in bridge loan - affiliate ....................          --           --      (42,000)
   Decrease in term loan - affiliate ......................          --           --     (175,000)
   Increase in receivable financing .......................      42,500           --
   Increase in short-term borrowings ......................      40,000           --
   Increase (decrease) in repurchase agreements ...........     100,000      (74,055)      (8,961)
   Issuance of 11% senior notes ...........................          --           --      235,000
   Payment of financing issue expenses ....................          --           --       (7,558)
   Net proceeds from issuance of common units .............          --           --       52,920
   Distributions to unitholders ...........................     (43,163)     (37,586)     (30,380)
   Issuance of additional partnership interests ...........          --        6,771        2,547
   Other, net .............................................          --           --          254
                                                              ---------    ---------    ---------
   Net Cash Provided by (Used in) Financing Activities ....     139,337     (104,870)      (1,475)
                                                              ---------    ---------    ---------
Increase (Decrease) in Cash and Cash Equivalents ..........     (51,289)      36,705       14,492
Cash and Cash Equivalents Beginning of Period .............      54,230       17,525        3,033
                                                              ---------    ---------    ---------
Cash and Cash Equivalents End of Period ...................   $   2,941    $  54,230    $  17,525
                                                              =========    =========    =========

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
   Cash Paid for Interest .................................   $  33,041    $  29,925    $  24,742
                                                              =========    =========    =========
</Table>

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



                                      F-5
<PAGE>



                           EOTT ENERGY PARTNERS, L.P.
                  CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL
                                 (In Thousands)

<Table>
<Caption>


                                                            COMMON      SPECIAL    SUBORDINATED  GENERAL
                                                         UNITHOLDERS  UNITHOLDERS  UNITHOLDERS   PARTNER        TOTAL
                                                         -----------  -----------  ------------  ---------    ---------
<S>                                                      <C>          <C>          <C>           <C>          <C>
Partners' Capital at December 31, 1998 (Unaudited)
     (Restated) (Note 3) ..............................   $  13,968    $  20,967    $  37,936    $   1,682    $  74,553
Net income (loss) (Restated) (Note 3) .................        (720)         582          670           29          561
Cash distributions ....................................     (28,385)      (1,416)          --         (579)     (30,380)
Issuance of Common Units ..............................      52,920           --           --          535       53,455
Contribution of Additional Partnership Interests ......      15,905           --           --        6,023       21,928
Conversion of Special Units ...........................      20,133      (20,133)          --           --           --
                                                          ---------    ---------    ---------    ---------    ---------

Partners' Capital at December 31, 1999 (Unaudited) ....      73,821           --       38,606        7,690      120,117

Net income ............................................       9,116           --        4,441          276       13,833
Cash distributions ....................................     (35,105)          --       (1,800)        (681)     (37,586)
                                                          ---------    ---------    ---------    ---------    ---------

Partners' Capital at December 31, 2000 (Unaudited) ....      47,832           --       41,247        7,285       96,364

Net loss ..............................................     (10,042)          --       (4,892)        (299)     (15,233)
Cash distributions ....................................     (35,105)          --       (7,200)        (858)     (43,163)
                                                          ---------    ---------    ---------    ---------    ---------

Partners' Capital at December 31, 2001 ................   $   2,685    $      --    $  29,155    $   6,128     $ 37,968
                                                          =========    =========    =========    =========    =========
</Table>

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




                                      F-6
<PAGE>



                           EOTT ENERGY PARTNERS, L.P.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.    BASIS OF PRESENTATION

     EOTT Energy Partners, L.P. (the "MLP") is a Delaware limited partnership
which operates through its affiliated operating limited partnerships, EOTT
Energy Operating Limited Partnership, EOTT Energy Canada Limited Partnership,
EOTT Energy Pipeline Limited Partnership and EOTT Energy Liquids, L.P., each of
which is a Delaware limited partnership. In 1999, EOTT Energy Partners, L.P.
formed EOTT Energy Finance Corp. as a direct wholly-owned subsidiary of the MLP.
This entity was set up in connection with a debt offering to facilitate certain
investors' ability to purchase EOTT's senior notes, more fully described in Note
8. The terms "we", "EOTT" and the "Partnership" herein refer to EOTT Energy
Partners, L.P. and its affiliated limited partnerships.

     EOTT Energy Corp. (the "General Partner"), a Delaware corporation and a
wholly-owned subsidiary of Enron Corp. ("Enron"), serves as the sole general
partner of the MLP. In August 2001, we reorganized the ownership of our three
original operating partnerships, EOTT Energy Operating Limited Partnership, EOTT
Energy Pipeline Limited Partnership and EOTT Energy Canada Limited Partnership,
to make all of our operating partnerships 100% owned subsidiaries of the MLP. In
the reorganization, EOTT Energy Corp. exchanged its 1% general partner interests
in each of the three subsidiary partnerships for an additional 0.98% general
partner interest in the MLP. EOTT Energy General Partner, L.L.C., which is
wholly-owned by the MLP and serves as general partner of EOTT Energy Liquids,
L.P., now serves as general partner of the original three operating
partnerships. This reorganization was effected in order to save substantial
costs of compliance with Securities and Exchange Commission (the "SEC")
regulations adopted in 2000. In the absence of the reorganization, the rules
would require EOTT to provide separate, audited financial statements for each of
the three original operating partnerships in connection with any guaranteed
securities we might choose to register. The reorganization had no material
impact on the MLP or its unitholders because the interests contributed to EOTT
by the General Partner were at least equal in value to the additional 0.98%
general partner interest in the MLP issued in consideration for the
contribution. At December 31, 2001, EOTT Energy Corp. owned an approximate 1.98%
general partner interest in the MLP. Based upon information provided by Enron,
Enron beneficially owns approximately 18% of our outstanding common units, 78%
of our outstanding subordinated units and 37% of our total units outstanding
because it retains voting power and shared investment power over the securities.

     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 operations, is includable in the federal income tax returns of each
unitholder. 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 unitholders' tax attributes in the
Partnership.

     The accompanying consolidated financial statements and related notes
present the financial position as of December 31, 2001 and 2000 for the
Partnership, and the results of its operations, cash flows and changes in
partners' capital for the years ended December 31, 2001, 2000 and 1999. For the
years ended December 31, 2001, 2000 and 1999, traditional net income and
comprehensive income are the same.

     We have restated our financial results for the years 1998 and 1999 as more
fully discussed in Note 3. The restatement is related to losses incurred in
connection with the theft of NGL product, concealment of commercial activities
and other unauthorized activities by a former employee. As a result of the
restatement, reported net income for the year 1998 is decreased by $1.0 million
and reported net income for the year 1999 is increased by $1.0 million. As more
fully discussed in Note 3, the financial statements presented herein for the
years 1999 and 2000 are unaudited.


                                      F-7
<PAGE>

                           EOTT ENERGY PARTNERS, L.P.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


     Certain reclassifications have been made to prior period amounts to conform
with the current period presentation. Additionally, we have made certain
reclassifications and revisions to our income statement presentation. We now
reflect as a component of "gross profit," all costs associated with the
production of revenues (including costs of sales, operating expenses and
applicable depreciation and amortization). This contrasts with prior year
presentations that included the cost of products and associated transportation
costs as components of "gross margin." Additionally, certain other income and
expenses (including gains and losses on assets sales and income or expense
related to litigation settlements) which were previously classified as "Other,
net" have been reclassified and are reflected as a component of "Operating
Income." These reclassifications had no impact on reported net income.

2.   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

     Principles of Consolidation. We own and operate our assets through our
operating limited partnerships. The accompanying financial statements reflect
the consolidated accounts of the MLP and the operating limited partnerships
after elimination of intercompany transactions.

     Nature of Operations. Through our affiliated limited partnerships, EOTT
Energy Operating Limited Partnership, EOTT Energy Canada Limited Partnership,
EOTT Energy Pipeline Limited Partnership, and EOTT Energy Liquids, L.P., we are
engaged in the purchasing, gathering, transporting, trading, storage and resale
of crude oil and refined petroleum products, natural gas liquids ("NGLs") and
related activities. We are also engaged in the operation of a hydrocarbon
processing plant (the "MTBE Plant") and a natural gas liquids storage facility
(the "Mont Belvieu Facility"). Our principal business segments are North
American Crude Oil - East of Rockies crude oil gathering and marketing
operations, Pipeline Operations, Liquids Operations, and West Coast Operations.

     Cash Equivalents. We record as cash equivalents all highly liquid
short-term investments having original maturities of three months or less.

     Inventories. Inventories are summarized as follows (in thousands):

<Table>
<Caption>

                                                                                December 31,
                                                                             -----------------
                                                                              2001       2000
                                                                             ------- ----------
                                                                                     (Unaudited)
<S>                                                                          <C>       <C>
         Crude oil .......................................................   $76,207   $77,282

         Refined products ................................................     3,903     6,148

         Natural gas liquids (includes finished product and feedstock) ...     4,287     1,223

         Materials and supplies ..........................................     5,288        --
                                                                             -------   -------

         Total ...........................................................   $89,685   $84,653
                                                                             =======   =======
</Table>

     At December 31, 2001, crude oil and refined products inventories used in
our trading and marketing operations are valued at fair value. Crude oil
inventory in our Pipeline Operations, and natural gas liquids inventory are
valued at average cost. Materials and supplies, which consist of spare parts
used at our MTBE Plant, are also valued at average cost. At December 31, 2000,
all inventories were valued at average cost. See Note 4 for information
regarding the change in inventory costing methodology for inventories used in
our energy trading activities.


                                      F-8
<PAGE>


                           EOTT ENERGY PARTNERS, L.P.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Property, Plant and Equipment ("PP&E"). The components of PP&E, at cost, are as
follows (in thousands):

<Table>
<Caption>

                                                                                   December 31,
                                                                             -------------------------
                                                                               2001            2000
                                                                             ---------     -----------
                                                                                           (Unaudited)
<S>                                                                          <C>           <C>

        Operating PP&E, including pipelines, storage tanks, etc ....         $ 504,010     $  491,625
        Liquids storage facility (Mont Belvieu Facility)....................    46,523             --
        Office PP&E, including furniture and fixtures.......................    43,701         42,233
        Hydrocarbon processing facility (MTBE Plant)........................    34,546             --
        Tractors and trailers...............................................    10,878         13,898
        Buildings and leasehold improvements................................     9,093         11,413
        Land................................................................     8,242          3,224
                                                                             ---------     ----------
           Total PP&E, at cost.............................................. $ 656,993     $  562,393
                                                                             =========     ==========
</Table>

     Normal maintenance and repairs are charged to expense as incurred while
significant improvements which extend the life of the asset are capitalized.
Upon retirement or sale of an asset, the asset and the related accumulated
depreciation are removed from the accounts and any resulting gain or loss is
reflected in the results of operations.

     Costs incurred in connection with planned major maintenance activities at
our MTBE Plant (turnaround costs) are deferred when incurred and amortized on a
straight-line basis over the period of time estimated to lapse until the next
turnaround occurs. These costs include repairing, restoring or replacing
processing equipment. Turnaround activities are anticipated to occur every four
years, with the most recent turnaround having been completed during the first
quarter of 2002.

     Impairment of Assets. We evaluate impairment of our long-lived assets in
accordance with Statement of Financial Accounting Standards ("SFAS") No. 121
"Accounting for the Impairment of Long-Lived Assets to Be Disposed Of", and
effective January 1, 2002 SFAS No. 144 "Accounting for the Impairment or
Disposal of Long-Lived Assets," and would recognize an impairment when estimated
future cash flows associated with an asset or group of assets are less than the
asset carrying amount. Certain assets included in PP&E, primarily pipelines and
the MTBE Plant, are subject to factors which could affect future cash flows.
These factors include competition, regulation, environmental matters,
consolidation in the industry, refinery demand for specific grades of crude oil,
area market price structures and continued developmental drilling in certain
areas of the United States. We continuously monitor these factors and pursue
alternative strategies to maintain or enhance cash flows associated with these
assets; however, no assurances can be given that we can mitigate the effects, if
any, on future cash flows related to any changes in these factors.

     Depreciation. Depreciation is provided by applying the straight-line method
to the cost basis of property, plant and equipment, less estimated salvage
value, over the estimated useful lives of the assets. Asset lives are 15 to 20
years for barging, terminaling, gathering and pipeline facilities, 5 to 10 years
for transportation equipment, 20 to 25 years for the MTBE Plant and the Mont
Belvieu Facility and 3 to 20 years for other buildings and equipment.

     Amortization. Goodwill is amortized over a period of 10 to 15 years, and is
recorded net of its accumulated amortization in Other Assets. Accumulated
amortization of goodwill at December 31, 2001 and 2000 was $32.0 million and
$30.9 million, respectively.

     In July 2001, the Financial Accounting Standards Board (FASB) issued SFAS
No. 142, "Goodwill and Other Intangible Assets." SFAS No. 142, which must be
applied to fiscal years beginning after December 15, 2001, modifies the
accounting and reporting of goodwill and intangible assets. The pronouncement
requires


                                      F-9
<PAGE>

                           EOTT ENERGY PARTNERS, L.P.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



entities to discontinue the amortization of goodwill, reallocate all existing
goodwill among its reporting segments based on criteria set by SFAS No. 142 and
perform initial impairment tests by applying a fair value-based analysis on the
goodwill in each reporting segment. Any impairment at the initial adoption date
shall be recognized as the effect of a change in accounting principle.
Subsequent to the initial adoption, goodwill shall be tested for impairment
annually or more frequently if circumstances indicate a possible impairment.
Under SFAS No. 142, entities are required to determine the useful life of other
intangible assets and amortize the value over the useful life. If the useful
life is determined to be indefinite, no amortization will be recorded. For
intangible assets recognized prior to the adoption of SFAS No. 142, the useful
life should be reassessed. Other intangible assets are required to be tested for
impairment in a manner similar to goodwill. While we do not expect the adoption
of SFAS No. 142 to have a material impact on our results of operations, we have
not yet completed our initial impairment tests. At December 31, 2001, we have
$7.4 million of net goodwill in Other Assets. Goodwill amortization totaled $1.1
million, $1.1 million and $2.0 million for the years 2001, 2000 and 1999
respectively.

     Pipeline Linefill. Pipeline linefill, which consists of minimum operating
requirements, is recorded at cost. Total minimum operating linefill requirements
held in third party pipelines and our pipelines at December 31, 2001 and 2000
were 3.2 million barrels at a cost of $52.9 million and 3.5 million barrels at a
cost of $54.6 million, respectively. Minimum linefill requirements in third
party pipelines at December 31, 2001 and 2000 were valued at $13.6 million and
$16.8 million, respectively, and classified as Other Current Assets on the
balance sheet. Minimum linefill requirements held in our pipelines at December
31, 2001 and 2000, were valued at $39.3 million and $37.8 million, respectively,
and classified as Property, Plant and Equipment on the balance sheet.

     Hedging/Energy Trading/Derivative Activities. We purchase crude oil at
field gathering points as well as in bulk at major pipeline terminal points and
major marketing points. Generally, as we purchase crude oil, we enter into
corresponding sales transactions involving physical deliveries of crude oil to
third party users, such as independent refineries, or corresponding sales of
futures contracts on the New York Mercantile Exchange ("NYMEX"). This process
enables us to minimize our exposure to commodity price risk during the time from
our crude oil purchase until we make physical delivery of the crude oil. After
the initial purchase of a barrel of crude oil, we may re-market that barrel both
in the futures and physical markets in order to maximize the value of the
volumes purchased.

     We enter primarily into commodity futures transactions in an effort to
minimize the impact of market fluctuations on inventories and contractual
commitments for the purchase and sale of crude oil. Based on the historical
correlations between the NYMEX price for West Texas Intermediate crude at
Cushing, Oklahoma and the various marketing hubs, where we market crude oil, we
believe the hedging program has been effective in reducing our overall risk. We
continuously monitor the basis differentials between our various trading hubs
and Cushing, Oklahoma to further manage our basis exposure.

     Prior to January 1, 2001, the derivative instruments described above
qualified for hedge accounting as they reduced the price risk of the underlying
hedged item and were designated as a hedge at inception. Additionally, as the
instrument terms were matched with respect to the underlying crude oil type,
delivery period requirements and quantity being hedged, the derivatives resulted
in financial price risk impacts which were inversely correlated to those of the
items being hedged.

     Realized and unrealized changes in the market value of these transactions,
which were entered into and accordingly designated as hedges, were deferred
until the gain or loss on the hedged transaction was recognized in accordance
with SFAS No. 80 "Accounting for Futures Contracts." The financial impacts of
crude oil hedge contracts were included in our Consolidated Statements of
Operations as a component of costs


                                      F-10
<PAGE>

                           EOTT ENERGY PARTNERS, L.P.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


of sales. Such financial impacts were offset by gains or losses realized in the
physical market. Any cash flow recognition resulting from hedging activities was
treated in the same manner as the underlying transaction.

     Beginning January 1, 2001, we are reporting derivative activities in
accordance with SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities," as amended. SFAS No. 133 requires that derivative instruments
(including certain derivative instruments embedded in other contracts) be
recorded in the balance sheet as either assets or liabilities measured at fair
value. SFAS No. 133 requires that changes in the derivative's fair value be
recognized currently in earnings unless specific hedge accounting criteria are
met. Special accounting for qualifying hedges allows a derivative's gains and
losses to offset related results from the hedged item in the income statement,
and requires that a company formally document, designate, and assess the
effectiveness of transactions that receive hedge accounting. Under SFAS No. 133,
we are required to "mark-to-fair value" all of our derivative instruments at the
end of each reporting period. This contrasts with previous accounting principles
which generally only required our transactions designated as energy trading
activities to be marked-to-fair value. SFAS No. 133 requires that as of the date
of the initial adoption, the difference between the fair value of derivative
instruments and the previous carrying amount of those derivatives be recorded in
net income or other comprehensive income, as appropriate, as the cumulative
effect of a change in accounting principle. The cumulative effect of adopting
SFAS No. 133 effective January 1, 2001 was $1.3 million ($0.05 per diluted unit)
and is reflected as an increase in income in the Consolidated Statement of
Operations. We have not designated any derivatives as hedging instruments.

     Emerging Issues Task Force ("EITF") Issue 98-10, "Accounting for Contracts
Involved in Energy Trading and Risk Management Activities" was adopted January
1, 1999. EITF Issue 98-10 requires energy trading contracts (as defined) to be
recorded at fair value in the balance sheet with changes in fair value included
in earnings. The cumulative effect of adopting EITF Issue 98-10 was $1.7 million
and is reflected as an increase in income in the Consolidated Statement of
Operations.

     Revenue Recognition. We recognize revenue on the accrual method, for
non-energy trading activities and non-derivative instruments, based on the right
to receive payment for goods and services delivered to third parties. We review
our portfolio of transactions to assess contracts which qualify as energy
trading activities. Substantially all of our current gathering, marketing and
trading activities are accounted for on a mark-to-fair value basis. Qualifying
derivative instruments are accounted for pursuant to SFAS No. 133 with the
remaining energy trading activities accounted for pursuant to EITF Issue 98-10.

     Changes in the market value of transactions designated as energy trading
activities in accordance with EITF Issue 98-10, and derivative instruments
accounted for under SFAS No. 133, are recorded in revenues every period as
mark-to-fair value gains or losses. The related price risk management assets and
liabilities are recorded in other current or non-current assets and liabilities,
as applicable, on the balance sheet. The fair value of transactions designated
as energy-trading activities is determined primarily based on forward prices of
the commodity, adjusted for certain transaction costs associated with the
transactions. For the years ended December 31, 2001, 2000 and 1999, we had net
mark-to-fair value losses of $2.5 million (which includes $2.6 million of income
related to the fair value of inventory), $3.6 million and $5.6 million,
respectively.

     Certain estimates were made in determining the fair value of contracts. We
have determined these estimates using available market data and valuation
methodologies. Judgment may be required in interpreting data, and the use of
different market assumptions or estimation methodologies may affect the
estimated fair value amounts.

     Cost of Sales and Operating Expenses. Cost of sales includes the cost of
product such as crude oil, refined products, feedstocks for the MTBE Plant and
associated transportation costs. Operating expenses consist of


                                      F-11
<PAGE>


plant, field and pipeline expenses, including payroll and benefits, utilities,
telecommunications, fuel and power, environmental expenses and property taxes.

     Other (Income) Expense. The components of other (income) expense are as
     follows (in thousands):

<Table>
<Caption>

                                                                Year Ended December 31,
                                                         -------------------------------
                                                           2001       2000       1999
                                                         -------      -----      -----
                                                                   (Unaudited)(Unaudited)
<S>                                                      <C>       <C>         <C>
         (Gain) loss on disposal of fixed assets .....     $ 229      $(799)     $(636)
         Litigation settlements and provisions .......       528         89       (256)
         Other .......................................      (547)       428        (97)
                                                           -----      -----      -----
              Total ..................................     $ 210      $(282)     $(989)
                                                           =====      =====      =====
</Table>

     Other, Net. The components of other, net, are as follows (in thousands):


<Table>
<Caption>

                                                                      Year Ended December 31,
                                                                ---------------------------------
                                                                 2001         2000         1999
                                                                -------      -------      -------
                                                                           (Unaudited)  (Unaudited)
<S>                                                             <C>          <C>          <C>
         Gain (loss) on foreign currency transactions .....     $  (341)     $  (366)     $   485
         Discount fees on sale of receivables .............        (176)      (2,260)        (732)
                                                                -------      -------      -------
              Total .......................................     $  (517)     $(2,626)     $  (247)
                                                                =======      =======      =======
</Table>

     SFAS No. 140 "Accounting for Transfers and Servicing of Financial Assets
and Extinguishments of Liabilities - A Restatement of FASB Statement No. 125"
was effective March 31, 2001. Under SFAS No. 140, certain accounts receivable
under our Receivables Agreement, discussed further in Note 8, are accounted for
as financings. Previously, these transfers were accounted for as sales in
accordance with the provisions of SFAS No. 125. Under SFAS No. 125, the
transferred receivables were removed from the balance sheet and costs associated
with the transfers were included in "Other, net" on the income statement. Under
SFAS No. 140, the transferred receivables and the related receivable financing
remain on the balance sheet and costs associated with the transfers are
classified as "Interest Expense and Related Charges" on the Consolidated Income
Statement.

     Foreign Currency Transactions. Canadian operations represent all of our
foreign activities. The U.S. dollar is the functional currency. Foreign currency
transactions are initially translated into U.S. dollars. The resulting gains and
losses are included in the determination of net income (loss) in the period in
which the exchange rate changes.

     Environmental. Expenditures for ongoing compliance with environmental
regulations that relate to current operations are expensed or capitalized as
appropriate. Estimated liabilities are recorded when environmental assessments
indicate that remedial efforts are probable and the costs can be reasonably
estimated. Estimates of the liability and insurance recovery, if any, are based
upon currently available facts, existing technology and presently enacted laws
and regulations. The estimated environmental liability at December 31, 2001 and
2000 was $6.8 million and $3.0 million, respectively, and was classified in
Other


                                      F-12
<PAGE>


                           EOTT ENERGY PARTNERS, L.P.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Current and Other Long-Term Liabilities in 2001 and Other Current Liabilities in
2000. The estimated insurance recoveries recorded at December 31, 2001 and 2000
were $9.1 million and $3.8 million, respectively, and were classified in Trade
and Other Receivables. These estimated liabilities and recoveries from insurance
are subject to revision in future periods based on actual costs or new
information and are included in the balance sheet at undiscounted amounts.

     Use of Estimates. The preparation of financial statements in conformity
with generally accepted accounting principles requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.

3.   RESTATEMENT OF FINANCIAL RESULTS

     As initially reported in our Annual Report on Form 10-K for the year ended
December 31, 1999, in the fourth quarter of 1999 we recorded a $6.2 million
charge related to the theft of NGL product, concealment of commercial activities
and other unauthorized activities by a former employee. The unauthorized
activities centered around two transactions entered into by the former employee.
The first transaction involved an exchange transaction entered into in December
1998. The exchange provided for us to receive 100,000 barrels of butane from a
third party in December 1998 and deliver back the 100,000 barrels of butane to
the same third party in January 2000. The second transaction involved a propane
sale contract entered into in April 1999 that provided for the sale of 337,500
barrels of propane at $0.25 cents per gallon. The 337,500 barrels were
originally to be delivered in December 1999. In December 1999, the sales
contract was amended to provide for delivery of the 337,500 barrels of propane
in the fourth quarter of 2000 at $0.215 cents per gallon. We discovered these
unauthorized activities in January 2000 and recorded a $6.2 million charge
related to these transactions in the fourth quarter of 1999.

     In connection with a proxy filing in the fall of 2001 concerning a planned
recapitalization, which was subsequently terminated due to the Enron bankruptcy,
the SEC reviewed previous 1934 Act filings and we received comments from the SEC
to which we are responding. In response to certain SEC comments regarding the
unauthorized trading activities, we are restating prior year financial results
to reflect the fair value impact of these transactions over the periods during
which the contracts were outstanding. The restatements relate to the timing of
the recognition of the loss on the transactions and do not impact total
Partners' Capital at December 31, 2001 or 2000. The restatement results in a
decrease in net income for the year 1998 of $1.0 million ($0.05 per diluted
unit) and a corresponding increase in net income for the year 1999 of $1.0
million ($0.04 per diluted unit).

     On February 5, 2002, Arthur Andersen LLP ("Andersen") withdrew as our
independent accountants. We were informed that Andersen's withdrawal related to
Andersen's professional standards concerns, including auditor independence
issues, related to events involving Enron. The restatement of our financial
statements for the years 1998 and 1999, and the quarterly periods in 1999 and
2000, requires the issuance of an updated audit opinion covering the years 1999
and 2000 from Andersen or the issuance of a new audit opinion covering those
years by a new independent accountant. Since Andersen has advised us that they
will not issue an updated opinion due to the independence issues related to
their resignation, and PricewaterhouseCoopers LLP's ("PWC") engagement for
purposes of this Annual Report is presently limited to an audit of 2001, we are
filing unaudited financial statements for the years 1999 and 2000 with this
Annual Report. We have requested PWC to consider auditing the affected periods
and they are reviewing our request. We will consider alternatives for obtaining
an audit of the affected periods, as necessary. We can give no assurances we
will be able to obtain an audit of the affected periods. The independent
auditors' reports of Andersen on our financial statements during 1999 and 2000
did not contain an adverse opinion or a disclaimer of opinion, and were not
qualified or modified as to uncertainty, audit scope or accounting principles.


                                      F-13
<PAGE>


                           EOTT ENERGY PARTNERS, L.P.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


However, the restated financial statements for 1999 and 2000 contained in this
Annual Report are not covered by an audit report or opinion of any kind.

     A summary of the effects of the restatements on reported amounts for the
years ended December 31, 1998 and 1999 are presented below. The effects on
reported amounts for the quarterly periods in the years 1999 and 2000 are
presented in Note 17. (Amounts in thousands, except per share amounts)

<Table>
<Caption>

                                     Year Ended December 31, 1999          Year Ended December 31, 1998
                                  ----------------------------------       ----------------------------
                                   As Reported           As Restated       As Reported      As Restated
                                   -----------           -----------       -----------      -----------
                                   (Unaudited)           (Unaudited)       (Unaudited)      (Unaudited)
<S>                                <C>                   <C>               <C>              <C>
Revenues                           $ 8,664,401           $8,664,401        $ 5,294,697      $ 5,294,697
Gross Profit                            73,205               74,234             51,100           50,071
Operating Income                        26,974               28,003              6,479            5,450
Net Income                                (468)                 561             (4,067)          (5,096)
Diluted Earnings Per Unit                (0.02)                0.02              (0.21)           (0.26)
</Table>


4.   CHANGE IN ACCOUNTING PRINCIPLE

     In the first quarter of 2001, we changed our method of accounting for
inventories used in our energy trading activities from the average cost method
to the fair value method. In executing these activities, we use both physically
stored and contracted purchase barrels to meet our obligations. We believe fair
value accounting for inventories used in our energy trading activities is
preferable because it better informs users of the financial statements of our
net commodity price risk and it better aligns financial reporting for this
inventory with the way in which price risk is measured and managed as part of
our energy trading activities.

     The cumulative effect of the change in accounting for inventories as of
January 1, 2001 was $0.2 million ($0.01 per diluted unit) and is reported as a
decrease in net income for 2001. The change in accounting for inventories
increased reported net income in 2001 by approximately $2.6 million. On a pro
forma basis, assuming the new inventory valuation method had been applied
retroactively, reported net income for the year 1999 would have increased by
$1.2 million.


5.   ACQUISITION AND DISPOSITIONS OF ASSETS

     Acquisition of Liquids Operations

     Assets Acquired/Long-Term Contracts. Effective June 30, 2001, through a
newly created, wholly-owned subsidiary, EOTT Energy Liquids, L.P., a Delaware
limited partnership, we purchased certain liquids processing, storage and
transportation assets located in the Texas Gulf Coast region. We paid $117
million in cash to Enron and State Street Bank and Trust Company of Connecticut,
National Association, Trustee (the "Trustee"). The assets held by the Trustee
were held under a lease financing arrangement with Enron. Immediately prior to
the acquisition, all of the assets were operated by EGP Fuels Company, a
Delaware corporation and wholly-owned subsidiary of Enron ("EGP Fuels").

     This acquisition included (i) the MTBE Plant, located in Morgan's Point,
Texas, which processes approximately 16,000 barrels per day and is currently
being used for the production of isobutylene and methyl tertiary butyl ether
("MTBE"), (ii) the Mont Belvieu Facility, a natural gas liquids storage
facility, located in Mont Belvieu, Texas, that consists of ten active storage
wells with a total capacity of approximately ten million barrels,


                                      F-14
<PAGE>


                           EOTT ENERGY PARTNERS, L.P.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


(iii) a liquids pipeline grid system used for the transportation of natural gas
liquids and other products to and from the Mont Belvieu Facility and the MTBE
Plant and other distribution points and (iv) loading, unloading and
transportation facilities that are associated with the foregoing (collectively,
the "Assets").

     We acquired the Assets pursuant to the terms of a purchase and sale
agreement between the Partnership and Enron (the "Agreement"). The Agreement
contained representations and warranties of the parties and certain indemnity
agreements.

     Concurrently with the acquisition of the Assets described above, we entered
into a ten-year tolling agreement for the conversion of feedstocks into
products, on a take-or-pay basis ("Toll Conversion Agreement"), and a ten-year
storage and transportation agreement for the use of a significant portion of the
Mont Belvieu Facility and pipeline grid system, on a take-or-pay basis ("Storage
Agreement"). Both agreements were with Enron Gas Liquids, Inc. ("EGLI"), a
wholly-owned subsidiary of Enron, which is now in bankruptcy. Under these
agreements EGLI retained all existing third party commodity, transportation and
storage contracts associated with these facilities. These agreements were the
principle basis for determining the desirability of the transaction and the
purchase price of the Assets. See further discussion of the terms of the Toll
Conversion and Storage Agreements below.

     The purchase price of $117 million was based upon the estimated value of
the Assets and the associated long-term contracts. Allocation of the purchase
price to the acquired Assets in accordance with Accounting Principles Board
Opinion No. 16 resulted in an increase in property, plant and equipment and
materials and supplies of approximately $82 million and $5 million respectively.
Approximately $30 million of the purchase price was allocated to the long-term
contracts (see further discussion below and in Note 7). Due to the related party
nature of the transaction, the terms of the transaction and related contracts
were reviewed by the Audit Committee of our General Partner, which consisted of
three directors who were not employees of the General Partner or any other
affiliate of Enron. The Audit Committee engaged its own counsel and an
investment banking firm that rendered an opinion as to the fairness of the
transaction from a financial point of view. The Audit Committee and the Board of
Directors of our General Partner (including the disinterested directors)
unanimously approved the transaction. We financed the purchase price through
short-term borrowings from Standard Chartered Trade Services Corporation
("SCTS") available under inventory and receivable financing facilities. These
facilities were increased to an aggregate amount of $300 million by the
Partnership on an interim basis. See further discussion in Note 8.

     Current Status of Agreements. As more fully explained in Note 10, on
December 3, 2001, EGLI was included in Enron's bankruptcy filing. Due to the
non-performance by EGLI under the Toll Conversion Agreement in late November
2001, we began to operate the MTBE Plant as a merchant operation in the spot
market. We were unable to market the Mont Belvieu Facility or enter into third
party spot or term contracts until the Storage Agreement was rejected by EGLI.

     On April 2, 2002, the Bankruptcy Court entered a stipulation and agreed
order rejecting the Toll Conversion and Storage Agreements (the "Stipulation"),
which order became final and non-appealable on April 12, 2002. Rejection of the
Storage Agreement with EGLI resulted in the loss of the buyer of the fixed
throughput and storage capacity at the Mont Belvieu Facility. However, the
rejection allows us to directly seek new customers and pursue long-term
contracts for the Mont Belvieu Facility to replace the long-term and continuous
stream of revenue we expected under the Storage Agreement with EGLI. Although we
expect to use some of our storage capacity in our operations and marketing
activities related to the MTBE Plant, we expect to market the majority of the
storage capacity to third parties, preferably those with a presence in Mont
Belvieu, Texas.


                                      F-15
<PAGE>


                           EOTT ENERGY PARTNERS, L.P.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


     As a result of the rejection of the Toll Conversion Agreement, our
operation of the MTBE Plant has been converted to a merchant operation, which
means that we take title to feedstocks and sell products directly to third
parties, as opposed to providing tolling services to EGLI. This means that we
bear the risk of physical loss associated with storing these feedstocks and
products. We are also subject to a significant increase in commodity price risk
for feedstocks and marketing and commodity price risk associated with owning and
selling MTBE and other end products, which may vary based on factors beyond our
control. Additionally, our cash flow over the expected life of this asset will
likely vary significantly from levels previously forecast under the contracts
with EGLI. We are continuing to operate the assets and are examining long-term
options for their operation which could include long-term tolling arrangements
with third parties or a sale of the MTBE Plant.

     Terms of the Rejected Contracts. Under the Toll Conversion Agreement, we
agreed to convert feedstocks into liquid petroleum gas products for a fee. We
expected to satisfy our obligations under this agreement by processing
feedstocks at the MTBE Plant. Under this agreement, we agreed to convert
feedstocks to MTBE, a mix of isobutylene and isobutane, mixed butane, a mix of
propane and propylene or other liquid petroleum gas mix products (collectively,
the "Products"), in each case as designated by EGLI on a quarterly basis,
provided that not less than 85% of the mix of Products to be produced in a
particular calendar quarter (or not less than 78% under certain circumstances)
would be MTBE. EGLI was obligated to nominate, for each calendar month,
feedstocks that would enable us to produce a daily average of not less than
504,000 gallons of MTBE nor more than 693,000 gallons of MTBE, subject to
certain exceptions, based on assumed yields from specified feedstocks. We
believe that the MTBE Plant has the ability to produce approximately 650,000
gallons of MTBE per day per month under normal operating conditions, excluding
quarters which include a major turnaround. EGLI was required to use commercially
reasonable efforts to deliver feedstocks to the MTBE Plant (or another mutually
agreeable delivery point) in specified quantities that correspond to the
Products into which feedstocks were to be converted as specified by EGLI. EGLI
was obligated to accept delivery of all Products we produced except for Products
that did not conform to required specifications.

     The processing fee payable under the agreement was determined by
negotiations between EOTT and EGLI. In connection with these negotiations, we
considered, among other factors, the proposed purchase price for the assets,
recent historical and projected future operating and capital costs of the MTBE
Plant and our proposed obligations relating to conversion of feedstocks into
Products. The processing fee agreed to by the parties was a fixed fee paid to us
by EGLI for each gallon of MTBE or its equivalent (as specified in the
agreement) we produced in a calendar quarter up to a specified number of gallons
(the "Minimum Quarterly Conversion Quantity"), which fee was to escalate on an
annual basis commencing on January 1, 2003. Additionally, for each gallon of
MTBE or its equivalent in a quarter in excess of the Minimum Quarterly
Conversion Quantity, EGLI was obligated to pay us a separate fee that was based
on a formula that took into account market prices for MTBE and market prices for
specified feedstocks during such quarter. We believed that we would earn a
market favorable internal rate of return on our capital investment during the
term of the Toll Conversion Agreement if we produced the Minimum Quarterly
Conversion Quantity of Products each quarter, operated the MTBE Plant on a basis
consistent with historical operating costs and kept the capital and plant
turnaround costs in line with the estimates we made prior to the acquisition.

     The Toll Conversion Agreement obligated EGLI to pay us the same specified
conversion fee with respect to the Minimum Quarterly Conversion Quantity even if
EGLI failed to request conversion of feedstocks into Products in an amount at
least equal to the Minimum Quarterly Conversion Quantity and even if EGLI failed
to deliver feedstocks in specified quantities that would enable EOTT to produce
the Minimum Quarterly Conversion Quantity of Products (based on assumed yields).
The agreement obligated us to pay EGLI liquidated damages in the event EGLI
requested conversion of feedstocks into Product and delivered the specified
feedstocks to us, but we failed to deliver the Minimum Quarterly Conversion
Quantity of Products that satisfied the quality specifications.


                                      F-16
<PAGE>

                           EOTT ENERGY PARTNERS, L.P.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



     At any time during the term of the Toll Conversion Agreement, EGLI had the
option to require us to enter into an amendment to the agreement to (i) change
the types of products to be produced by us to isooctane, isobutylene, isobutane
or other products that EGLI may reasonably request and (ii) make a corresponding
change to the feedstocks to be provided by EGLI. In the event that EGLI
exercised this option, the conversion fee was to be adjusted to enable us to
realize a market rate of return, consistent with the market rate of return
realized by us with respect to the tolling arrangement prior to any such
amendment, on the sum of (x) the cost to convert the MTBE Plant (or a separate
facility as may be agreed to by EOTT and EGLI) to produce such new products, as
determined by an independent engineering firm, (y) commercially reasonable
operating and maintenance costs for the facility as determined by an independent
third party and (z) a specified dollar amount that decreases periodically
throughout the term of the agreement. We expected that, upon exercise of this
option, the conversion fees payable by EGLI would increase as a result of this
negotiation due primarily to capital costs that would be necessary to convert
the complex to produce other products.

     In the event that EGLI defaulted in its obligation to nominate the required
quantities of Products to be produced by us, failed to deliver the required
feedstocks relating to the Products to be produced, failed to make required
payments or otherwise failed to notify us of our obligations under the Toll
Conversion Agreement, we had the right to terminate the agreement and recover
damages calculated based on the present value of the conversion fees that we
would otherwise have received over the remaining term of the agreement. In the
event that EGLI determined that it no longer desired to have us produce MTBE due
to changes in environmental regulation or otherwise and EGLI did not exercise
its option to amend the agreement to provide for a new mix of products, then we
would be entitled to recover damages and termination costs from EGLI under this
provision. See further discussion regarding EOTT's relationships with Enron,
possible claims against Enron, and other recent developments with Enron in Note
10.

     Under terms of the Storage Agreement, we agreed to provide EGLI storage
capacity for natural gas liquids and liquid petroleum gas mixtures in ten
underground storage wells acquired by us as part of the acquisition. We also
agreed to provide EGLI with pipeline transportation services for such products
pursuant to a pipeline system that services the storage wells. The storage
capacity and transportation capabilities available to EGLI were subject to
nomination procedures as well as scheduling and customary operational
restrictions, including constraints relating to the maximum quantities of
products that could be injected or withdrawn from the storage wells. EGLI was
obligated to pay storage fees to us based on a fixed rate which escalated
annually and annual volume numbers agreed to by the parties and additional
storage and transportation fees based on the actual quantities of products
stored and transported according to a fee schedule.

     Pro Forma Results. Detailed below are our unaudited summarized pro forma
results of operations for the years ended December 31, 2001 and 2000 as though
the acquisition had taken place at the beginning of each of the respective
years. The pro forma results of operations only include the effects of the Toll
Conversion and Storage Agreements from July 1, 2001 to the date of EGLI's
bankruptcy filing. From June 30, 2001, the effective date of the acquisition of
the Assets, through December 31, 2001, we recognized $37.5 million of revenues
related to the Toll Conversion and Storage Agreements with EGLI. Pro forma
adjustments include higher depreciation expense, elimination of income taxes,
and lower interest expense related to the financing of the acquisition.


                                      F-17
<PAGE>



                           EOTT ENERGY PARTNERS, L.P.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


     The unaudited pro forma results of operations are not indicative of actual
operating results had the transactions occurred when indicated, nor do they
purport to indicate operating results that may occur in the future.

(Unaudited:  in thousands, except per unit amounts)

<Table>
<Caption>

                                                          PRO FORMA FOR THE
                                                             YEARS ENDED
                                                             DECEMBER 31,
                                                    ----------------------------
                                                        2001             2000
                                                    -----------      -----------
<S>                                                 <C>              <C>
Revenue .......................................     $ 8,708,947      $11,832,338
Gross Profit ..................................     $   105,868      $   101,651
Net Income(1) .................................     $   (18,095)     $     7,816
Diluted Net Income per Unit ...................     $     (0.65)     $      0.28
</Table>

     (1) The 2001 amount includes the $29.1 million impairment of the EGLI
contracts.

Acquisition From Texas - New Mexico Pipe Line Company

     On May 1, 1999, we acquired crude oil transportation and storage assets in
West Texas and New Mexico from Texas-New Mexico Pipe Line Company, which
included approximately 1,800 miles of common carrier crude oil pipelines. We
paid $33 million in cash and recorded a $4 million liability related to assumed
environmental obligations and financed the total acquisition cost using
short-term borrowings from Enron.

Dispositions

     Effective June 30, 2001, we sold our West Coast crude oil gathering and
blending operations to Pacific Marketing and Transportation LLC for $14.3
million. We could be required to repay up to $1.5 million of the sale price,
subject to a two-year look-back provision regarding average operating results
during the period July 1, 2001 through June 30, 2003. Such amount is reflected
in Other Long-Term Liabilities in the Consolidated Balance Sheet at December 31,
2001.


                                      F-18
<PAGE>


                           EOTT ENERGY PARTNERS, L.P.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



6.   EARNINGS PER UNIT

     Basic earnings per unit includes the weighted average impact of outstanding
units of EOTT (i.e., it excludes unit equivalents). Diluted earnings per unit
considers the impact of all potentially dilutive securities (including the
conversion of subordinated units into common units). Net income (loss) shown in
the table below excludes the approximate two percent interest of the General
Partner. Earnings (loss) per unit are calculated as follows (in thousands,
except per unit amounts):

<Table>
<Caption>

                                2001                             2000 (Unaudited)                 1999 (Restated) (Unaudited)
                 ------------------------------       --------------------------------     ---------------------------------
                               Wtd                                  Wtd.                       Net         Wtd
                    Net      Average     Per            Net        Average       Per         Income       Average      Per
                  (Loss)      Units      Unit         Income        Units       Unit         (Loss)       Units       Unit
                 --------    -------   --------       --------   ----------   --------     ----------   ----------  --------
<S>              <C>         <C>       <C>            <C>          <C>        <C>          <C>            <C>        <C>
Basic:(1)
   Common        $(10,042)   18,476    $  (0.54)      $  9,116     18,476     $   0.49     $   (138)      15,877     $(0.01)
   Subordinated  $ (4,892)    9,000    $  (0.54)      $  4,441      9,000     $   0.49     $    670        9,000     $ 0.07
Diluted(2)       $(14,934)   27,476    $  (0.54)      $ 13,557     27,476     $   0.49     $    532       24,877     $ 0.02
</Table>


     (1) Net income (loss), excluding the approximate two percent General
         Partner interest, has been apportioned to each class of unitholder
         based on the ownership of total units outstanding in accordance with
         the Partnership Agreement, which is also reflected on the Statement of
         Partners' Capital. Special units were considered common units. Due to a
         negative capital account balance for the common unitholders during the
         second and third quarters of 1998, the loss allocated to the common
         unitholders attributable to these periods was reallocated to the
         remaining unitholders based on their ownership percentage. The
         allocated loss was recouped by the unitholders allocated the additional
         losses in the first quarter of 1999.

     (2) The diluted earnings (loss) per unit calculation assumes the conversion
         of subordinated units into common units. The disproportionate income
         (loss) allocation between the unitholders has no effect on the diluted
         computation.

     Net income and per unit information related to the net income before
cumulative effect of accounting changes and cumulative effect of the accounting
changes for the year ended December 31, 2001 is as follows:


<Table>
<Caption>

                                                                   NET INCOME
                                                    -----------------------------------------
                                                             Basic
                                                    --------------------------
                                                     Common       Subordinated       Diluted
                                                    --------      ------------      --------
<S>                                                 <C>           <C>               <C>
Net Loss Before Cumulative Effect ...........       $(10,749)       $ (5,236)       $(15,985)
Cumulative Effect of Accounting Changes
    Adoption of SFAS No.133 .................            833             405           1,238
    Change in Inventory Valuation Method ....           (126)            (61)           (187)
                                                    --------        --------        --------
Net Loss ....................................       $(10,042)       $ (4,892)       $(14,934)
                                                    ========        ========        ========
</Table>


<Table>
<Caption>

                                                                   PER UNIT
                                                    -----------------------------------------
                                                             Basic
                                                    --------------------------
                                                     Common       Subordinated       Diluted
                                                    --------      ------------      --------
<S>                                                 <C>           <C>               <C>
Net Loss Before Cumulative Effect............       $ (0.58)      $  (0.58)         $ (0.58)
Cumulative Effect of Accounting Changes
    Adoption of SFAS No.133..................          0.05           0.05             0.05
    Change in Inventory Valuation Method ....         (0.01)         (0.01)           (0.01)
                                                    -------       --------           -------
Net Loss.....................................       $ (0.54)      $  (0.54)          $(0.54)
                                                    =======       ========           ======
</Table>



                                      F-19
<PAGE>


                           EOTT ENERGY PARTNERS, L.P.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


     Per unit information related to the net income before cumulative effect of
accounting change and cumulative effect of the change in accounting principle
for the year ended December 31, 1999 is as follows:

<Table>
<Caption>
                                                 Year Ended December 31, 1999 (Restated) (Unaudited)
                                                 ----------------------------------------------------
                                                             Basic
                                                 --------------------------------
                                                  Common             Subordinated           Diluted
                                                 --------            ------------          ----------
<S>                                              <C>                 <C>                   <C>
Net Loss Before Cumulative Effect
    of Accounting Change .................       $  (0.08)              $    --              $(0.05)
Cumulative Effect of Accounting Change ...           0.07                  0.07                0.07
                                                 --------               -------              ------
Net Income (Loss) ........................       $  (0.01)              $  0.07              $ 0.02
                                                 ========               =======              ======
</Table>


     As further discussed in Note 8, we issued 3,500,000 common units to the
public on September 29, 1999.

7.   ASSET IMPAIRMENT AND NONRECURRING ITEMS

     As previously discussed, concurrently with the purchase of the Assets, we
entered into the Toll Conversion and Storage Agreements with EGLI. Subsequently,
in December 2001, EGLI was included in Enron's bankruptcy filing, and in April
2002, the Bankruptcy Court entered a stipulation and agreed order rejecting the
two agreements. As a result of EGLI's non-performance under the contracts, we
recorded a $29.1 million impairment in the fourth quarter of 2001 representing
our total remaining investment in the contracts. See Note 10 for further
discussion of the impact of Enron's bankruptcy on the Partnership.

     During 2000, we filed an insurance claim to recover the losses related to
the theft of NGL product (as discussed below) and received $2.5 million. In
addition, we recorded additional charges of $1.9 million primarily related to
severance charges for a former officer and the closing of the remaining contract
for mid-continent NGL activities.

     In the fourth quarter of 1999, as restated, we recorded $8.8 million of
nonrecurring items, which include $6.8 million related to mid-continent NGL
activities and a $2.0 million severance charge. The $6.8 million charge related
to mid-continent NGL activities includes a $5.2 million charge for the theft of
NGL product, concealment of commercial activities and other unauthorized actions
by a former employee. See further discussion of these activities and the
restatement of prior periods in Note 3. The remaining $1.6 million charge
relates to realized gains and losses on liquidated contracts in the fourth
quarter of 1999 and the change in unrealized gains and losses on forward energy
trading contracts accounted for under EITF Issue 98-10 at December 31, 2000.

     In 1999, we implemented a new marketing and accounting system. As a result,
marketing, field and administrative personnel were reduced and a severance
charge of $2.0 million was recorded pursuant to the existing EOTT Energy Corp.
Severance Plan.

8.   CREDIT RESOURCES AND LIQUIDITY

     Credit Resources. The Partnership had a credit facility with Enron to
provide credit support in the form of guarantees, letters of credit and working
capital loans through December 31, 2001. The total amount of the Enron facility
was $1.0 billion, and it contained sublimits of $100 million for working capital
loans and $900 million for guarantees and letters of credit. Letter of credit
fees were based on actual charges by the banks which ranged from .20% to .375%
per annum. Interest on outstanding loans was charged at LIBOR plus 250 basis
points per annum.


                                      F-20
<PAGE>


                           EOTT ENERGY PARTNERS, L.P.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


     On November 30, 2001, we entered into an interim credit facility with
Standard Chartered Bank ("Standard Chartered"), our primary lender, for the
purpose of replacing our existing credit facility with Enron. This interim
facility provided for the issuance through March 2002 of up to $150 million of
letters of credit. On December 21, 2001, we increased this interim credit
facility ("Credit Facility") to $300 million, which included a $40 million limit
for working capital loans, and extended the facility to April 30, 2002. This
Credit Facility was amended and extended, as discussed below.

     The Credit Facility was subject to defined borrowing base limitations and
included provisions restricting distributions to unitholders. The Credit
Facility was secured by a security interest in all of our unencumbered current
and fixed assets. Letter of credit fees were 1.5% per annum. Interest on
outstanding loans was charged at LIBOR plus 3%.

     In addition, we have an agreement with SCTS which provides for the
financing of purchases of crude oil inventory utilizing forward commodity
repurchase agreements ("Inventory Repurchase Agreement"). At December 31, 2001,
we had outstanding repurchase agreements of approximately $100 million with an
interest rate of 2.48%. Pursuant to the agreements, which had terms of
thirty-three days, EOTT repurchased the crude oil inventory on January 23, 2002
for approximately $100.2 million. At December 31, 2000, there were no repurchase
agreements outstanding.

     We also have an agreement with SCTS which provides for the transfer of up
to an aggregate amount of $100 million of certain trade receivables
("Receivables Agreement") outstanding at any one time. As of December 31, 2001
and 2000, $42.5 million and $45.0 million, respectively, of receivables had been
transferred under this agreement. In 2000, we accounted for these transactions
as sales under the provisions of SFAS No. 125. These transactions did not
qualify as sales under SFAS No. 140 and therefore are accounted for as
financings at December 31, 2001. The weighted average interest rate on
receivables financed at December 31, 2001 was 2.77%.

     In connection with the acquisition of certain liquids assets, as further
discussed in Note 5, the Inventory Repurchase Agreement and Receivables
Agreement were increased to an aggregate amount of $300 million on an interim
basis until long-term financing could be obtained. In connection with the
extension of these agreements in February 2002 discussed below, the aggregate
amount under these facilities was reduced to the combined original amount of
$200 million. We have not been able to refinance these liquids assets on a
long-term basis and any refinancing will be at higher interests rates than we
expected to incur prior to the Enron bankruptcy.

     In February 2002, we received commitments from Standard Chartered and SCTS
to amend and extend our Credit Facility as well as our Inventory Repurchase
Agreement and Receivables Agreement to February 2003 (collectively, "the
Facilities"). The extension of the Facilities was effective April 23, 2002. The
arrangement fee is 2% of the Facilities. The amended Inventory Repurchase
Agreement and Receivables Agreement bear interest at LIBOR plus 3%.

     The Credit Facility, as amended, is subject to defined borrowing base
limitations. The borrowing base is the sum of cash and equivalents, specified
percentages of eligible receivables, inventory, products contracted for or
delivered but not billed and a specified percentage of eligible fixed assets.
Letter of credit fees will be up to 3% per annum.

     The commitment fee is 0.5% per annum of the unused portion of the Credit
Facility. We may elect that loans under the Credit Facility bear interest at a
rate per annum equal to the alternative base rate, as defined in the amended
Credit Facility or LIBOR plus 3%. The alternative base rate is 3% per annum plus
the higher of (a) the annual rate of interest announced from time to time by
Standard Chartered as its base rate or (b) 0.5% of 1% above the overnight
Federal Funds rate, as published by the Federal Reserve Bank of New York.


                                      F-21
<PAGE>


                           EOTT ENERGY PARTNERS, L.P.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     The Credit Facility includes covenants and restrictions primarily related
to distributions to unitholders, amount of permitted expansion capital and
specified quarterly amounts for earnings before interest, depreciation and
amortization, net income and tangible net worth. Distributions to unitholders
cannot be made until all of the following occur: (i) we permanently reduce our
aggregate obligations to Standard Chartered and SCTS to an amount not exceeding
$300 million; (ii) our consolidated net worth is $10 million greater than our
consolidated net worth as of January 31, 2002, excluding any non-cash asset
write-downs incurred after January 31, 2002; and (iii) we resolve certain claims
(trade and other payables) of Enron and its affiliates against us related to
Enron's bankruptcy proceedings. For further details, see Note 10.

     At December 31, 2001, we had $196.1 million in letters of credit
outstanding under the Credit Facility. At December 31, 2000, we had $103.3
million in letters of credit outstanding under the Enron facility. In addition,
Enron guarantees outstanding at December 31, 2000 totaled $537.5 million.

     Prior to the Enron bankruptcy, we believed that the Credit Facility,
Inventory Repurchase Agreement and Receivables Agreement were sufficient to
support our purchasing activities and working capital and liquidity requirements
had the recapitalization plan been consummated. However, as a result of Enron's
bankruptcy and in part as a result of the increase in the price of crude oil,
some of our trade creditors have been less willing than before the Enron
bankruptcy to extend credit to us on an unsecured basis and the amount of
letters of credit we have been required to post increased from $196.1 million at
December 31, 2001 to $243.5 million at March 31, 2002. Subsequent to year-end,
due to the impacts of the Enron bankruptcy as well as the rise in crude oil
prices, we have had to reduce our marketing activities due to the lack of
sufficient credit support available under the Credit Facility.

     Our ability to obtain letters of credit to support our purchases of crude
oil or other petroleum products is fundamental to our gathering and marketing
activities. Additionally, we have a significant need for working capital due to
the large dollar volume of marketing transactions. We can give no assurance that
we will not be required to further reduce or restrict our gathering and
marketing activities because of limitations on our ability to obtain credit
support and financing for our working capital needs. Any significant decrease in
our financial strength, regardless of the reason for such decrease, may also
increase the number of transactions requiring letters of credit or other
financial support, may make it more difficult for us to obtain such letters of
credit, and/or may increase the cost of obtaining them. This could in turn
adversely affect our ability to maintain or increase our level of purchasing and
marketing activities or otherwise adversely affect our profitability and
Available Cash as defined in the MLP's amended and restated agreement of limited
partnership and amendments thereto (the "Partnership Agreement"), and thus, our
ability to meet the conditions necessary to make distributions.

     Senior Notes. On October 1, 1999, we issued to the public $235 million of
11% senior notes. The senior notes are due October 1, 2009, and interest is paid
semiannually on April 1 and October 1. The senior notes are fully and
unconditionally guaranteed by all of our operating limited partnerships. On or
after October 1, 2004, we may redeem the notes, and prior to October 1, 2002, we
may redeem up to 35% of the notes with proceeds of public or private sales of
equity at specified redemption prices. Provisions of the senior notes could
limit additional borrowings, sale and lease back transactions, affiliate
transactions, distributions to unitholders, mergers, consolidations, or sales of
assets if certain financial performance ratios are not met. The net proceeds
from the issuance of the 11% senior notes and the issuance of the common units
were used to repay loans and short-term borrowings from Enron.

     Distributions. Under the Partnership Agreement, it is intended that we
distribute 100% of our Available Cash, as defined in the Partnership Agreement,
within 45 days after the end of each quarter to unitholders of record and to the
General Partner. Available Cash consists generally of all of our cash receipts
adjusted for our cash disbursements and net changes to reserves. The full
definition of Available Cash is set forth in the


                                      F-22
<PAGE>


                           EOTT ENERGY PARTNERS, L.P.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



Partnership Agreement and amendments thereto, which have been filed as exhibits
with the SEC. From Available Cash, we are required to make a minimum quarterly
distribution to the General Partner and the holders of our common units. The
minimum quarterly distribution ("MQD") is currently measured at $0.475 per
common unit, distributed 98.02% to the holders of our common units and 1.98% to
our General Partner. If we fail to make the entire minimum distribution in any
quarter, the part of distribution not made is accounted for as an "arrearage."
If, in any quarter, we have Available Cash in excess of the MQD, we are required
to make the MQD and then repay the arrearage to holders of our common units,
before making a distribution to the holders of the subordinated units or the
Additional Partnership Interests ("APIs").

     Under a support agreement with Enron, Enron committed to provide total cash
distribution support in an amount necessary to pay MQDs, with respect to
quarters ending on or before December 31, 2001, in an amount up to an aggregate
of $29.1 million in exchange for APIs. Because of the bankruptcy of Enron and
certain of its subsidiaries and the resulting uncertainty related to our term
financing and working capital facilities, along with the continued weakness in
the crude markets, projected expenditure requirements related to scheduled
turnaround costs for our MTBE Plant and certain capital expansion projects, our
distribution for the fourth quarter of 2001 of $0.25 per common unit was lower
than the intended minimum quarterly distribution amount of $0.475 per common
unit. Enron did not pay the fourth quarter distribution shortfall of $0.225 per
common unit. See further discussion in Note 10.

     On April 3, 2002 we announced that there would be no distribution to
limited partners for the first quarter of 2002. The decision to not pay a
distribution for the first quarter of 2002 was based on cash flow from
operations for the first quarter of 2002, impact of the scheduled turnaround of
the MTBE Plant, and our need to preserve financial resources to finance
previously committed capital expenditures.

     As previously discussed, under the Credit Facility, there are restrictions
on the ability to pay distributions to unitholders. In any event, we do not
expect that any distributions to our unitholders will be made prior to the
fourth quarter of 2002.




                                      F-23

<PAGE>



9.   PARTNERS' CAPITAL

     The following is a reconciliation of units outstanding for the years ended
December 31, 2001, 2000 and 1999:


<Table>
<Caption>

                                                                            Common          Special         Subordinated
                                                                             Units            Units            Units
                                                                          ----------       ----------       ------------
<S>                                                                       <C>              <C>              <C>
         Units Outstanding at December 31, 1998 (unaudited) .......       11,996,000        2,980,011         9,000,000

         Conversion of Special Units into Common Units -1999 ......        2,980,011       (2,980,011)               --
         Issuance of Common Units -1999 ...........................        3,500,000               --                --
                                                                          ----------       ----------        ----------

         Units Outstanding at December 31, 1999, 2000 and 2001* ...       18,476,011               --         9,000,000
                                                                          ==========       ==========        ==========
</Table>

         *Amounts for 1999 and 2000 are unaudited.

     On February 12, 1999, we obtained approval of proposals presented at a
special meeting of unitholders. Approval of these proposals, among other things,
(a) authorized us to issue an additional 10 million common units to raise cash
to reduce indebtedness, for acquisitions and other Partnership purposes, (b)
changed the terms of the special units so that they became convertible into
common units and (c) resulted in an increase in Enron's distribution support to
$29.1 million and an extension of the support through the fourth quarter of
2001. As a result of the approval of the proposals, Enron contributed the $21.9
million in APIs outstanding at December 31, 1998.

     On September 29, 1999, we issued 3,500,000 common units to the public at
$15.12 per unit. Net proceeds of $52.9 million were used to repay loans to
Enron.


                                      F-24
<PAGE>

                           EOTT ENERGY PARTNERS, L.P.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


10.  IMPACT OF ENRON BANKRUPTCY AND TRANSACTIONS WITH ENRON AND RELATED PARTIES

IMPACT OF ENRON BANKRUPTCY

     Beginning on December 2, 2001, Enron along with certain of its
subsidiaries, filed to initiate bankruptcy proceedings under Chapter 11 of the
United States Code with the United States Bankruptcy Court for the Southern
District of New York (the "Bankruptcy Court"). Neither the General Partner nor
the Partnership are included in the filing. Enron has announced that it is
proceeding with reorganization efforts and intends to present restructuring
alternatives to the unsecured creditors' committee participating in Enron's
bankruptcy proceedings in 2002.

     Because of our contractual relationships with Enron and certain of its
subsidiaries, the bankruptcy has significantly impacted us in various ways,
discussed below.

     Rejection of Certain Agreements with EGLI. We have been adversely impacted
as a result of the inclusion of EGLI in Enron's bankruptcy. As discussed in Note
5, we had in place ten-year Toll Conversion and Storage Agreements with EGLI. On
April 2, 2002, the Bankruptcy court entered a Stipulation, which became final
and non-appealable on April 12, 2002, rejecting the Toll Conversion and Storage
Agreements. As a result, we recorded a $29.1 million non-cash impairment, which
was our remaining investment in these contracts. See further discussion
concerning the impact of the rejection of the Agreements in Note 5.

     We have a monetary damage claim against EGLI and Enron as a result of the
rejection of the agreements under the Stipulation, which has been filed in the
bankruptcy proceedings. The final amount of our claim resulting from the
rejection of the two agreements has not yet been fully determined. See further
discussion of the impact of the agreements in Note 5.

     Performance Collateral from Enron. Enron guaranteed payments under the Toll
Conversion and Storage Agreements; however, such guaranty was limited to $50
million under the Toll Conversion Agreement and $25 million under the Storage
Agreement. On May 10, 2002, we filed a claim under this guaranty in the Enron
bankruptcy proceeding. We, however, cannot predict the amounts that we will
collect or the timing of any such collection. Additionally, EGLI owed us
approximately $9 million under the Toll Conversion and Storage Agreements prior
to filing for bankruptcy. Pursuant to these agreements, on November 27, 2001, we
requested that EGLI post two $25 million letters of credit. In lieu of posting
letters of credit, we received $25 million from EGLI/Enron, against which we
recouped $9 million of outstanding invoices to EGLI. We currently intend to
apply the remaining sum, approximately $16 million, to recoup against or seek
offset of a portion of our damages resulting from EGLI's rejection of the Toll
Conversion and Storage Agreements. We also have outstanding accounts payable to
EGLI in the amount of approximately $2 million for butane and methanol feedstock
we acquired prior to EGLI filing for bankruptcy. We are exploring the
possibility of offsetting this $2 million payable against a portion of the
damages resulting from EGLI's rejection of the Toll Conversion and Storage
Agreements. We are uncertain, however, as to how these issues will be resolved.

     Tax and Environmental Indemnities. We might also incur losses in the event
that Enron fails to indemnify us for certain ad valorem taxes and potential
environmental expenditures relating to the MTBE Plant and the Mont Belvieu
Facility. Such indemnity obligations include agreements to indemnify us (i) for
any and all costs and expenses incurred in defending the pending litigation and
an administrative claim by the City of Morgan's Point, Texas, relating to ad
valorem taxes on the MTBE Plant; (ii) for ad valorem taxes assessed, settled or
attributable in excess of any valuations of the MTBE Plant over $27 million for
the years 2001, 2002, 2003, 2004 and one half of the ad valorem taxes on such
excess in 2005; (iii) for expenditures incurred under certain circumstances to
modify the MTBE Plant if and when required to comply with the Nitrogen Oxide
emissions provisions of the Federal and Texas Clean Air Acts or other
environmental laws; (iv) for certain environmental


                                      F-25
<PAGE>

                           EOTT ENERGY PARTNERS, L.P.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


conditions associated with Enron or certain Enron affiliates' ownership or
operation of the MTBE Plant and the Mont Belvieu Facility prior to June 30,
2001; and (v) for certain title defects in certain real property, easements,
rights-of-way, and personal property. The total indemnity amount provided for
under the purchase and sale agreement is up to $25 million. We do not believe
these indemnities have any value; however, we intend to make appropriate claims
as a result of such indemnity obligations through Enron's bankruptcy
proceedings. For further details concerning the June 2001 purchase of the MTBE
Plant and the Mont Belvieu Facility and the Toll Conversion and Storage
Agreements, see Notes 5 and 7.

     Cost and Availability of Credit. The actual cost incurred for our interim
and term credit facilities increased significantly above the cost being
negotiated for these Facilities just immediately prior to Enron's financial
deterioration and ultimate bankruptcy. We have been unable to refinance amounts
borrowed for the purchase of the Liquids assets on a long-term basis at rates
comparable to those expected in September 2001, immediately prior to Enron's
financial deterioration and ultimate bankruptcy. Our trade creditors have been
less willing to extend credit to us on an unsecured basis and the amount of
letters of credit we have been required to post for our marketing activities has
increased significantly. See further discussion in Note 8.

     General Partner Alternatives. Although neither our General Partner nor we
have filed for Chapter 11 bankruptcy protection, it is possible that Enron could
attempt to take action to cause our General Partner to file for bankruptcy
protection. If our General Partner were to file for bankruptcy relief, the
filing would be an "Event of Withdrawal" under our Partnership Agreement and our
General Partner will be deemed to have withdrawn. Upon the occurrence of an
Event of Withdrawal, our General Partner is required to give notice to our
limited partners within 30 days after such occurrence. An Event of Withdrawal
triggers dissolution and winding up of the affairs of the Partnership unless (i)
a successor General Partner is elected and admitted to the Partnership within
180 days, (ii) a written opinion of counsel is issued that such withdrawal would
not result in the loss of the limited liability of any limited partner or of the
limited partner of any of our operating limited partnerships or cause the
Partnership or any of our operating limited partnerships to be taxed as a
corporation, and (iii) the new general partner executes a new partnership
agreement and executes and files a new certificate of limited partnership.
Election of a successor General Partner requires a vote of a majority of the
outstanding units to reconstitute the Partnership and approve the successor
general partner. Upon the election of a new general partner, the General
Partner's interest will be converted to common units. Despite the provisions of
our Partnership Agreement discussed in this section, if our General Partner were
to file for bankruptcy protection, the bankruptcy court may refuse to enforce
these provisions or may require different or additional procedures and
consideration to allow these provisions to be followed.

     Enron has to date, however, chosen not to take action to cause the
inclusion of our General Partner in its bankruptcy proceedings, which were
commenced on December 2, 2001. Neither Enron, the General Partner, nor any other
Enron affiliate has advised us of any intention of Enron, any Enron affiliate or
our General Partner to place our General Partner into bankruptcy. Because the
bankruptcy of Enron and certain of its affiliates created conflicts of interest
between EOTT and Enron and certain of its affiliates (for example, with respect
to the EGLI contracts, now rejected), the General Partner and Enron established
a Restructuring Committee to consider (among other things) all matters involving
a possible restructuring of our relationship with Enron. This committee is
comprised of our three solely independent, non-Enron related directors. This
committee was also granted the power, through amendments to our charter and
by-laws, to place our General Partner into bankruptcy.

     Pension Plan Underfunding Issues. The MLP does not have any employees on
its payroll, and does not sponsor any pension plans. However, the MLP and its
operating limited partnerships use the services of employees of our General
Partner, a wholly-owned subsidiary of Enron. Our General Partner provides the
services of these employees to the MLP under the terms of the Partnership
Agreement and provides the services of these employees to EOTT Energy General
Partner, L.L.C. under the terms of an administrative



                                      F-26
<PAGE>


                           EOTT ENERGY PARTNERS, L.P.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


services agreement. Our General Partner is a participating employer in a defined
benefit pension plan known as the Enron Corp. Cash Balance Plan (the "Cash
Balance Plan"). It is our understanding, based on information provided by Enron,
that the assets of the Cash Balance Plan are currently less than the present
value of all accrued benefits on both an SFAS No. 87 (Employers' Accounting for
Pensions) basis and a plan termination basis by approximately $90 million, with
approximately 48 percent of that amount attributable to members of the Enron
"controlled group" that are not in bankruptcy.

     The Enron administrative committee for the Cash Balance Plan was recently
replaced by an independent fiduciary, the State Street Bank and Trust Company of
Boston, Massachusetts. This replacement, which was made at the request of the
U.S. Department of Labor ("DOL"), occurred as part of an agreement reached
between the DOL and Enron.

     A federal government corporation known as the Pension Benefit Guaranty
Corporation (the "PBGC") has the power to terminate underfunded pension plans in
certain situations, after receiving the permission either of the employer or of
a court. When such a termination occurs, the PBGC uses a method of calculating
liability for underfunding of the pension plan that, under current interest
rates and assumptions, usually results in a much higher liability figure than
the liability figure that results from liability calculated on an on-going,
rather than a termination, basis. Should such termination occur, liability for
any underfunding of the plan, calculated on a termination basis, may be imposed
jointly and severally on all members of the employer's "controlled group," which
is a defined term under the Employment Retirement Income Security Act ("ERISA")
and the United States Internal Revenue Code.

     In the event of termination of the Cash Balance Plan, the PBGC could impose
such "controlled group" liability on our General Partner. The PBGC could demand
that our General Partner pay the underfunded amount, calculated on a termination
basis. If our General Partner failed to pay such claim, the PBGC could move to
perfect against our General Partner's property a lien that automatically
attaches against the assets of each member of the "controlled group" in an
amount equal to the lesser of the underfunding or 30% of the aggregate net worth
of the "controlled group." Further, if Enron failed to make minimum funding
payments exceeding in the aggregate $1 million, a lien would automatically
attach to assets of Enron "controlled group" and "affiliated service group"
members. It is our understanding that Enron is not presently delinquent in
making on-going contributions to its pension plan. However, any such lien would
be subordinate to any then-existing, perfected liens against our General
Partner's property.

     Under these circumstances, our General Partner would exercise all its
rights to defend against such a claim, and, in the event the PBGC had not
already pursued and collected from solvent members of the "controlled group,"
would assert its rights to recover contribution from such members. At this time,
we cannot predict whether either the PBGC or Enron will seek to terminate the
Cash Balance Plan. Any claim paid by the General Partner would become our
responsibility under the provisions of the MLP's Partnership Agreement, subject
to any claims of indemnity, offset, recoupment or any counterclaims we might
have against our General Partner or any of its affiliates.

     Distributions to Our Common Unitholders. Our distribution for the fourth
quarter of 2001 was $0.25 per common unit, which is lower than the minimum
quarterly distribution amount of $0.475 per common unit intended under our MLP
Partnership Agreement. The reduction in the distribution resulted from the
bankruptcy of Enron and certain of its subsidiaries and the resulting
uncertainty related to our term financing and working capital facilities, along
with the continued weakness in the crude markets, projected expenditure
requirements related to scheduled turnaround costs for the MTBE Plant and
certain capital expansion projects currently underway. Enron was obligated under
a support agreement to provide cash distribution support through the fourth
quarter of 2001. As a result of Enron's financial deterioration and bankruptcy,
however, Enron did not pay the fourth quarter cash distribution shortfall of
$0.225 per common unit. We expect to submit a claim for such distribution
support amount in Enron's bankruptcy proceedings.


                                      F-27
<PAGE>


                           EOTT ENERGY PARTNERS, L.P.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


     Additionally, on April 3, 2002, we announced that we would not make a
distribution to our common unitholders for the first quarter of 2002. See
further discussion in Note 8.

     Claims Against Enron's Bankruptcy Estate. We have several potential claims
against Enron's and certain of its subsidiaries' bankruptcy estates and have
retained outside counsel to evaluate such claims. The claims will likely be
deemed to be unsecured claims against certain of the Enron entities involved in
the Enron bankruptcy. We have also filed a claim for rejection damages in excess
of $500 million against Enron and certain of its subsidiaries in the Enron
bankruptcy proceedings. We are uncertain regarding the ultimate amount of claims
that we will be able to establish in the bankruptcy proceeding and we cannot
predict the amounts, if any, that we may collect or the timing of any such
collection.

TRANSACTIONS WITH ENRON AND AFFILIATES

     Revenue and Cost of Sales. A summary of transactions with Enron and its
affiliates follows (in thousands):

<Table>
<Caption>

                                                 Year Ended December 31,
                                          ---------------------------------------
                                            2001           2000           1999
                                          --------     -----------     ----------
                                                       (Unaudited)     (Unaudited)
<S>                                       <C>            <C>            <C>
          Sales to affiliates .........   $ 97,224       $ 49,673       $ 18,859
          Purchases from affiliates ...   $ 32,813       $ 57,162       $279,167
</Table>

     Sales to affiliates in 2001, 2000 and 1999 consist primarily of sales of
crude oil to Enron Reserve Acquisition Corp. and conversion, storage and
transportation fees from EGLI. Purchases from affiliates consist primarily of
crude oil and condensate purchases from Enron Reserve Acquisition Corp. and
Enron North America Corp. These transactions in our opinion are no more or less
favorable than can be obtained from unaffiliated third parties.

     Due to the Enron bankruptcy, collectibility of certain receivables from
Enron and its affiliates totaling $0.6 million at December 31, 2001 was
uncertain and therefore such receivables were written off against the allowance
for bad debts. Other related party balances related to purchases and sales of
goods and services have been classified as payables to Enron and affiliates,
net. Related party receivables at December 31, 2001 and 2000 were $0.5 million
and $2.0 million, respectively. Related party payables at December 31, 2001 and
2000 were $2.1 million and $19.7 million, respectively. The payables at December
31, 2001 primarily represent amounts owed by EOTT on the purchase of feedstocks
from EGLI.

     Operations and General and Administrative Services. As is commonly the case
with publicly traded partnerships, we do not directly employ any persons
responsible for managing or operating the Partnership or for providing services
relating to day-to-day business affairs. The General Partner provides such
services or obtains such services from third parties and the Partnership is
responsible for reimbursing the General Partner for substantially all of its
direct and indirect costs and expenses. The General Partner, through the MLP
Partnership Agreement, provides services to us including liability and casualty
insurance and certain data processing services and employee benefits. Those
costs were $2.5 million, $3.6 million and $3.8 million for the years ended
December 31, 2001, 2000 and 1999, respectively and are included in operating
expense. We believe that the charges were reasonable. As of December 31, 2001
and 2000, we owe approximately $12.2 million and $14.1 million, respectively,
with respect to these services.

     The General Partner entered into an agreement with Enron Pipeline Services
Company ("EPSC"), a wholly-owned subsidiary of Enron that is currently not in
bankruptcy, to provide certain operating and


                                      F-28
<PAGE>


                           EOTT ENERGY PARTNERS, L.P.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


administrative services to the General Partner, effective October 1, 2000. These
services were previously performed directly by the General Partner. The
agreement provides that the General Partner will reimburse EPSC for its costs
and expenses in rendering the services. The General Partner will in turn be
reimbursed by us. The General Partner anticipates taking these services over in
2002 to provide them to us directly. The costs incurred related to these
services for the year ended December 31, 2001 and for the three months ended
December 31, 2000 were $56.7 million and $6.3 million, respectively. As of
December 31, 2001 and 2000, we owe $11.5 million and $4.8 million, respectively,
with respect to these services.

     In connection with the acquisition of Liquids assets in June 2001, the
General Partner entered into an agreement with EGP Fuels to provide transition
services through December 31, 2001 for the processing of invoices and payments
to third parties related to the MTBE Plant and Mont Belvieu Facility. The
agreement provided that the General Partner will reimburse EGP Fuels for these
direct costs and we will reimburse the General Partner. Costs related to these
services were $12.3 million for the six months ended December 31, 2001 and were
still outstanding at December 2001.

     We have recorded liabilities of approximately $36.0 million to Enron and
its affiliates, including the General Partner, under various agreements,
discussed above. We are exploring possibilities of recouping and/or seeking
offset against certain of our claims in the bankruptcy proceeding against our
liabilities to Enron and its affiliates, including the General Partner. At this
point, however, it is uncertain how these issues will be resolved.

     Credit Facility. We had a credit facility with Enron to provide credit
support in the form of guarantees, letters of credit and working capital loans
through December 31, 2001. See further discussion in Note 8.

     Purchase and Sale Agreement. We acquired certain liquids processing,
storage and transportation assets in June 2001 from Enron. See further
discussion in Note 5.

     Special Units. The special units ranked equally with the common units in
all distributions and upon liquidation and were voted as a class with the common
units. In connection with the support agreement, we issued 1,150,000 special
units to Enron in December 1998 and, as discussed further below, Enron
contributed $21.9 million in APIs to the Partnership in February 1999. The
special units were converted into common units in March 1999 on a one-for-one
basis.

     Support Agreement. Pursuant to a support agreement dated September 21,
1998, (a) Enron made loans to us to fund the cash portion of the consideration
paid to Koch Pipeline Company L.P. and Koch Oil Company (collectively "Koch")
for the acquisitions of gathering and marketing assets, (b) Enron increased and
extended our credit facility with Enron to $1 billion through December 31, 2001,
(c) we issued 1,150,000 special units to Enron, and (d) Enron agreed to
contribute $21.9 million in APIs to us and extend its cash distribution support
through the fourth quarter of 2001, subject to unitholder approval. We obtained
unitholder approval of these proposals on February 12, 1999.

     As previously discussed in Note 8, during the first quarter of 2002, we
requested distribution support from Enron under the terms of the Support
Agreement in connection with payment of the minimum quarterly distribution for
the fourth quarter of 2001. Enron did not provide the requested support.

     Additional Partnership Interests. On May 14, 1999 and February 14, 2000,
Enron paid $2.5 million and $6.8 million, respectively, in support of our first
and fourth quarter 1999 distributions to our common unitholders and received
APIs. APIs have no voting rights and do not receive distributions; however, APIs
will be entitled to be redeemed if, with respect to any quarter, the MQD and any
common unit arrearages have been paid, but only to the extent that Available
Cash with respect to such quarter exceeds the amount necessary to pay the MQD on
all units.


                                      F-29
<PAGE>


                           EOTT ENERGY PARTNERS, L.P.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


     Recapitalization Plan. On September 6, 2001, we announced a
recapitalization plan that included a recapitalization agreement with Enron, our
General Partner, and Koch Petroleum Group, L.P., to convert all outstanding
subordinated units and APIs into common units and the implementation of
refinancing plans. Due to events involving Enron, the recapitalization agreement
terminated under its own terms as the transaction was not closed before December
31, 2001 and the refinancing plans were terminated.



                                      F-30
<PAGE>


                           EOTT ENERGY PARTNERS, L.P.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


11.  EMPLOYEE BENEFIT AND RETIREMENT PLANS

     Employees of the General Partner are covered by various retirement, stock
purchase and other benefit plans of Enron. See further discussion in Note 10 of
the potential impact of the Enron bankruptcy on various benefit plans of Enron
in which the General Partner participates. In April 1993, the General Partner
adopted welfare benefit plans providing medical, dental, life, accidental death
and dismemberment and long-term disability coverage to employees, with all
related premiums and costs being incurred by the General Partner. Total benefit
costs for 2001 were $6.7 million, including $4.6 million in costs attributable
to health and welfare benefit plans. Total benefit costs for 2000 were $9.4
million, including $5.8 million in costs attributable to health and welfare
benefit plans. Total benefit costs for 1999 were $9.4 million, including $5.7
million in costs attributable to health and welfare benefit plans.

     Additionally, the General Partner maintains a variable pay plan based on
earnings before interest, income taxes, depreciation and amortization of which
$3.8 million, $3.8 million and $3.0 million was recorded in 2001, 2000 and 1999,
respectively.

     The General Partner's employees continue benefit accrual under the Cash
Balance Plan. All accrued benefits under the Cash Balance Plan will be preserved
in the Cash Balance Plan until the General Partner adopts separate plans or
participating employees are eligible for distribution under the plan. The
General Partner's employees continue to participate in the Enron Employee Stock
Ownership Plan and continue to be eligible for participation in the Enron Corp.
Savings Plan.

     As of September 30, 2001, the most recent valuation date, the plan net
assets, including contributions to the trust during the fourth quarter of 2001,
of the Enron Cash Balance Plan (non-contributory defined benefit plan), in which
the employees of the General Partner participate, were less than the actuarial
present value of projected plan benefit obligations by approximately $76.8
million. As of September 30, 2000, the plan assets, including contributions to
the trust during the fourth quarter of 2000, of the Enron Cash Balance Plan in
which the employees of the General Partner participate, were more than the
actuarial present value of projected plan benefit obligations by approximately
$3.3 million. The assumed discount rate, rate of return on plan assets and rate
of increases in wages used in determining the actuarial present value of
projected benefits were 7.75%, 10.5%, and 4.0%, respectively, in both 2001 and
2000.

     The General Partner provides certain postretirement medical, life insurance
and dental benefits to eligible employees who retire after January 1, 1994.
Benefits are provided under the provisions of contributory defined dollar
benefit plans for eligible employees and their dependents. These postretirement
benefit costs are accrued over the service lives of employees expected to be
eligible to receive such benefits. Enron retains liability for former employees
of the General Partner who retired prior to January 1, 1994. The accumulated
postretirement benefit obligation ("APBO") existing at December 31, 2001 and
2000 totaled $1.1 million and $0.9 million, respectively. The measurement of the
APBO assumes a 7.0% and 7.75% discount rate in 2001 and 2000. Currently there is
no intention to prefund our obligations under the Enron postretirement benefit
plan.


                                      F-31
<PAGE>



                           EOTT ENERGY PARTNERS, L.P.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     The following table sets forth information related to changes in the
benefit obligations, changes in plan assets, a reconciliation of the funded
status of the plans and components of the expense recognized related to
postretirement benefits provided by the General Partner (in thousands):

<Table>
<Caption>

                                                                        2001          2000
                                                                      -------        -------
                                                                                   (Unaudited)
<S>                                                                   <C>            <C>
     CHANGE IN BENEFIT OBLIGATION
        Benefit obligation at January 1 ........................      $   924        $ 1,070
        Service cost ...........................................           99            137
        Interest cost ..........................................           73             79
        Plan participants' contributions .......................           73             73
        Plan amendments ........................................            3             --
        Actuarial loss (gain) ..................................           37           (130)
        Effect of curtailments and settlements .................           --           (198)
        Benefits paid ..........................................         (106)          (107)
                                                                      -------        -------
            Benefit obligation at December 31 ..................      $ 1,103        $   924
                                                                      -------        -------

     CHANGE IN PLAN ASSETS
        Fair value of plan assets at January 1 .................      $    --        $    --
        Company contributions ..................................           33             34
        Plan participants' contributions .......................           73             73
        Benefits paid ..........................................         (106)          (107)
                                                                      -------        -------
            Fair value of plan assets at December 31                  $    --        $    --
                                                                      =======        =======

     RECONCILIATION OF FUNDED STATUS TO BALANCE SHEET
        Funded status at December 31 ...........................      $(1,103)       $  (924)
        Unrecognized prior service cost ........................          256            276
        Unrecognized actuarial gain ............................         (474)          (540)
                                                                      -------        -------
            Accrued benefit cost at December 31 ................      $(1,321)       $(1,188)
                                                                      =======        =======
</Table>

<Table>
<Caption>

COMPONENTS OF NET PERIODIC BENEFIT COST                                 2001         2000         1999
                                                                        -----     ----------- -----------
                                                                                  (Unaudited) (Unaudited)
<S>                                                                     <C>       <C>         <C>
     Service cost ..............................................        $  99        $ 137        $ 178
     Interest cost .............................................           73           79           82
     Amortization of prior service cost ........................           24           33           36
     Recognized net actuarial gain .............................          (29)         (38)         (19)
                                                                        -----        -----        -----
         Total net periodic postretirement benefit cost ........        $ 167        $ 211        $ 277
                                                                        =====        =====        =====
</Table>


     The General Partner provides unemployment, severance and disability-related
benefits or continuation of benefits such as health care and life insurance and
other postemployment benefits. SFAS No. 112 requires the cost of those benefits
to be accrued over the service lives of the employees expected to receive such
benefits. At December 31, 2001 and 2000, the liability accrued was $ 0.9 million
and $0.9 million, respectively.

     EOTT Energy Corp. Unit Option Plan. In February 1994, the Board of
Directors of the General Partner adopted the 1994 EOTT Energy Corp. Unit Option
Plan (the "Unit Option Plan"), which is a variable compensatory plan. To date,
no compensation expense has been recognized under the Unit Option Plan.


                                      F-32
<PAGE>


                           EOTT ENERGY PARTNERS, L.P.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



Under the Unit Option Plan, selected employees of the General Partner were
granted options to purchase subordinated units at a price of $15.00 per Unit as
determined by the Compensation Committee of the Board of Directors of the
General Partner. Options granted under the Unit Option Plan vested to the
employees over a five-year service period and will expire on the tenth
anniversary of the date of grant. No options are vested or exercisable prior to
the third anniversary of the grant.

     The following table sets forth the Unit Option Plan activity for the years
ended December 31, 2001, 2000 and 1999:

<Table>
<Caption>

                                                     Number of Unit Options
                                           -----------------------------------------
                                              2001            2000            1999
                                           ---------       ---------       ---------
                                                          (Unaudited)     (Unaudited)
<S>                                        <C>            <C>              <C>
Outstanding at January 1 ...............     460,000         925,000       1,030,000
        Granted ........................          --              --              --
        Exercised ......................          --              --              --
        Forfeited ......................       5,000         465,000         105,000
                                           ---------       ---------       ---------

Outstanding at December 31 .............     455,000         460,000         925,000
                                           =========       =========       =========

Available for grant at December 31 .....          --              --              --
                                           =========       =========       =========
</Table>

     The Board of Directors of the General Partner decided that it would not
grant any additional options under the Unit Option Plan. In addition, in
February 1997, the Unit Option Plan was amended to provide that, if the General
Partner and the option holder agree, any option may be exercised on a "net"
basis with no cash payment (other than for withholding taxes), so that upon
exercise the holder will receive a number of units with a fair market value
equal to the difference between the fair market value of the units covered by
the option and the exercise price of the option. As a result, the General
Partner anticipates that the actual number of units to be issued on exercise of
options will be substantially less than the number of units covered by
outstanding options.

     We elected not to adopt the fair value based method of accounting for stock
based compensation plans for accounting purposes. If we had elected to recognize
compensation cost based on the fair value of the options granted at grant date
as prescribed by SFAS No. 123, net income (loss) and net income (loss) per
diluted unit would have been changed to the following pro forma amounts (in
thousands):

<Table>
<Caption>

                                                                  2001(1)              2000            1999
                                                                ----------        ----------       -----------
                                                                                 (Unaudited)        (Restated)
                                                                                                   (Unaudited)
<S>                                                             <C>               <C>              <C>
Net Income (Loss) - as reported and restated for 1999 ...       $  (15,233)       $   13,833       $      561
Net Income (Loss) - pro forma ...........................       $  (15,233)       $   14,158       $      379

Diluted Net Income (Loss) per Unit - as reported ........       $    (0.54)       $     0.49       $     0.02
Diluted Net Income (Loss) per Unit - pro forma ..........       $    (0.54)       $     0.51       $     0.01
</Table>

(1)  Under the provisions of SFAS No. 123, no compensation expense would be
     recognized in 2001 relative to options granted under the EOTT Unit Option
     Plan in 1996 and 1998 since all such options are fully vested or have been
     forfeited. Consequently, pro forma and actual results for the year ended
     December 31, 2001 are identical.


                                      F-33
<PAGE>


                           EOTT ENERGY PARTNERS, L.P.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


     EOTT Energy Corp. Long-Term Incentive Plan. In October 1997, the Board of
Directors adopted the EOTT Energy Corp. Long Term Incentive Plan ("Plan"), which
is a variable compensatory plan. Under the Plan, selected key employees are
awarded Phantom Appreciation Rights ("PAR"). Each PAR is a right to receive cash
based on our performance prior to the time the PAR is redeemed. Our performance
is measured primarily by calculating the change in the average of Earnings
Before Interest on Debt related to acquisitions, Depreciation and Amortization
("EBIDA"), for each of the three consecutive fiscal years immediately preceding
the grant date of the PAR and the exercise date of the PAR. The Plan has a
five-year term beginning January 1, 1997, and PAR awards vest in 25% increments
in the four-year period following the grant year.

     The following table sets forth the Long-Term Incentive Plan activity for
the years ended December 31, 2001, 2000 and 1999:

<Table>
<Caption>

                                                      Number of PARS
                                         -----------------------------------------
                                           2001            2000             1999
                                         ---------       ---------       ---------
                                                        (Unaudited)     (Unaudited)
<S>                                      <C>            <C>             <C>
Outstanding at January 1 ..............    939,975       1,476,403         637,928
   Granted ............................    332,000          30,000         967,375
   Exercised ..........................    106,250              --              --
Forfeited .............................     98,350         566,428         128,900
                                         ---------       ---------       ---------

Outstanding at December 31 ............  1,067,375         939,975       1,476,403
                                         =========       =========       =========

Available for grant at December 31 ....         --       1,807,626       1,011,297
                                         =========       =========       =========
</Table>

         Note: Over the life of the plan, PARs available for grant cannot exceed
         an amount equal to 10% of the weighted average units outstanding for
         the year (2,747,601 as of December 31, 2001 and 2000, and 2,487,700 as
         of December 31, 1999). No PARs are available for grant after December
         31, 2001 as the term of the plan expired December 31, 2001.


                                      F-34
<PAGE>


                           EOTT ENERGY PARTNERS, L.P.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


12.  COMMITMENTS AND CONTINGENCIES

     Operating Leases. We lease certain real property, equipment, and operating
facilities under various operating leases. Future non-cancelable commitments
related to these items at December 31, 2001, are as follows (in thousands):
years ending December 31, 2002 - $5,602; 2003 - $4,719; 2004 - $3,705; 2005 -
$3,209; 2006 - $2,577; thereafter - $944.

     Total lease expense incurred was $9.4 million, $9.1 million and $10.4
million for the years ended December 31, 2001, 2000 and 1999, respectively.

     Litigation. We are, in the ordinary course of business, a defendant in
various lawsuits, some of which are covered in whole or in part by insurance. We
believe that the ultimate resolution of our pending litigation, individually and
in the aggregate, will not have a materially adverse impact on our financial
position or results of operations. Various legal actions have arisen in the
ordinary course of business, the most significant of which are discussed below.

     State of Texas Royalty Suit. We were served on November 9, 1995 with a
petition styled The State of Texas, et al. vs. Amerada Hess Corporation, et al.
The matter was filed in District Court in Lee County, Texas and involves several
major and independent oil companies and marketers as defendants. The plaintiffs
are attempting to put together a class action lawsuit alleging that the
defendants acted in concert to buy oil owned by members of the plaintiff class
in Lee County, Texas, and elsewhere in Texas, at "posted" prices, which the
plaintiffs allege were lower than true market prices. There is not sufficient
information in the petition to fully quantify the allegations set forth in the
petition, but we believe that any such claims against us will prove to be
without merit. There has been no activity on this matter in several years.

     The State of Texas, et al. vs. Amerada Hess Corporation, et al., Cause No.
97-12040; In the 53rd Judicial District Court of Travis County, Texas ("Common
Purchaser Act Suit"). This case was filed on October 23, 1997 in Austin by the
Texas Attorney General's office and involves several major and independent oil
companies and marketers as defendants. We were served on November 18, 1997. The
petition states that the State of Texas brought this action in its sovereign
capacity to collect statutory penalties recoverable under the Texas Common
Purchaser Act, arising from defendants' alleged willful breach of statutory
duties owed to royalty, overriding royalty and working interest owners of crude
oil sold to defendants, as well as alleged breach of defendants' common law and
contractual duties. The plaintiffs also allege the defendants have engaged in
discriminatory pricing of crude oil. This case appears to be similar to the
State of Texas Royalty Suit filed by the State of Texas on November 9, 1995. We
recorded a $0.4 million litigation reserve related to this suit in 1998. We and
several of the defendants reached a settlement with the State of Texas in a
settlement agreement, dated August 5, 1999. The settlement was funded to an
escrow account in July 1999. Settlement amounts for each defendant were
confidential. The parties are considering options to have the case fully
dismissed. This settlement disposed of any claims the State of Texas may have in
the State of Texas Royalty Suit, discussed above, but did not dismiss that case.
Also, any severance tax claims the State of Texas may have were specifically
excluded from this settlement. However, no severance tax claims were asserted in
the petition filed by the plaintiffs. There has been no activity on this matter
for several years.

     McMahon Foundation and J. Tom Poyner vs. Amerada Hess Corporation, et al.
(Including EOTT Energy Operating Limited Partnership), Civil Action No.
H-96-1155; United States District Court, Southern District of Texas, Houston
Division ("Texas Federal Anti-Trust Suit"). This suit was filed on April 10,
1996 as a class action complaint for violation of the federal antitrust laws and
involves several major and independent oil companies and marketers as
defendants. The relevant area is the entire continental United States, except
for Alaska, New York, Ohio, Pennsylvania, West Virginia and the Wilmington Field
at Long Beach, California. The plaintiffs claim that there is a combination and
conspiracy among the defendant oil companies to fix, depress, stabilize and
maintain at


                                      F-35
<PAGE>


                           EOTT ENERGY PARTNERS, L.P.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


artificially low levels the price paid for the first purchase of lease
production oil sold from leases in which the class members own interests. This
was allegedly accomplished by agreement of the defendants to routinely pay for
first purchases at posted prices rather than competitive market prices and
maintain them in a range below competitive market prices through an undisclosed
scheme of using posted prices in buy/sell transactions among themselves to
create the illusion that posted prices are genuine market prices. The plaintiffs
allege violations from October of 1986 forward. No money amounts were claimed.
See Summary below for current status.

     Randolph Energy, Inc., et al. vs. Amerada Hess Corporation, et al., Civil
Action No. 2:97CV273PG; In the United States District Court for the Southern
District of Mississippi, Jackson Division ("Mississippi Federal Anti-Trust
Suit"). We received the summons in this matter on August 18, 1997. The case was
filed on August 5, 1997 and is a class action complaint for alleged violation of
the federal antitrust laws, which involves several major and independent oil
companies and marketers as defendants. The plaintiffs claim that this litigation
arises out of a combination and conspiracy of the defendant oil companies to
fix, depress, stabilize and maintain at artificially low levels the prices paid
for the first purchase of lease production oil sold from leases in which the
class members own interests. The issues appear to be a duplication of the issues
in the Texas Federal Anti-Trust Suit previously discussed. No money amounts were
claimed. This suit was dismissed with prejudice on March 29, 2002. See Summary
below for current status.

     Cameron Parish School Board, et al. vs. Texaco, Inc., et al.; Civil Action
No. C-98-111; In the United States District Court for the Western District of
Louisiana, Lake Charles Division ("Louisiana Federal Anti-Trust Suit"). This
case was originally filed as a state law claim in Louisiana. When the case was
removed to federal court, the anti-trust claims were added, similar to the
claims made in the Texas Federal Anti-Trust Suit and the Mississippi Federal
Anti-Trust Suit. The plaintiffs claim that this litigation arises out of a
combination and conspiracy of the defendant oil companies to fix, depress,
stabilize and maintain at artificially low levels the prices paid for the first
purchase of lease production oil sold from leases in which the class members own
interests. The issues appear to be a duplication of the issues in the Texas
Federal Anti-Trust Suit and the Mississippi Federal Anti-Trust Suit, both
previously discussed above. On October 22, 1998, the judge granted the
Plaintiffs' motion to amend the petition and add additional defendants. The
Partnership and the General Partner were added to the case as defendants at that
time. No money amounts were claimed. See Summary below for current status.

     Summary. The Texas Federal Anti-Trust Suit, the Mississippi Federal
Anti-Trust Suit and the Louisiana Federal Anti-Trust Suit, along with several
other suits to which we are not a party, were consolidated and transferred to
the Southern District of Texas by transfer order, dated January 14, 1998. The
Judicial Panel on Multidistrict Litigation made this recommendation due to
similarity of issues in the cases. We recorded a $1.0 million litigation reserve
related to these suits in 1998. We, along with our General Partner, and a number
of other defendants, entered into a class-wide settlement, which was approved by
the court on April 7, 1999, with a final judgment entered on August 11, 1999.
Several appeals were filed and resolved concerning the settlement. The
settlement was funded on November 27, 2001.

     Assessment for Crude Oil Production Tax from the Comptroller of Public
Accounts, State of Texas. We received a letter from the Comptroller's Office
dated October 9, 1998 assessing us for severance taxes the Comptroller's Office
alleges are due on a difference the Comptroller's Office believes exists between
the market value of crude oil and the value reported on our crude oil tax report
for the period of September 1, 1994 through December 31, 1997. The letter states
that the action, based on a desk audit of our crude oil production reports, is
partly to preserve the statute of limitations where crude oil severance tax may
not have been paid on the true market price of the crude oil. The letter further
states that the Comptroller's position is similar to claims made in several
lawsuits, including the Texas Federal Anti-Trust Suit, in which the Partnership
is a defendant. The amount of the assessment, including penalty and interest, is
approximately $1.1 million. While the claim is still being reviewed, we believe
we should be without liability in this or related matters. There has been no
action on this matter since early 1999.


                                      F-36
<PAGE>


                           EOTT ENERGY PARTNERS, L.P.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


     Export License with United States Department of Commerce. We have applied
for and maintained Export Licenses through the U.S. Department of Commerce
("DOC") since 1994. These licenses authorized us to export crude oil to Canada.
Each license provided an applicable license quantity and value of merchandise as
authorized by the DOC to be exported. The licenses generally covered either a
one or two year period. In early 1999, as we were preparing a new license
application, we discovered that we had exported more barrels and value than had
been authorized by the DOC under our current (and prior) license. Pursuant to
Section 764.5 of the Export Administration Regulations, we filed a Voluntary
Disclosure with the DOC on February 5, 1999, giving the DOC notice of these
license overruns. The next formal stage of the Voluntary Disclosure process will
be for the DOC to issue a Charging Letter to us regarding a proposed fine for
the export license overruns. At this time, we do not know the date when or for
what amount the Charging Letter will be issued. We are currently negotiating a
monetary settlement with the DOC and we have recorded an estimate of the
potential settlement amount.

     John H. Roam, et al. vs. Texas-New Mexico Pipe Line Company and EOTT Energy
Pipeline Limited Partnership, Cause No. CV43296, In the District Court of
Midland County, Texas, 238th Judicial District ("Kniffen Estates Suit"). The
Kniffen Estates Suit was filed on March 2, 2001 by certain residents of the
Kniffen Estates, a residential subdivision located outside of Midland, Texas.
The allegations in the petition state that free crude oil products were
discovered in water wells in the Kniffen Estates area, on or about October 3,
2000. The plaintiffs claim the crude oil products are from a 1992 release from a
pipeline then owned by the Texas-New Mexico Pipe Line Company ("Tex-New Mex").
We purchased that pipeline from Tex-New Mex in 1999. The plaintiffs have alleged
Tex-New Mex was negligent, grossly negligent and malicious in failing to
accurately report and remediate the spill. With respect to us, the plaintiffs
are seeking damages arising from any contamination of the soil or groundwater
since we acquired the pipeline in question. No specific amount of money damages
was claimed, and it is not possible to determine any potential exposure to us at
this stage of the matter. In response to the Kniffen Estates Suit, we filed a
cross-claim against Tex-New Mex. In the cross-claim, we claim that, in relation
to the matters alleged by the plaintiffs, Tex-New Mex breached the purchase and
sale agreement between the parties dated May 1, 1999, by failing to disclose the
1992 release and by failing to undertake the defense and handling of the toxic
tort claims, fair market value claims, and remediation claims arising from the
release. Additionally, we are asserting claims of gross negligence, fraud and
specific performance. On April 5, 2002, we filed an amended cross-claim, which
alleges that Tex-New Mex defrauded us in Tex-New Mex's sale of the pipeline
systems to us in 1999. The amended cross-claim also alleges that various
practices employed by Tex-New Mex in the operation of its pipelines constitute
gross negligence and willful misconduct and void our obligation to indemnify
Tex-New Mex for remediation of releases that occurred prior to May 1, 1999. Due
to the early stages of the proceedings, it is not possible to determine the
possible outcome of this matter.

     Jimmie B. Cooper and Shryl S. Cooper v. Texas-New Mexico Pipe Line Company,
Inc., EOTT Energy Pipeline Limited Partnership and Amerada Hess Corporation,
Case No. CIV 01-1321 M/JHG, In the United States District Court for the District
of New Mexico. Plaintiffs in this lawsuit, filed on October 5, 2001, are surface
interest owners of certain property located in Lea County, New Mexico. The
plaintiffs allege that aquifers underlying their property and water wells
located on their property have been contaminated as a result of spills and leaks
from a pipeline running across their property that is or was owned by Tex-New
Mex and us. The plaintiffs also allege that oil and gas operations conducted by
Amerada Hess Corporation resulted in leaks or spills of pollutants that
ultimately contaminated the plaintiffs' aquifers and water wells. Our initial
investigation of this matter indicated that the alleged contamination of the
aquifers underlying the plaintiffs' property was not caused by leaks from the
pipeline now owned by us that traverses the plaintiffs' property. Although no
assurance can be made that we will successfully defend this lawsuit, we believe
that the ultimate resolution of this lawsuit will not have a materially adverse
impact on our financial position or results of operations.


                                      F-37
<PAGE>


                           EOTT ENERGY PARTNERS, L.P.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     Richard D. Warden and Nancy J. Warden v. EOTT Energy Pipeline Limited
Partnership and EOTT Energy Corp., Case No. CIV-02-370 L, In the United States
District Court for the Western District of Oklahoma. In this lawsuit, filed on
February 28, 2002, the plaintiffs are landowners, seeking damages allegedly
arising from a release of crude oil from a pipeline owned by us. Although we
undertook extensive remediation efforts with respect to the crude oil release
that is the subject of this lawsuit, plaintiffs allege that we did not properly
remediate the crude oil release and claim causes of action for negligence, gross
negligence, unjust enrichment, and nuisance. Due to the early stages of the
proceeding it is not possible for us to speculate on the possible outcome of
this matter. We believe that the ultimate resolution of this matter, however,
will not have a materially adverse impact on our financial position or results
of operations.

     David A. Huettner, et al. v. EOTT Energy Partners, L.P., et al, Case No.
1:02 CV-917, In the United States District Court, Northern District of Ohio,
Eastern Division ("Securities Suit"). This lawsuit was filed on May 15, 2002 for
alleged violations of the Securities and Exchange Act of 1934 and common law
fraud. The suit was brought by three of our former unitholders who claim that
Enron, our General Partner, certain of the officers and directors of Enron and
our General Partner and our independent accountants were aware of material
misstatements or omissions of information within various press releases, SEC
filings and other public statements, and failed to correct the alleged material
misstatements or omissions. Plaintiffs maintain that they were misled by our
press releases, SEC filings and other public statements when purchasing our
common units and were financially damaged thereby. Due to the recent filing of
this lawsuit, we have been unable to thoroughly investigate the validity of the
Plaintiffs' allegations, but based on management's current knowledge, we believe
the allegations are without merit. We can provide no assurances regarding the
outcome of this lawsuit, but will continue to gather and analyze new information
as it becomes available.

     Environmental. We are subject to extensive federal, state and local laws
and regulations covering the discharge of materials into the environment, or
otherwise relating to the protection of the environment, and which require
expenditures for remediation at various operating facilities and waste disposal
sites, as well as expenditures in connection with the construction of new
facilities. At the federal level, such laws include, among others, the Clean Air
Act ("CAA"), the Clean Water Act, the Oil Pollution Act, the Resource
Conservation and Recovery Act, the Comprehensive Environmental Response,
Compensation and Liability Act, and the National Environmental Policy Act, as
each may be amended from time to time. Failure to comply with these laws and
regulations may result in the assessment of administrative, civil, and criminal
penalties or the imposition of injunctive relief. We believe that our operations
and facilities are in substantial compliance with applicable environmental
regulations. Environmental laws and regulations have changed substantially and
rapidly over the last 20 years, and we anticipate that there will be continuing
changes. The clear trend in environmental regulation is to place more
restrictions and limitations on activities that may impact the environment, such
as emissions of pollutants, generation and disposal of wastes and use and
handling of chemical substances. Increasingly strict environmental restrictions
and limitations have increased our operating costs and those of other businesses
throughout the United States, and 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.

     Enron received a request for information from the Environmental Protection
Agency ("EPA") under Section 308 of the Clean Water Act, requesting information
regarding certain spills and releases from oil pipelines owned or operated by
Enron and its affiliated companies for the time period July 1, 1998 to July 11,
2001. Because we are the only Enron affiliated entity with domestic crude oil
pipeline operated by Enron, Enron responded for itself and on behalf of us to
the EPA's request on January 29, 2002. At this time, we are not able to predict
the outcome of the response made to the EPA's Section 308 request.


                                      F-38
<PAGE>


                           EOTT ENERGY PARTNERS, L.P.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     In connection with extensive asset purchases in 1998 and 1999, we
instituted a pipeline integrity management program in 1999. This program was
expanded in December of 2001 with a pipeline integrity assurance program to
comply with certain regulatory and legislative changes. Under this program, the
integrity of a pipeline is evaluated to avoid operating a pipeline that poses
significant risk of crude oil spills. Our written EOTT Pipeline Integrity
Program, which was intended to comply with the new Office of Pipeline Safety
Integrity Management regulations, was formally implemented in January 2002.
Anticipated operating expenses and capital expenditures to comply with that
program are budgeted annually; however, actual future expenditures may be
different from the amounts currently anticipated.

     In 2001, expenses incurred for spill clean up and remediation costs related
to the assets purchased from Tex-New Mex increased significantly. Based on our
experience with these assets, we filed an amended cross-claim against Tex-New
Mex, as previously discussed, alleging contingent claims for potential
remediation issues not yet known to us. We allege that Tex-New Mex failed to
report spills, underreported spills, failed to properly respond to leaks in the
pipeline and engaged in other activities with regard to the pipeline that may
result in future remediation liabilities. We obtained $20 million in insurance
coverage in connection with the acquisition from Tex-New Mex believing that
amount would be sufficient to cover remediation requirements along the pipeline
for a ten-year period. Through December 31, 2001, approximately $14 million of
environmental costs have been recognized under the insurance policy. We have
accrued current estimates for future remediation costs on all environmental
spills or releases which occurred prior to December 31, 2001; however, actual
future expenditures may be different than amounts currently anticipated. See
further discussion of the estimated environmental liability recorded at December
31, 2001 in Note 2.

     The presence of MTBE in some water supplies in California and other states
due to gasoline leakage from underground and aboveground storage tanks,
automobile and tanker truck accidents, pipelines and certain other sources
including operation of recreational watercraft on surface waters has led to
public concern that MTBE has contaminated drinking water supplies, and thereby
resulted in a possible health risk. As a result, in 1999, the Governor of
California ordered the ban of the use of MTBE as a gasoline component by the end
of 2002. The Governor of California recently extended the deadline for the ban
of the use of MTBE in California to December 31, 2003, based on concerns about
the availability and cost of alternative to MTBE.

     Heightened awareness of possible MTBE contamination has resulted in the
filing of numerous lawsuits, generally pursuing products liability theories, in
numerous jurisdictions including Texas. Defendants in these suits, including
MTBE producers, oil and gas companies, fuel distributors and others, have
claimed generally that federal and state laws permitted them to use MTBE to meet
federal clean air standards. Some defendants have contended that products
liability claims are pre-empted by the Clean Air Act amendments passed in 1999.
This defense has been recognized in at least two courts. One such case, which
reached trial in a California Superior Court, resulted in a jury verdict against
numerous defendants for contaminating ground water near Lake Tahoe, California.
As of May 7, 2002, this case was still pending with no determination of
penalties. While we believe we have manufactured and sold MTBE in compliance
with applicable laws permitting our activities, and we have not been included in
any of these lawsuits, it is possible that we could be adversely affected by
such a lawsuit in the future.

     Heightened public awareness has also resulted in other states and EPA
either passing or proposing restrictions on, or banning the use of, MTBE. As of
June, 2001, 12 states had enacted laws to phase out or limit MTBE. In July 2001,
Illinois enacted legislation banning MTBE as of July 2004. Rhode Island plans to
eliminate MTBE by July 2003. The New England Governors' conference resolved in
August 2001 to engage in a coordinated effort to amend the CAA to lift the
oxygen mandate for reformulated gasoline ("RFG") or to press the EPA to allow
these states to opt out of the RFG program's oxygen requirements. Currently,
Texas, the only state in which we produce MTBE, has not banned MTBE. No
assurances, however, can be made that


                                      F-39
<PAGE>


                           EOTT ENERGY PARTNERS, L.P.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Texas will not enact such legislation. The July 1999 report of the EPA's "Blue
Ribbon Panel on Oxygenates in Gasoline" recommended the reduced use of MTBE in
the United States. In 2000, EPA announced its intent to seek legislative changes
to give EPA the authority to ban the use of MTBE over a three-year period, and
as of March 2000, EPA also sought to ban MTBE using its rulemaking authority
under the Toxic Substances Control Act. Both the EPA and state regulatory
agencies have also established remediation and drinking water standards for MTBE
that require treatment for water with high concentrations of MTBE (EPA drinking
water standard is 20 to 40 parts per billion).

     The U.S. House of Representative and the U.S. Senate introduced legislation
in February 2001 with the goal of eliminating the use of MTBE in gasoline three
years from the date of enactment. Provisions are included within the proposed
Energy Policy Act of 2002 that would ban the use of MTBE four years post
enactment. However, the proposed Energy Policy Act of 2002 also includes
provisions that would provide monetary assistance to domestic MTBE producers to
be used to defray the costs associated with the transition of current MTBE
production facilities into facilities producing MTBE substitutes. The Bush
Administration has made statements in favor of conversion for MTBE substitutes
to the use of ethanol as an alternative to MTBE. If MTBE were to be restricted
or banned in Texas or throughout the United States, we could modify the MTBE
Plant to produce other products. We believe that modifying our existing MTBE
Plant to produce other gasoline blendstocks such as alkylates could require a
substantial capital investment. We cannot be certain that we would have the
resources available to effect such a conversion or that such conversion would be
economically viable. Further, we cannot predict whether the proposed Energy
Policy Act of 2002 or other similar legislation may be passed, or whether the
federal government will take steps to reverse California's ban on the use of
MTBE as a gasoline component, or if the Federal government will provide monetary
assistance for conversion. If the proposed federal legislation is enacted, or
the ban in California becomes effective, or Texas bans the use of MTBE, we would
expect such ban to materially reduce MTBE demand, which would have a material
adverse effect on our financial results.

     We may experience future releases of crude oil, MTBE or other substances
into the environment or discover releases that were previously unidentified.
While an inspection program is maintained on our pipelines to prevent and detect
such releases, and operational safeguards and contingency plans are in place for
the operation of our processing facilities, damages and liabilities incurred due
to any future environmental releases could affect our business. We believe that
our operations and facilities are in substantial compliance with applicable
environmental laws and regulations and that there are no outstanding potential
liabilities or claims relating to safety and environmental matters the
resolution of which, individually or in the aggregate, would have a materially
adverse effect on our financial position or results of operations. Our
environmental expenditures include amounts spent on permitting, compliance and
response plans, monitoring and spill cleanup and other remediation costs. In
addition, we could be required to spend substantial sums to ensure the integrity
of and upgrade our pipeline systems, and in some cases, we may take pipelines
out of service if we believe the costs of upgrades will exceed the value of the
pipelines.

     No assurance can be given, as to the ultimate amount or timing of future
expenditures for environmental remediation or compliance, and actual future
expenditures may be different from the amounts currently anticipated. In the
event of future increases in costs, we may be unable to pass on those increases
to our customers.

13.  FAIR VALUE OF FINANCIAL INSTRUMENTS

     Fair Value. Fair value represents the amount at which a financial
instrument could be exchanged in a current transaction between willing parties.
We have determined the estimated fair value amounts using


                                      F-40
<PAGE>

                           EOTT ENERGY PARTNERS, L.P.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



available market data and valuation methodologies. Judgment is required in
interpreting market data and the use of different market assumptions or
estimation methodologies may affect the estimated fair value amounts.

     We estimate that the fair value of our long-term 11% senior notes was
$255.3 million and $253.7 million at December 31, 2001 and 2000, respectively.
We believe that the carrying amounts of other financial instruments are a
reasonable estimate of their fair value, unless otherwise noted.

     Credit Risk. In the normal course of business, we extend credit to various
companies in the energy industry. Within this industry, certain elements of
credit risk exist and may, to varying degrees, exceed amounts recognized in the
accompanying consolidated financial statements, which may be affected by changes
in economic or other external conditions and may accordingly impact our overall
exposure to credit risk. Our exposure to credit loss in the event of
nonperformance is limited to the book value of the trade commitments included in
the accompanying Consolidated Balance Sheets. We manage our exposure to credit
risk through credit analysis, credit approvals, credit limits and monitoring
procedures. Further, we believe that our portfolio of receivables is well
diversified and that the allowance for doubtful accounts is adequate to absorb
any potential losses. We require collateral in the form of letters of credit for
certain of our receivables.

     During 2001, sales to one customer accounted for approximately 12% of our
total consolidated revenues. During 2000 and 1999, no single customer accounted
for more than 10% of total revenues.

     Market Risk. Our trading and non-trading transactions give rise to market
risk, which represents the potential loss that can be caused by a change in the
market value of a particular commitment. We closely monitor and manage our
exposure to market risk to ensure compliance with our stated risk management
policies which are regularly assessed to ensure their appropriateness given our
objectives, strategies and current market conditions.

     We enter into forward, futures and other contracts to hedge the impact of
market fluctuations on assets, lease crude oil purchases or other contractual
commitments. However, we do not consider our commodity futures and forward
contracts to be financial instruments since these contracts require or permit
settlement by the delivery of the underlying commodity, and thus, are not
subject to the provisions of SFAS No. 119. Changes in the market value of
transactions that were designated as hedges prior to 2001 were deferred until
the gain or loss was recognized on the hedged transaction at which time such
gains and losses were recognized through cost of sales. Changes in the market
value of transactions designated as energy trading activities are recorded every
period as mark-to-market gains or losses.

     We routinely enter into foreign currency futures contracts to hedge foreign
currency exposure from commercial transactions relating to current month crude
purchases and sales as well as fixed price swaps. These contracts generally
mature in one year or less. There were no foreign currency contracts outstanding
at December 31, 2001. At December 31, 2000, foreign currency contracts with a
notional principal amount of $10.0 million were outstanding, having exchange
rates which approximated current market exchange rates.

14.  NEW ACCOUNTING STANDARDS

     As more fully discussed in Note 2, in July 2001, the FASB issued SFAS No.
142, "Goodwill and Other Intangible Assets." SFAS No. 142, which must be applied
to fiscal years beginning after December 15, 2001, modifies the accounting and
reporting of goodwill and intangible assets.

     In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations." This statement requires entities to record the fair
value of a liability for legal obligations associated with the retirement
obligations of tangible long-lived assets in the period in which it is incurred.
When the liability is initially


                                      F-41
<PAGE>


                           EOTT ENERGY PARTNERS, L.P.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


recorded, a corresponding increase in the carrying amount of the related
long-lived asset would be recorded. Over time, accretion of the liability is
recognized each period, and the capitalized cost is depreciated over the useful
life of the related asset. Upon settlement of the liability, an entity either
settles the obligation for its recorded amount or incurs a gain or loss on
settlement. The standard is effective for fiscal years beginning after June 15,
2002, with earlier application encouraged. We are currently evaluating the
effect on its financial statements of adopting SFAS No. 143 and plan to adopt
the statement effective January 1, 2003.

     In August 2001, the FASB issued SFAS No. 144, "Accounting for Impairment or
Disposal of Long-Lived Assets." This statement clarified the financial
accounting and reporting for the impairment or disposal of long-lived assets.
Impairment is required to be recognized if the carrying amount of a long-lived
asset is not recoverable from its undiscounted cash flows. The impairment loss
to be recognized is the difference between the carrying amount and the fair
value of the asset. The standard also provides guidance on the accounting for
the long-lived assets that are held for disposal. This standard is effective for
the Partnership beginning January 1, 2002. The adoption of SFAS No. 144 did not
have a material impact on our results of operations or financial condition.

     In April 2002, the FASB issued SFAS No. 145 "Rescission of FASB Statements
No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical
Corrections." SFAS No. 145 rescinds SFAS No. 4, "Reporting Gains and Losses from
Extinguishments of Debt," SFAS No. 64 "Extinguishments of Debt Made to Satisfy
Sinking Fund Requirements" and SFAS No. 44, "Accounting for Intangible Assets of
Motor Carriers." The statement also amends SFAS No. 13, "Accounting For Leases"
to eliminate certain inconsistencies within that statement. SFAS 145 also makes
certain technical corrections or clarifications to other authoritative
pronouncements. Certain provisions of SFAS No. 145 are effective for
transactions occurring after or financial statements issued after May 15, 2002.
The adoption of SFAS 145 did not have a material impact on our results of
operations.

15.  BUSINESS SEGMENT INFORMATION

     We have four reportable segments, which management reviews in order to make
decisions about resources to be allocated and assess its performance: North
American Crude Oil - East of Rockies, Pipeline Operations, Liquids Operations
and West Coast Operations. The North American Crude Oil - East of Rockies
segment is organized into five operating regions and primarily purchases,
gathers, transports and markets crude oil. For segment reporting purposes, these
five operating regions have been aggregated as one reportable segment due to
similarities in their operations as allowed by SFAS No. 131. The Pipeline
Operations segment operates approximately 7,400 miles of active common carrier
pipelines in 12 states. The Liquids Operations includes the MTBE Plant and the
Mont Belvieu Facility. The West Coast Operations includes crude oil gathering
and marketing refined products marketing and a natural gas liquids business.
Effective June 30, 2001, we sold our crude oil gathering and marketing
operations on the West Coast to Pacific Marketing and Transportation LLC.

     The accounting policies of the segments are the same as those described in
the summary of significant accounting policies as discussed in Note 2. We
evaluate performance based on operating income (loss).

     We account for intersegment revenue and transfers between North American
Crude Oil - East of Rockies and West Coast Operations as if the sales or
transfers were to third parties, that is, at current market prices. Intersegment
revenues for Pipeline Operations are based on published pipeline tariffs.



                                      F-42
<PAGE>

                           EOTT ENERGY PARTNERS, L.P.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


FINANCIAL INFORMATION BY BUSINESS SEGMENT
 (IN THOUSANDS)

<Table>
<Caption>

                                              NORTH
                                             AMERICAN                     WEST                        CORPORATE
                                            CRUDE OIL      PIPELINE       COAST                           AND
                                             - EOR        OPERATIONS    OPERATIONS     LIQUIDS(a)       OTHER(g)    CONSOLIDATED(a)
                                           -----------    -----------   -----------   -----------     -----------   ---------------
YEAR ENDED DECEMBER 31, 2001
<S>                                        <C>            <C>           <C>           <C>             <C>            <C>
Revenue from external customers ........   $ 8,064,869    $    24,009   $   471,393   $    48,701     $        --    $ 8,608,972

Intersegment revenue(h) ................        47,490        103,515        19,698            --        (170,703)            --
                                           -----------    -----------   -----------   -----------     -----------    -----------

   Total revenue .......................     8,112,359        127,524       491,091        48,701        (170,703)     8,608,972
                                           -----------    -----------   -----------   -----------     -----------    -----------

Gross profit ...........................        25,213         56,689          (473)       18,279              --         99,708
                                           -----------    -----------   -----------   -----------     -----------    -----------

Operating income (loss) ................         9,742         49,966        (4,679)      (11,926)        (24,848)        18,255

Other expense ..........................            --             --            --            --         (34,561)       (34,561)
                                           -----------    -----------   -----------   -----------     -----------    -----------

Net income (loss) before cumulative
    effect of accounting changes .......         9,742         49,966        (4,679)      (11,926)        (59,409)       (16,306)
                                           -----------    -----------   -----------   -----------     -----------    -----------

Long-lived assets ......................        75,703        266,806        28,270        83,552          11,544        465,875
                                           -----------    -----------   -----------   -----------     -----------    -----------

Total assets ...........................       629,199        290,805        48,091        85,961          46,454      1,100,510
                                           -----------    -----------   -----------   -----------     -----------    -----------

Additions to long-lived assets .........         3,844         16,500        11,028        84,716           2,140        118,228
                                           -----------    -----------   -----------   -----------     -----------    -----------

Depreciation and amortization ..........         6,010         21,792         2,146         3,047           3,083         36,078
                                           -----------    -----------   -----------   -----------     -----------    -----------
</Table>


<Table>
<Caption>

                                             NORTH
                                            AMERICAN                                WEST             CORPORATE
                                            CRUDE OIL          PIPELINE            COAST                AND
                                             - EOR            OPERATIONS        OPERATIONS(b)        OTHER(b)(g)     CONSOLIDATED
                                          ------------       ------------       ------------        ------------     ------------
YEAR ENDED DECEMBER 31, 2000 (UNAUDITED)
<S>                                       <C>                <C>                <C>                 <C>              <C>
Revenue from external customers ...       $ 10,699,692       $     20,988       $    893,325        $         --     $ 11,614,005

Intersegment revenue(h) ...........             10,477            119,305                 --            (129,782)              --
                                          ------------       ------------       ------------        ------------     ------------

   Total revenue ..................         10,710,169            140,293            893,325            (129,782)      11,614,005
                                          ------------       ------------       ------------        ------------     ------------

Gross profit ......................             18,524             73,606              3,016                  --           95,146
                                          ------------       ------------       ------------        ------------     ------------

Operating income (loss) ...........              2,109             66,292               (345)            (22,817)          45,239

Other expense .....................                 --                 --                 --             (31,406)         (31,406)
                                          ------------       ------------       ------------        ------------     ------------

Net income (loss) .................              2,109             66,292               (345)            (54,223)          13,833
                                          ------------       ------------       ------------        ------------     ------------

Long-lived assets .................             79,416            269,343             31,693              13,481          393,933
                                          ------------       ------------       ------------        ------------     ------------

Total assets ......................            998,013            288,943            124,427              79,637        1,491,020
                                          ------------       ------------       ------------        ------------     ------------

Additions to long-lived assets ....                838              4,328              2,406               6,698           14,270
                                          ------------       ------------       ------------        ------------     ------------

Depreciation and amortization .....              7,515             21,153              2,689               2,511           33,868
                                          ------------       ------------       ------------        ------------     ------------
</Table>



                                      F-43

<PAGE>


                           EOTT ENERGY PARTNERS, L.P.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

<Table>
<Caption>



                                             NORTH
                                           AMERICAN                                WEST             CORPORATE
                                           CRUDE OIL           PIPELINE           COAST                AND
                                          - EOR(c)(d)        OPERATIONS(c)  OPERATIONS(c)(e)(f)    OTHER (d)(g)      CONSOLIDATED
                                          -----------        -------------  -------------------    ------------      ------------
                                                                                (RESTATED)                             (RESTATED)
<S>                                       <C>                <C>            <C>                   <C>                <C>
YEAR ENDED DECEMBER 31, 1999 (UNAUDITED)

Revenue from external customers ...       $ 7,999,092        $    28,647       $   636,676        $       (14)       $ 8,664,401

Intersegment revenue(h) ...........            43,653             89,890            17,360           (150,903)                --
                                          -----------        -----------       -----------        -----------        -----------

   Total revenue ..................         8,042,745            118,537           654,036           (150,917)         8,664,401
                                          -----------        -----------       -----------        -----------        -----------

Gross profit ......................            16,293             55,595             2,394                (48)            74,234
                                          -----------        -----------       -----------        -----------        -----------

Operating income (loss) ...........            (1,850)            51,006            (1,128)           (20,025)            28,003

Other expense .....................                --                 --                --            (29,189)           (29,189)
                                          -----------        -----------       -----------        -----------        -----------

Net income (loss) before cumulative
    effect of accounting change ...            (1,850)            51,006            (1,128)           (49,214)            (1,186)
                                          -----------        -----------       -----------        -----------        -----------

Long-lived assets .................            77,247            285,180            32,605              9,463            404,495
                                          -----------        -----------       -----------        -----------        -----------

Total assets ......................         1,084,613            306,321           129,461             38,266          1,558,661
                                          -----------        -----------       -----------        -----------        -----------

Additions to long-lived assets ....             1,194             49,544             1,353              6,638             58,729
                                          -----------        -----------       -----------        -----------        -----------

Depreciation and amortization .....             8,704             20,012             2,669              1,751             33,136
                                          -----------        -----------       -----------        -----------        -----------
</Table>


         (a)  2001 includes the $29.1 million impairment of the EGLI contracts.
              See Note 7.

         (b)  2000 includes nonrecurring income of $1.3 million related to
              mid-continent NGL activities recorded in West Coast Operations and
              nonrecurring severance charges of $0.7 million recorded in
              Corporate and Other.

         (c)  1999 includes twelve months of results of operations associated
              with the assets acquired from Koch and eight months of results of
              operations associated with the assets acquired from Texas-New
              Mexico Pipe Line Company.

         (d)  1999 includes nonrecurring severance charges of $2.0 million of
              which $1.8 million is recorded in North American Crude Oil - EOR
              and $0.2 million is recorded in Corporate.

         (e)  1999 includes nonrecurring charges of $8.8 million of costs
              related to mid-continent NGL activities.

         (f)  The 1999 West Coast Operations and Consolidated amounts have been
              restated for certain unauthorized mid-continent NGL trading
              activities. See Note 3.

         (g)  Corporate and Other also includes intersegment eliminations.

         (h)  Intersegment sales for North American Crude Oil - EOR and West
              Coast Operations are made at prices comparable to those received
              from external customers. Intersegment sales for Pipeline
              Operations are based on published pipeline tariffs.



                                      F-44
<PAGE>

                           EOTT ENERGY PARTNERS, L.P.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


16.  SUBSEQUENT EVENTS

     On January 21, 2002, the Board of Directors of EOTT Energy Corp., as
General Partner, declared a quarterly cash distribution of $0.25 per common unit
for the period October 1, 2001 through December 31, 2001, which is lower than
the minimum quarterly distribution of $0.475 per common unit intended under the
MLP Partnership Agreement. In connection with the fourth quarter distribution,
we requested distribution support from Enron under the terms of Enron's
distribution support agreement. No support was provided in connection with our
request. See further discussion in Note 10. The total distribution of
approximately $4.7 million was paid on February 14, 2002 to the General Partner
and all common unitholders of record as of the close of business on January 31,
2002. The fourth quarter 2001 distribution was paid utilizing Available Cash, as
defined in the Partnership Agreement, from the Partnership.

     On February 26, 2002, we received a commitment from Standard Chartered to
extend the interim credit facility to February 28, 2003 subject to closing
conditions. See further discussion in Note 8.

     On April 3, 2002, we suspended the first quarter 2002 distribution to
unitholders. See further discussion in Notes 8 and 10.


     On April 12, 2002, a federal bankruptcy judge signed the stipulation and
agreed order approving the rejection of the contracts with EGLI. The order
became final and non-appealable on April 12, 2002. See further discussion in
Notes 5 and 10.

     On April 23, 2002, we closed the amended and extended $300 million Credit
Facility with Standard Chartered and extended the Inventory Repurchase Agreement
and Receivables Agreement. The Facilities will be available through the end of
February 2003. See further discussion in Note 8.



                                      F-45
<PAGE>


17.   QUARTERLY FINANCIAL DATA (UNAUDITED)
      (In Thousands, Except Per Unit Amounts)

<Table>
<Caption>

                                                    FIRST            SECOND          THIRD            FOURTH
                                                   QUARTER           QUARTER        QUARTER           QUARTER            TOTAL
                                                 ------------     -------------   ------------     ------------      ------------
2001
<S>                                              <C>              <C>             <C>              <C>               <C>
   Revenues ..................................   $  2,544,437     $   2,256,946   $  2,322,553     $  1,485,036      $  8,608,972

   Gross profit ..............................         25,301            24,992         30,817           18,598            99,708

   Operating income ..........................         12,497            12,365         17,417          (24,024)           18,255

   Net income (loss) before cumulative
      effect of accounting change ............          5,269             4,133          7,363          (33,071)          (16,306)

   Basic net income (loss) before cumulative
      effect of accounting change per Unit
      Common .................................           0.19              0.15           0.26            (1.18)            (0.58)
      Subordinated ...........................           0.19              0.15           0.26            (1.18)            (0.58)

   Diluted net income (loss) before cumulative
      effect of accounting change per Unit ...           0.19              0.15           0.26            (1.18)            (0.58)

   Cash distributions per Common Unit(2) .....          0.475             0.475          0.475            0.475             1.900
                                                 ------------     -------------   ------------     ------------      ------------

2000 (RESTATED)(1)(3)

   Revenues ..................................   $  2,681,446     $   2,514,458   $  3,144,627     $  3,273,474      $ 11,614,005

   Gross profit ..............................         21,700            25,105         23,715           24,626            95,146

   Operating income ..........................         10,621            12,528         11,755           10,335            45,239

   Net income ................................          1,971             4,412          4,109            3,341            13,833

   Basic net income per Unit
      Common .................................           0.07              0.16           0.15             0.12              0.49
      Subordinated ...........................           0.07              0.16           0.15             0.12              0.49

   Diluted net income per Unit ...............           0.07              0.16           0.15             0.12              0.49

   Cash distributions per Common Unit(2) .....          0.475             0.475          0.475            0.475             1.900
                                                 ------------     -------------   ------------     ------------      ------------

2000 (REPORTED)(1)(3)

   Revenues ..................................   $  2,681,696     $   2,514,934   $  3,143,529     $  3,273,846      $ 11,614,005

   Gross profit ..............................         21,950            25,581         22,617           24,998            95,146

   Operating income ..........................         10,871            13,004         10,657           10,707            45,239

   Net income ................................          2,221             4,888          3,011            3,713            13,833

   Basic net income per Unit
      Common .................................           0.08              0.17           0.11             0.13              0.49
      Subordinated ...........................           0.08              0.17           0.11             0.13              0.49

   Diluted net income per Unit ...............           0.08              0.17           0.11             0.13              0.49

   Cash distributions per Common Unit(2) .....          0.475             0.475          0.475            0.475             1.900
                                                 ------------     -------------   ------------     ------------      ------------
</Table>



                                      F-46
<PAGE>



                           EOTT ENERGY PARTNERS, L.P.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


<Table>
<Caption>


                                                        FIRST        SECOND          THIRD            FOURTH
                                                       QUARTER       QUARTER        QUARTER           QUARTER            TOTAL
                                                    ------------  -------------   ------------      ------------      -----------
<S>                                                 <C>           <C>             <C>               <C>               <C>
1999 (RESTATED)(3)

   Revenues ......................................  $  1,433,157  $   2,257,886   $  2,313,569      $  2,659,789      $ 8,664,401

   Gross profit ..................................        21,080         20,029         18,003            15,122           74,234

   Operating income ..............................         8,179          6,983          5,680             7,161           28,003

   Net income (loss) before cumulative
      effect of accounting change ................         2,240            450         (1,880)           (1,996)          (1,186)

   Basic net income (loss) before cumulative
      effect of accounting change per Unit
        Common ...................................          0.07           0.02          (0.08)            (0.07)           (0.08)
        Subordinated .............................          0.13           0.02          (0.08)            (0.07)              --

   Diluted net income (loss) before cumulative
      effect of accounting change per Unit .......          0.09           0.02          (0.08)            (0.07)           (0.05)

   Cash distributions per Common Unit(2) .........         0.475          0.475          0.475             0.475            1.900
                                                    ------------  -------------   ------------      ------------      -----------

1999 (REPORTED)(3)

   Revenues ......................................  $  1,433,157  $   2,259,303   $  2,315,464      $  2,656,477      $ 8,664,401

   Gross profit ..................................        21,374         21,761         20,433             9,637           73,205

   Operating income ..............................         8,473          8,715          8,110             1,676           26,974

   Net income (loss) before cumulative
      effect of accounting change ................         2,534          2,182            550            (7,481)          (2,215)

   Basic net income (loss) before cumulative
      effect of accounting change per Unit
        Common ...................................          0.08           0.09           0.02             (0.27)           (0.13)
        Subordinated .............................          0.15           0.09           0.02             (0.27)           (0.01)

   Diluted net income (loss) before cumulative
      effect of accounting change per Unit .......          0.10           0.09           0.02             (0.27)           (0.09)

   Cash distributions per Common Unit(2) .........         0.475          0.475          0.475             0.475            1.900
                                                    ------------  -------------   ------------      ------------      -----------
</Table>


(1)  Second quarter 2000 amounts include nonrecurring items of $1.5 million
     related to insurance proceeds received for the theft of NGL product offset
     by other costs primarily related to severance charges associated with a
     former officer. See Note 7 to the Consolidated Financial Statements.

(2)  Cash distributions are shown in the quarter paid and are based on the prior
     quarter's earnings.

(3)  The 2000 and 1999 amounts have been restated to reflect the fair value
     impact of the unauthorized trading activities over the periods during which
     the contracts were outstanding. See further discussion in Note 3 to the
     Consolidated Financial Statements.





                                      F-47
<PAGE>



                                   SCHEDULE II
                           EOTT ENERGY PARTNERS, L.P.
                 VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
              FOR THE YEARS ENDED DECEMBER 31, 1999, 2000 AND 2001
                                 (In Thousands)

================================================================================
<Table>
<Caption>


                                                  Balance at    Charged to                         Balance
                                                  Beginning     Costs and      Deductions           at End
                                                  of Period      Expenses       and Other          of Period
                                                  ----------    ----------     ----------          ---------
<S>                                               <C>           <C>            <C>                 <C>
Year ended December 31, 1999 (Unaudited)
   Allowance for Doubtful Accounts ..........     $ 1,860        $    --        $  (128)           $ 1,732
   Litigation Provisions ....................     $ 1,400        $    --        $  (400)           $ 1,000
   Safety and Environmental .................     $ 1,000        $    --        $ 1,998            $ 2,998

Year ended December 31, 2000 (Unaudited)
   Allowance for Doubtful Accounts ..........     $ 1,732        $    --        $    95            $ 1,827
   Litigation Provisions ....................     $ 1,000        $    --        $    --            $ 1,000
   Safety and Environmental .................     $ 2,998        $ 2,000        $(2,038)           $ 2,960

Year ended December 31, 2001
   Allowance for Doubtful Accounts ..........     $ 1,827        $    --        $  (602)           $ 1,225
   Litigation Provisions ....................     $ 1,000        $   315        $(1,000)           $   315
   Safety and Environmental .................     $ 2,960        $ 5,365        $(1,489)           $ 6,836
</Table>

                                       S-1


<PAGE>


                                INDEX TO EXHIBITS


<Table>
<Caption>


EXHIBIT
NUMBER            DESCRIPTION
-------           -----------
<S>       <C>     <C>
  3.1     --      Form of Partnership Agreement of EOTT Energy Partners, L.P.
                  (incorporated by reference to Exhibit 3.1 to Registration
                  Statement, File No. 33-73984)

  3.2     --      Amendment No. 1 dated as of August 8, 1995, to the Amended and
                  Restated Agreement of Limited Partnership of EOTT Energy
                  Partners, L.P. (incorporated by reference to Exhibit 3.2 to
                  Annual Report on Form 10-K for the Year Ended December 31,
                  1995)

  3.3     --      Amendment No. 2 dated as of July 16, 1996, to the Amended and
                  Restated Agreement of Limited Partnership of EOTT Energy
                  Partners, L.P. (incorporated by reference to Exhibit 3.3 to
                  Quarterly Report on Form 10-Q for the Quarter Ended June 30,
                  1996)

  3.4     --      Amendment No. 3 dated as of February 13, 1997, to the Amended
                  and Restated Agreement of Limited Partnership of EOTT Energy
                  Partners, L.P. (incorporated by reference to Exhibit 3.4 to
                  Annual Report on Form 10-K for the Year Ended December 31,
                  1996)

  3.5     --      Amendment No. 4 dated as of November 30, 1998, to the Amended
                  and Restated Agreement of Limited Partnership of EOTT Energy
                  Partners, L.P. (incorporated by reference to Exhibit 3.5 to
                  Annual Report on Form 10-K for the Year Ended December 31,
                  1998)

  3.6     --      Amendment No. 5 dated as of December 7, 1998, to the Amended
                  and Restated Agreement of Limited Partnership of EOTT Energy
                  Partners, L.P. (incorporated by reference to Exhibit 3.6 to
                  Annual Report on Form 10-K for the Year Ended December 31,
                  1998)

  3.7     --      Amendment No. 6 dated as of September 16, 1999 to the Amended
                  and Restated Agreement of Limited Partnership of EOTT Energy
                  Partners, L.P. (incorporated by reference to Exhibit 3.1 to
                  Current Report on Form 8-K dated September 29, 1999)

  3.8     --      Reorganization Agreement dated as of August 29, 2001, between
                  EOTT Energy Partners, L.P., EOTT Energy Operating Limited
                  Partnership, EOTT Energy Pipeline Limited Partnership, EOTT
                  Energy Canada Limited Partnership, EOTT Energy Corp., and EOTT
                  Energy General Partner (incorporated by reference to Exhibit
                  3.8 to Current Report on Form 8-K/A dated August 30, 2001)

  3.9     --      Amendment No. 7 dated as of August 29, 2001 to the Amended and
                  Restated Agreement of Limited Partnership of EOTT Energy
                  Partners, L.P. (incorporated by reference to Exhibit 3.9 to
                  Current Report on Form 8-K/A dated August 30, 2001)

  3.10    --      Form of Amended and Restated Agreement of Limited Partnership
                  of EOTT Energy Operating Limited Partnership (incorporated by
                  reference to Exhibit 10.11 to Registration Statement, File No.
                  33-73984)
</Table>


<PAGE>

<Table>

<S>       <C>     <C>
  3.11    --      Amendment No. 1 dated as of September 1, 1999, to Amended and
                  Restated Agreement of Limited Partnership of EOTT Energy
                  Operating Limited Partnership (incorporated by reference to
                  Exhibit 3.2 to current report on Form 8-K dated September 29,
                  1999)

  3.12    --      Amendment No. 2 dated as of August 29, 2001, to Amended and
                  Restated Agreement of Limited Partnership of EOTT Energy
                  Operating Limited Partnership (incorporated by reference to
                  Exhibit 3.10 to Current Report on Form 8-K/A dated August 30,
                  2001)

  3.13    --      Form of Amended and Restated Agreement of Limited Partnership
                  of EOTT Energy Pipeline Limited Partnership (incorporated by
                  reference to Exhibit 3.8 to Registration Statement, File No.
                  33-82269)

  3.14    --      Amendment No. 1 dated as of September 1, 1999, to Amended and
                  Restated Agreement of Limited Partnership of EOTT Energy
                  Pipeline Limited Partnership (incorporated by reference to
                  Exhibit 3.3 to current report on Form 8-K dated September 29,
                  1999)

  3.15    --      Amendment No. 2 dated as of August 29, 2001, to Amended and
                  Restated Agreement of Limited Partnership of EOTT Energy
                  Pipeline Limited Partnership (incorporated by reference to
                  Exhibit 3.11 to Current Report on Form 8-K/A dated August 30,
                  2001)

  3.16    --      Amended and Restated Agreement of Limited Partnership of EOTT
                  Energy Canada Limited Partnership (incorporated by reference
                  to Exhibit 3.9 to Registration Statement, File No. 33-82269)

  3.17    --      Amendment No. 1 dated as of September 1, 1999, to Amended and
                  Restated Agreement of Limited Partnership of EOTT Energy
                  Canada Limited Partnership (incorporated by reference to
                  Exhibit 3.2 to current report on Form 8-K dated September 29,
                  1999)

  3.18    --      Amendment No. 2 dated as of August 29, 2001, to Amended and
                  Restated Agreement of Limited Partnership of EOTT Energy
                  Canada Limited Partnership (incorporated by reference to
                  Exhibit 3.12 to Current Report on Form 8-K/A dated August 30,
                  2001)

  3.19    --      Agreement of Limited Partnership dated as of June 28, 2001 of
                  EOTT Energy Liquids, L.P. (incorporated by reference to
                  Exhibit 3.13 to Quarterly Report on Form 10-Q for the Quarter
                  Ended September 30, 2001)

  3.20    --      Limited Liability Company Agreement dated as of June 27, 2001
                  of EOTT Energy General Partner, L.L.C. (incorporated by
                  reference to Exhibit 3.14 to Quarterly Report on Form 10-Q for
                  the Quarter Ended September 30, 2001)

  3.21    --      Amendment No. 1 dated as of August 29, 2001, to the Limited
                  Liability Company Agreement of EOTT Energy General Partner,
                  L.L.C. (incorporated by reference to Exhibit 3.15 to Quarterly
                  Report on Form 10-Q for the Quarter Ended September 30, 2001)

  4.1     --      Form of Indenture for Senior Debt Securities and Subordinated
                  Debt Securities (incorporated by reference to Exhibit 4.1 to
                  Registration Statement, File No. 333-82269)
</Table>

<PAGE>


<Table>

<S>       <C>     <C>
   10.01  --      Form of Corporate Services Agreement between Enron Corp. and
                  EOTT Energy Corp. (incorporated by reference to Exhibit 10.08
                  to Registration Statement, File No. 33-73984)

   10.02  --      Form of Contribution and Closing Agreement between EOTT Energy
                  Corp. and EOTT Energy Partners, L.P. (incorporated by
                  reference to Exhibit 10.09 to Registration Statement, File No.
                  33-73984)

   10.03  --      Form of Ancillary Agreement by and among Enron Corp., EOTT
                  Energy Partners, L.P., EOTT Energy Operating Limited
                  Partnership, EOTT Energy Pipeline Limited Partnership, EOTT
                  Energy Canada Limited Partnership, and EOTT Energy Corp.
                  (incorporated by reference to Exhibit 10.10 to Registration
                  Statement, File No. 33-73984)

   10.04  --      EOTT Energy Corp. Annual Incentive Plan (incorporated by
                  reference to Exhibit 10.14 to Registration Statement, File No.
                  33-73984)

   10.05  --      EOTT Energy Corp. 1994 Unit Option Plan and the related Option
                  Agreement (incorporated by reference to Exhibit 10.15 to
                  Registration Statement, File No. 33-73984)

   10.06  --      EOTT Energy Corp. Severance Pay Plan (incorporated by
                  reference to Exhibit 10.16 to Registration Statement, File No.
                  33-73984)

   10.07  --      EOTT Energy Corp. Long Term Incentive Plan (incorporated by
                  reference to Exhibit 10.19 to Quarterly Report on Form 10-Q
                  for the Quarter Ended September 30, 1997)

   10.08  --      Support Agreement dated September 21, 1998 between EOTT Energy
                  Partners, L.P., EOTT Energy Operating Limited Partnership and
                  Enron Corp. (incorporated by reference to Exhibit 10.22 to
                  Quarterly Report on Form 10-Q for the Quarter Ended September
                  30, 1998)

***10.09  --      Crude Oil Supply and Terminalling Agreement dated as of
                  December 1, 1998 between Koch Oil Company and EOTT Energy
                  Operating Limited Partnership (incorporated by reference to
                  Exhibit 10.23 to Annual Report on Form 10-K for the Year Ended
                  December 31, 1998)

   10.10  --      Amended and Restated Credit Agreement as of December 1, 1998
                  between EOTT Energy Operating Limited Partnership, as
                  Borrower, and Enron Corp., as Lender (incorporated by
                  reference to Exhibit 10.24 to Annual Report on Form 10-K for
                  the Year Ended December 31, 1998)

   10.11  --      Amendment dated March 17, 1999 to the Amended and Restated
                  Credit Agreement as of December 1, 1998 between EOTT Energy
                  Operating Limited Partnership, as Borrower, and Enron Corp.,
                  as Lender (incorporated by reference to Exhibit 10.26 to
                  Annual Report on Form 10-K for the Year Ended December 31,
                  1998)

***10.12  --      Amendment dated December 1, 1998 to the Crude Oil Supply and
                  Terminalling Agreement dated as of December 1, 1998 between
                  Koch Oil Company and EOTT Energy Operating Limited Partnership
                  (incorporated by reference to Exhibit 10.28 to Annual Report
                  on Form 10-K for the Year Ended December 31, 1998)
</Table>

<PAGE>

<Table>

<S>       <C>     <C>
   10.13  --      Amendment dated August 11, 1999 to the Amended and Restated
                  Credit Agreement as of December 1, 1998 between EOTT Energy
                  Operating Limited Partnership, as Borrower, and Enron Corp.,
                  as Lender (incorporated by reference to Exhibit 10.30 to
                  Quarterly Report on Form 10-Q for the Period Ended June 30,
                  1999)

   10.14  --      Form of Executive Employment Agreement between EOTT Energy
                  Corp. and Dana R. Gibbs (incorporated by reference to Exhibit
                  10.32 to Quarterly Report on Form 10-Q for the Period Ended
                  September 30, 2000)

   10.15  --      Form of Executive Employment Agreement between EOTT Energy
                  Corp. and Lawrence Clayton, Jr. (incorporated by reference to
                  Exhibit 10.33 to Quarterly Report on Form 10-Q for the Period
                  Ended September 30, 2000)

***10.16  --      Letter Agreement dated September 14, 2000 amending Crude Oil
                  Supply and Terminalling Agreement (incorporated by reference
                  to Exhibit 10.34 to Quarterly Report on Form 10-Q for the
                  Period Ended September 30, 2000)

   10.17  --      Form of Executive Employment Agreement between EOTT Energy
                  Corp. and Molly Sample (incorporated by reference to Exhibit
                  10.35 to Annual Report on Form 10-K for the year ended
                  December 31, 2000)

   10.18  --      Form of Executive Employment Agreement between EOTT Energy
                  Corp. and Lori Maddox (incorporated by reference to Exhibit
                  10.36 to Annual Report on Form 10-K for the year ended
                  December 31, 2000)

***10.19  --      Letter Agreement dated February 6, 2001 amending Crude Oil
                  Supply and Terminalling Agreement dated December 1, 1998
                  (incorporated by reference to Exhibit 10.37 to Annual Report
                  on Form 10-K for the year ended December 31, 2000)

   10.20  --      Purchase and Sale Agreement between Enron Corp. and EOTT
                  Energy Partners, L.P., dated June 29, 2001, with list of
                  omitted schedules and agreement to furnish omitted schedules
                  supplementally to the Securities and Exchange Commission upon
                  request (incorporated by reference to Exhibit 10.38 to Current
                  Report on Form 8-K dated July 13, 2001)

***10.21  --      Mont Belvieu Storage Capacity Purchase Agreement Dated as of
                  June 29, 2001 between EOTT Energy Liquids, L.P. and Enron Gas
                  Liquids, Inc. (incorporated by reference to Exhibit 10.39 to
                  Quarterly Report on Form 10-Q for the period ended June 30,
                  2001)

***10.22  --      Toll Conversion Agreement dated as of June 29, 2001 between
                  EOTT Energy Liquids, L.P. and Enron Gas Liquids, Inc.
                  (incorporated by reference to Exhibit 10.40 to Quarterly
                  Report on Form 10-Q for the period ended June 30, 2001)

   10.23  --      Administrative Services Agreement dated as of June 29, 2001
                  between EOTT Energy Corp. and EOTT Energy General Partner,
                  L.L.C. (incorporated by reference to Exhibit 10.41 to
                  Quarterly Report on Form 10-Q for the period ended June 30,
                  2001)

** 10.24  --      Letter Agreement dated June 27, 2001, amending Crude Oil
                  Supply and Terminalling Agreement dated December 1, 1998
</Table>


<PAGE>
<Table>

<S>       <C>     <C>
** 10.25  --      Letter Agreement dated August 23, 2001, amending Crude Oil
                  Supply and Terminalling Agreement dated December 1, 1998

*  10.26  --      Letter Agreement dated December 18, 2001, amending Crude Oil
                  Supply and Terminalling Agreement dated December 1, 1998

** 10.27  --      Letter Agreement dated January 9, 2002, amending Crude Oil
                  Supply and Terminalling Agreement dated December 1, 1998

** 10.28  --      Commodity Repurchase Agreement, dated as of February 28, 1998,
                  between EOTT Energy Operating Limited Partnership and Standard
                  Chartered Trade Service Corporation

** 10.29  --      Receivable(s) Purchase Agreement, dated as of October 19,
                  1999, between EOTT Energy Operating Limited Partnership and
                  Standard Chartered Trade Services Corporation.

*  10.30  --      First Amendment to the Receivable(s) Purchase Agreement, dated
                  as of January 12, 2000, by and between EOTT Energy Operating
                  Limited Partnership and Standard Chartered Trade Services
                  Corporation

** 10.31  --      Second Amended and Restated Reimbursement, Loan and Security
                  Agreement, dated as of April 23, 2002, by and between EOTT
                  Energy Operating Limited Partnership, et al. and Standard
                  Chartered Bank

*  10.32  --      Letter Agreement, dated as of April 23, 2002, regarding
                  Commodity Repurchase Agreement and Receivable(s) Purchase
                  Agreement

   18.1   --      Preferability Letter on Change in Accounting Principle
                  (incorporated by reference to Exhibit 18.1 to Quarterly Report
                  on Form 10-Q for the Period Ended March 31, 2001)

*  21.1   --      Subsidiaries of the Registrant

*  23.1   --      Consent of PricewaterhouseCoopers LLP
</Table>


*   Filed herewith.

**  Filed herewith; however, confidential treatment has been requested with
    respect to certain portions of this exhibit.

*** Certain portions of this exhibit have been treated confidentially.