EOTT ENERGY PARTNERS LP, 424B5, 1999-09-24

EOTT ENERGY PARTNERS LP
424B5, 1999-09-24
PETROLEUM BULK STATIONS & TERMINALS

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<PAGE> 1

FILED PURSUANT TO RULE 424(b)(5)
REGISTRATION NO. 333-82269
PROSPECTUS SUPPLEMENT
(TO PROSPECTUS DATED SEPTEMBER 2, 1999)

3,500,000 COMMON UNITS

EOTT ENERGY PARTNERS, L.P.

REPRESENTING LIMITED PARTNER INTERESTS

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

We are offering 3,500,000 common units as described in this prospectus
supplement and the accompanying prospectus. The common units represent limited
partner interests in EOTT Energy Partners, L.P. Our common units are traded on
the New York Stock Exchange under the symbol "EOT." On September 23, 1999, the
last reported sale price for the common units on the New York Stock Exchange was
$16.00 per common unit.

INVESTING IN THE COMMON UNITS INVOLVES CERTAIN RISKS. WE URGE YOU TO
CONSIDER CAREFULLY THE "RISK FACTORS" BEGINNING ON PAGE 2 OF THE ACCOMPANYING
PROSPECTUS.

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

<TABLE>
<CAPTION>
Per
Common Unit Total
----------- -----
<S> <C> <C>
Public offering price....................................... $16.00 $56,000,000
Underwriting discounts and commissions...................... $ 0.88 $ 3,080,000
Proceeds, before expenses, to EOTT.......................... $15.12 $52,920,000
</TABLE>

The underwriters may also purchase up to an additional 525,000 common units
on the same terms described above within 30 days from the date of this
prospectus supplement to cover over-allotments, if any. The underwriters are
offering the common units subject to various conditions and may reject all or
part of any order. The underwriters expect to deliver the common units to
purchasers on September 29, 1999.

Neither the Securities and Exchange Commission nor any state securities
commission has approved or disapproved of these securities or determined if this
prospectus supplement or the accompanying prospectus is truthful or complete.
Any representation to the contrary is a criminal offense.

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

PAINEWEBBER INCORPORATED
LEHMAN BROTHERS
DAIN RAUSCHER WESSELS
A DIVISION OF DAIN RAUSCHER INCORPORATED
ING BARINGS
THE DATE OF THIS PROSPECTUS SUPPLEMENT IS SEPTEMBER 23, 1999.
<PAGE> 2

TABLE OF CONTENTS

<TABLE>
<CAPTION>
PROSPECTUS SUPPLEMENT PAGE NO.
--------------------- --------
<S> <C>
Summary............................ S-1
Use of Proceeds.................... S-11
Capitalization..................... S-12
Price Range of Common Units and
Distributions.................... S-13
Selected Historical Financial
Data............................. S-14
Management's Discussion and
Analysis of Financial Condition
and
Results of Operations............ S-16
Business........................... S-25
Management......................... S-32
Principal Unitholders.............. S-34
Underwriting....................... S-35
Legal Matters...................... S-36
Experts............................ S-36
</TABLE>

<TABLE>
<CAPTION>
PROSPECTUS PAGE NO.
---------- --------
<S> <C>
About This Prospectus.............. ii
Where You Can Find More
Information...................... ii
Cautionary Statement Regarding
Forward Looking Statements....... iii
Who We Are......................... 1
Risk Factors....................... 2
Conflicts of Interest and Fiduciary
Responsibilities................. 7
Use of Proceeds.................... 8
Description of the Debt
Securities....................... 8
Ratio of Earnings to Fixed
Charges.......................... 13
Description of Our Common Units.... 13
Cash Distribution Policy........... 15
Description of Our Partnership
Agreement........................ 16
Tax Considerations................. 19
Plan of Distribution............... 34
Legal Matters...................... 35
Experts............................ 35
</TABLE>

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

IMPORTANT NOTICE ABOUT INFORMATION IN THIS
PROSPECTUS SUPPLEMENT AND THE ACCOMPANYING PROSPECTUS

This document is in two parts. The first part is the prospectus supplement,
which describes our business and the specific terms of this common unit
offering. The second part, the base prospectus, gives more general information,
some of which may not apply to the offering. Generally, when we refer only to
the "prospectus," we are referring to both parts combined.

IF THE DESCRIPTION OF THE OFFERING VARIES BETWEEN THE PROSPECTUS SUPPLEMENT
AND THE BASE PROSPECTUS, YOU SHOULD RELY ON THE INFORMATION IN THE PROSPECTUS
SUPPLEMENT.

YOU SHOULD RELY ONLY ON THE INFORMATION CONTAINED IN OR INCORPORATED BY
REFERENCE IN THIS PROSPECTUS. WE HAVE NOT, AND THE UNDERWRITERS HAVE NOT,
AUTHORIZED ANYONE TO PROVIDE YOU WITH DIFFERENT INFORMATION. WE ARE NOT MAKING
AN OFFER OF THE COMMON UNITS IN ANY JURISDICTION WHERE THE OFFER IS NOT
PERMITTED. YOU SHOULD NOT ASSUME THAT THE INFORMATION CONTAINED IN THIS
PROSPECTUS OR IN THE DOCUMENTS INCORPORATED BY REFERENCE IN THIS PROSPECTUS IS
ACCURATE AS OF ANY DATE OTHER THAN THE DATE ON THE FRONT OF THOSE DOCUMENTS.

i
<PAGE> 3

SUMMARY

This summary highlights some basic information from this prospectus
supplement to help you understand our business and the common units. It likely
does not contain all the information that is important to you. You should
carefully read this prospectus supplement and the accompanying prospectus to
understand fully the offering, as well as the tax and other considerations that
are important to you in making your investment decision. You should also read
carefully the information about us that is incorporated by reference in this
prospectus. In this prospectus, the terms "EOTT," "we," "ours," and "us" refer
to EOTT Energy Partners, L.P. and its subsidiary partnerships, unless the
context requires otherwise.

THE COMPANY

We are one of the largest independent crude oil gathering and marketing
companies in North America. We gather and market from over 40,000 oil wells in
18 states and Canada, averaging 431,300 barrels per day during the second
quarter of 1999. In addition, we are engaged in interstate and intrastate crude
oil transportation, crude oil terminalling and storage activities, and crude oil
blending. Most of the crude oil we purchase directly from the oil well ("lease
crude oil") is delivered to refiners and other customers nationwide. We
transport crude oil through pipelines, including approximately 8,300 miles of
our pipeline and gathering systems, and our trucking operations, a fleet of 386
owned or leased trucks. For the three months ended June 30, 1999, our gross
margin was $55.7 million and adjusted EBITDA (as defined in note 7 on page S-8)
was $19.1 million.

Our general partner is EOTT Energy Corp., a Delaware corporation and an
indirect wholly owned subsidiary of Enron Corp. Enron is one of the world's
leading electricity, natural gas and communications companies. With over $34
billion in assets at June 30, 1999, Enron produces electricity and natural gas;
develops, constructs and operates energy facilities worldwide; delivers physical
commodities and financial and risk management services to customers around the
world; and is developing a nationwide communications network for data
transmission. Enron currently owns approximately 22% of our common units and
indirectly owns approximately 78% of our subordinated units.

We engage in the following business activities:

- GATHERING AND MARKETING. We gather, store and transport crude oil in the
United States and Canada. This involves purchasing and gathering crude
oil from producers and other sellers for subsequent sale to refiners and
other customers. We gather crude oil from over 6,000 producers and
operators, of which approximately 89% of the volumes are from independent
producers and the remaining 11% are from major integrated oil companies.
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 volumes and in obtaining new lease volumes. Most of
these operations are included in our North American Crude Oil -- East of
Rockies business segment.

- 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 and state regulatory authorities. We
transported 512,800 barrels per day in the second quarter of 1999, 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 76% of the revenues of the
Pipeline Operations business segment for the three months ended June 30,
1999, were generated from tariffs charged to our North American Crude
Oil -- East of Rockies business segment.

- CRUDE OIL BLENDING AND NATURAL GAS LIQUIDS PROCESSING. We blend West
Coast sour crude with sweet crude oil and natural gas liquids to upgrade
heavy sour crude oil into a medium gravity Alaskan North Slope type of
crude oil, which we sell to Los Angeles Basin refineries. In addition, we
have a gas processing plant, a fractionation plant, and refrigerated
propane storage and related distribution

S-1
<PAGE> 4

facilities, which provide natural gas liquids to our crude oil blending
operation. We conduct these operations in our West Coast Operations
business segment.

We operate gathering systems in all major production areas in the lower 48
states. The 18 states in which we gather have represented, on average,
approximately 97% of the production in the lower 48 states from 1985 to 1997,
according to the most recent data available from the American Petroleum
Institute. These states have had a historical average annual oil production
decline rate of 2.6% over the same period; however, this may not necessarily
represent the decline rates in the particular fields from which we gather crude
oil.

ACQUISITIONS

Since 1995 we have acquired assets from several companies. The most
significant acquisition was from Koch on December 1, 1998, which almost tripled
our pipeline mileage and nearly doubled lease crude oil barrels under contract.
The following chart provides a summary of our acquisition history:

<TABLE>
<CAPTION>
SELLER DATE OF ACQUISITION ASSETS ACQUIRED CONSIDERATION PAID
- ------ ------------------- --------------- ------------------
<S> <C> <C> <C>
Texas-New Mexico
PipeLine........ May 1, 1999 1,800 miles of common carrier $33.0 million in cash
crude oil pipelines and related
storage facilities
Koch.............. December 1, 1998 3,900 miles of crude oil $235.6 million
pipelines, crude oil transport ($184.5 million in
trucks, meter stations, cash, 2,000,000
vehicles, storage tanks and common units and
lease purchase contracts for 2,000,000
approximately 180,000 barrels subordinated units)
per day
Koch.............. July 1, 1998 300 miles of crude oil $28.5 million in cash
pipelines, associated storage
facilities for approximately
500,000 barrels and lease
purchase contracts for up to
40,000 barrels per day
CITGO............. February 1, 1997 400 miles of intrastate and $12.0 million in cash
interstate common carrier crude
oil pipelines
Amerada Hess...... December 29, 1995 614 miles of crude oil pipelines $54.0 million in cash
and related storage facilities
</TABLE>

We believe that the crude oil industry is undergoing a period of
consolidation in which major integrated oil companies and large independent
producers are combining in order to reduce costs and focus on core businesses.
As a result, we expect this consolidation trend to result in the availability of
both gathering and marketing assets and oil and gas properties. Independent
producers are likely buyers of the oil and gas properties. We believe this trend
provides us with a significant opportunity to:

- acquire additional, strategically-placed gathering assets; and

- obtain additional lease crude oil from major integrated oil companies
that have reduced or eliminated their gathering assets and from
independents who acquire oil and gas properties sold by major integrated
oil companies.

S-2
<PAGE> 5

BUSINESS STRATEGY

Our business objective is to maintain and enhance our position as a leading
independent purchaser, gatherer, transporter and marketer of crude oil in North
America, increase our cash flow and earnings and improve our results of
operations by pursuing the following strategies:

- OPTIMIZE OUR PROFITABILITY AND INCREASE THE UTILIZATION OF OUR EXISTING
ASSETS. We have reorganized our operations into eight discrete regional
business centers that will be responsible for operating our gathering and
marketing and pipeline operations as an integrated business. These
business centers will be accountable as separate profit centers and
employees will receive incentives based on performance and profitability.
The business centers are responsible for implementing the following
initiatives:

-- In Gathering: (i) review existing lease contracts to eliminate those
that are uneconomic; (ii) increase volumes on our common carrier
pipelines by, among other things, marketing excess capacity to third
parties; and (iii) expand customer services to producers and operators,
such as division order, storage and transportation services.

-- In Marketing: (i) improve our marketing systems, as well as implement
what we believe to be the first real-time inventory information system
for our industry; (ii) utilize market intelligence from our expanded
asset base to improve operating margins among transportation, storage
and delivery alternatives; and (iii) expand customer services to
refiners, such as assisting refineries in locating competitively priced
crude oil.

- REDUCE OPERATING COSTS. We have identified several operating areas where
cost savings can be achieved and are implementing the following
initiatives: (i) increase the efficiency of our trucking fleet through
the use of central dispatch and geographical routing systems that use
satellite-based global positioning technologies; (ii) reduce the cost of
our division order services by increasing the scale of operations and
improving our database system; and (iii) consolidate our existing
information systems into an integrated management, marketing and
inventory information system.

- GROW THROUGH ACQUISITIONS. As one of the largest independent gathering
and marketing companies in the lower 48 states, we believe we are well
positioned to be a leading consolidator among gathering and marketing
companies. We continually seek acquisition opportunities and regularly
examine acquisition targets. We believe that conditions in the crude oil
industry, primarily mergers among major integrated oil companies and
independent producers, will provide significant opportunities to acquire
additional assets at attractive values. We will continue to focus on
adding pipeline assets to improve our margins and the stability of our
cash flow.

Consistent with our acquisition strategy, we are engaged in discussions
with a third party relating to a possible acquisition, although we can give you
no assurance regarding whether the acquisition will be completed. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Recent Developments."

COMPETITIVE STRENGTHS

We believe that the following competitive strengths will allow us to
successfully execute our business strategy:

- LARGE AND DIVERSE ASSET BASE. Our extensive asset base allows us to
select among several transportation, storage and delivery alternatives
for the crude oil that we gather and market. Depending on market
conditions, we may ship by pipeline, truck or barge, use our own storage
facilities or select alternate delivery destinations. We believe that our
asset base gives us significant flexibility in our efforts to maximize
destination prices and minimize transportation costs.

S-3
<PAGE> 6

In addition, we are less vulnerable to supply shortages in any one
producing area or operating difficulties with any one producer.

- ESTABLISHED TRACK RECORD OF ACQUIRING AND INTEGRATING ASSETS. Since 1995,
we have made five asset acquisitions. As a result, our pipeline miles
have increased from approximately 1,700 miles in 1995 to 8,300 miles in
1999, and average lease barrels gathered per day have increased from
251,800 in 1995 to 431,300 in the second quarter of 1999. Primarily as a
result of recent acquisitions, gross margin increased to $55.7 million
from $29.2 million, and EBITDA increased to $17.1 million from $5.7
million, for the three months ended June 30, 1999 compared to the same
period in 1998.

- ENRON RELATIONSHIP. In addition to its 2% general partnership interest,
Enron owns 3,276,811 common units and indirectly owns 7,000,000
subordinated units, which represent a limited partnership interest of
approximately 37% after giving effect to the offering. Enron has
committed to provide total cash distribution support with respect to
quarters ending on or before December 31, 2001, in an amount up to an
aggregate of $29.0 million. Enron also provides us with credit support
through a $1.0 billion credit facility. We also have the ability to
consult with Enron on a variety of operational matters, such as
transportation and internal controls, and to receive from Enron
administrative support in areas such as legal and insurance.

- MANAGEMENT. Our senior management team has an average of more than 13
years of experience in the industry and an average of over nine years
with EOTT or its predecessors and affiliates. Our regional business
managers have an average of 22 years of industry experience.

S-4
<PAGE> 7

THE OFFERING

SECURITIES OFFERED......... 3,500,000 common units (4,025,000 common units if
the underwriters' over-allotment option is
exercised in full)

UNITS TO BE OUTSTANDING
AFTER THE OFFERING......... 18,476,011 common units and 9,000,000 subordinated
units. If the underwriters' over-allotment option
is exercised in full, 19,001,011 common units and
9,000,000 subordinated units will be outstanding.

CONCURRENT OFFERING........ Concurrently with this common units offering, we
are offering $235.0 million aggregate principal
amount of our senior notes to the public. The
concurrent notes offering is conditioned upon the
closing of this common units offering. This common
units offering is not conditioned upon the closing
of the concurrent notes offering.

USE OF PROCEEDS............ We intend to use the proceeds of this offering to
repay $42.0 million outstanding under the bridge
loan from Enron and a portion of the $175.0 million
term loan from Enron. If we complete the concurrent
notes offering, we will use the proceeds of both
offerings to repay the $42.0 million bridge loan
from Enron, the $175.0 million term loan from
Enron, $50.2 million of short term borrowings
outstanding under a working capital facility with
Enron and for fees and expenses and for other
general partnership purposes.

DISTRIBUTION SUPPORT....... Enron has committed to provide total cash
distribution support in exchange for additional
partnership interests 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 $29.0 million
($26.5 million of which remains available as of
August 13, 1999, the date of the latest
distribution).

DISTRIBUTIONS TO COMMON
UNITHOLDERS.............. We intend, to the extent there is sufficient
available cash, to distribute to each holder of
common units at least $0.475 per common unit per
quarter, which is the minimum quarterly
distribution, or $1.90 per common unit on a yearly
basis. Our general partner has broad discretion in
making cash disbursements and establishing
reserves. During the subordination period, which
generally will not end before September 30, 2000,
we will make the minimum quarterly distributions to
holders of common units before any distributions
will be made on the subordinated units.

TIMING OF DISTRIBUTIONS.... We make distributions approximately 45 days after
March 31, June 30, September 30 and December 31 to
unitholders on the applicable record date.

NEW YORK STOCK EXCHANGE
SYMBOL................... EOT

S-5
<PAGE> 8

OUR STRUCTURE

EOTT Energy Corp., our sole general partner and an indirect wholly owned
subsidiary of Enron Corp., manages our activities and conducts our business. The
following chart depicts our organization and our ownership structure after this
common units offering. The percentages reflected in the following chart
represent the approximate ownership interests in each of EOTT Energy Partners,
L.P. and EOTT Energy Operating Limited Partnership, individually, and not on an
aggregate basis.

[CHART]

S-6
<PAGE> 9

SUMMARY HISTORICAL FINANCIAL AND OPERATING DATA

The following summary historical financial data as of and for each of the
years in the three year period ended December 31, 1998 are derived from our
audited financial statements, which are incorporated by reference herein. The
data as of and for the three month periods ended June 30, 1999 and March 31,
1999 are derived from our unaudited financial statements, which are incorporated
by reference herein.

<TABLE>
<CAPTION>
THREE MONTHS THREE MONTHS YEAR ENDED DECEMBER 31,
ENDED ENDED ------------------------------------
JUNE 30, 1999 MARCH 31, 1999 1998(1) 1997(2) 1996
------------- -------------- ---------- ---------- ----------
(IN THOUSANDS, EXCEPT OPERATING DATA)
<S> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Revenue......................................... $2,259,303 $1,433,157 $5,294,697 $7,646,099 $7,469,730
Cost of sales................................... 2,203,606 1,380,361 5,162,092 7,533,054 7,320,203
---------- ---------- ---------- ---------- ----------
Gross margin.................................... 55,697 52,796 132,605 113,045 149,527
Operating expenses.............................. 38,632 36,183 104,425 96,158 101,945
Depreciation and amortization................... 8,350 8,140 20,951 16,518 15,720
Impairment of assets............................ -- -- -- 7,961 --
---------- ---------- ---------- ---------- ----------
Operating income (loss)......................... 8,715 8,473 7,229 (7,592) 31,862
Interest and related charges.................... (7,318) (6,502) (10,165) (6,661) (3,659)
Other income (expense), net..................... 785 563 (1,131) (146) 606
---------- ---------- ---------- ---------- ----------
Net income (loss) before cumulative effect of
accounting change............................. $ 2,182 $ 2,534 $ (4,067) $ (14,399) $ 28,809
Cumulative effect of accounting change.......... -- 1,747 -- -- --
---------- ---------- ---------- ---------- ----------
Net income (loss)............................... $ 2,182 $ 4,281 $ (4,067) $ (14,399) $ 28,809
========== ========== ========== ========== ==========
BALANCE SHEET DATA (AT END OF PERIOD):
Total assets.................................... $1,241,035 $1,101,850 $ 965,820 $ 782,921 $1,026,197
Total debt(3)................................... 357,198 359,218 328,313 109,300 62,728
Partners' capital............................... 89,805 94,856 75,582 62,093 106,173
Additional partnership interests(4)............. 2,547 -- 21,928 12,775 9,091
OTHER FINANCIAL DATA:
Capital expenditures(5)......................... 37,476 5,588 266,569 22,837 6,723
Cash distributions to Unitholders............... 7,233 6,935 22,842 29,681 28,831
EBITDA(6)....................................... 17,065 16,613 28,180 16,887 47,582
Adjusted EBITDA(7).............................. 19,134 14,532
OTHER OPERATING DATA:(8)
North American Crude Oil -- East of Rockies
Average lease volumes (mbbls/day)............. 412.2 413.6 285.6 282.4 278.6
Gross margin(9)............................... $ 19,886 $ 22,092 $ 92,071 $ 82,562 $ 117,255
EBITDA(9)..................................... $ 1,712 $ 3,966 $ 37,313 $ 27,313 $ 55,950
Storage capacity (mbbls)...................... 15,100 13,700 13,700 8,200 7,400
Gross margin per lease barrel................. $ 0.53 $ 0.59 $ 0.88 $ 0.80 $ 1.15
Pipeline Operations
Total average volumes (mbbls/day)............. 512.8 382.4 188.3 142.3 103.8
Gross margin.................................. $ 28,443 $ 23,564 $ 30,856 $ 19,539 $ 13,916
EBITDA........................................ $ 18,642 $ 15,567 $ 13,572 $ 7,851 $ 6,911
Pipeline miles................................ 8,300 6,200 6,200 2,300 1,700
Gross margin per barrel....................... $ 0.61 $ 0.68 $ 0.45 $ 0.38 $ 0.37
West Coast Operations
Total average volumes (mbbls/day)............. 105.8 120.3 128.0 120.3 107.1
Gross margin.................................. $ 7,416 $ 7,140 $ 9,698 $ 9,342 $ 15,523
EBITDA........................................ $ 2,514 $ 2,879 $ 669 $ 558 $ 7,355
</TABLE>

(see footnotes on following page)

S-7
<PAGE> 10

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

(1) Includes one month of results of operations associated with the assets
acquired from Koch on December 1, 1998.

(2) Includes non-recurring charges of (i) $6.5 million impairment of an
information system development project, (ii) $1.5 million impairment of
three Ohio products terminals held for sale and (iii) $2.0 million of
severance costs related to the exit of the East of Rockies refined products
business and corporate realignment.

(3) Consists of loans from Enron and crude oil repurchase agreements with a
financial institution.

(4) Subsequent to year-end 1998, Enron contributed the $21.9 million in
additional partnership interests to us in exchange for common units pursuant
to its commitment made in connection with the Support Agreement discussed in
note 12 to the audited consolidated financial statements incorporated by
reference herein. In May 1999, Enron provided additional common unit
distribution support related to the three months ended March 31, 1999
through the issuance by us of $2.5 million in additional partnership
interests.

(5) Includes $12.0 million in 1997 for the purchase of crude gathering and
pipeline assets from CITGO. Includes $258.1 million in 1998 for the purchase
of crude oil gathering and transportation assets from Koch. The three months
ended June 30, 1999 includes $33.0 million for the purchase of pipeline
assets from Texas-New Mexico PipeLine.

(6) EBITDA is computed as the sum of operating income and depreciation and
amortization. EBITDA is presented as a measure of our debt service ability,
and not as an alternative to (i) operating income (as determined by
generally accepted accounting principles) as an indicator of our operating
performance, or (ii) cash flows from operating activities (as determined by
generally accepted accounting principles) as a measure of liquidity. EBITDA
is not a calculation based on generally accepted accounting principles.
Investors should be cautioned that EBITDA as reported by us may not be
comparable in all instances to EBITDA as reported by other companies.

(7) Adjusted EBITDA excludes (i) the impact of non-cash mark-to-market gains for
the three months ended June 30, 1999 and March 31, 1999 of $1.0 million and
$2.1 million, respectively, and (ii) $3.1 million of cost of sales
associated with covering inventory variances, largely due to the integration
of assets from Koch, in a period of rapidly rising crude oil prices, for the
three months ended June 30, 1999.

(8) Selected financial information from our principal business segments excludes
corporate overhead.

(9) Includes intersegment transportation costs charged by our Pipeline
Operations business segment for the transport of crude oil at published
pipeline tariffs. For the three months ended June 30 and March 31, 1999,
intersegment transportation costs charged by the Pipeline Operations
business segment represented $22.2 million and $20.3 million, respectively.
For 1998, 1997 and 1996, intersegment transportation costs charged by the
Pipeline Operations business segment represented $24.5 million, $13.7
million and $10.2 million, respectively.

S-8
<PAGE> 11

RISK FACTORS

You should carefully consider the following factors and the other
information set forth or incorporated by reference in this prospectus supplement
and the accompanying prospectus before deciding to purchase any common units.

- ECONOMIC AND INDUSTRY FACTORS BEYOND OUR CONTROL, INCLUDING PRODUCTION
LEVELS OF CRUDE OIL, CAN ADVERSELY AFFECT OUR GROSS MARGIN.

Our ability to pay cash distributions and service our debt obligations
depends primarily on our gross margin, which is the difference between the sales
price of crude oil and the cost of crude oil purchased, including costs paid to
third parties for transportation and handling charges. Historically, our
business has been very competitive with thin and volatile profit margins. Our
gross margin is affected by many factors beyond our control, including:

- 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; and

- 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.

The absolute price levels for crude oil do not necessarily bear a direct
relationship to our gross margins per barrel, and our gross margins per barrel
cannot be projected with any level of certainty. Due to the volatility of crude
oil prices and the decline in crude oil production, crude oil gathering margins
have suffered industry wide over the last few years. Although there has been a
general improvement in crude oil margins since 1997, margins have not returned
to historical levels.

- 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.

Our profitability depends in part on our ability to offset volumes lost
because of natural declines in crude oil production from depleting wells or
volumes lost to competitors. This is particularly difficult in an environment of
reduced drilling activity and discontinued production operations. The amount of
drilling and production will depend in large part on crude oil prices. To the
extent that low crude oil prices result in lower volumes of lease crude oil
available for purchase, we may experience lower per barrel margins, as
competition for available lease crude oil on the basis of price intensifies. It
is possible that domestic crude oil producers may further reduce or discontinue
drilling and production operations. In addition, a sustained depression in crude
oil prices could result in the bankruptcy of some producers.

Because producers experience inconveniences in switching lease crude oil
purchasers, producers typically do not change purchasers on the basis of minor
variations in price. Thus, we may experience difficulty acquiring lease crude
oil in areas where there are existing relationships between producers and other
gatherers and purchasers of crude oil. Furthermore, we cannot assure you that we
will be successful in obtaining production made available by major oil companies
or that we will be successful in acquiring other gatherers or marketers.

S-9
<PAGE> 12

- CASH DISTRIBUTIONS TO OUR UNITHOLDERS ARE NOT GUARANTEED AND MAY
FLUCTUATE; ENRON'S COMMITMENT TO SUPPORT CASH DISTRIBUTIONS ON COMMON
UNITS WILL EXPIRE AFTER 2001; IF WE COMPLETE THE CONCURRENT NOTES
OFFERING, WE WILL BE BOUND BY COVENANTS THAT COULD RESTRICT
DISTRIBUTIONS.

Our cash distributions are not guaranteed and may fluctuate with our
performance. Enron has a commitment to contribute to us up to $29 million ($26.5
million of which is available) if necessary to support our ability to pay the
minimum quarterly distribution of $0.475 per unit ($1.90 annualized). In
addition to the current commitment, Enron has previously contributed $21.9
million to help us pay the minimum quarterly distribution. However, Enron's
commitment to support the minimum quarterly distribution extends only to
quarters through December 31, 2001. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Liquidity and Capital
Resources" for a discussion of covenants that could restrict payments of
distributions.

See "Risk Factors" beginning on page 2 of the accompanying prospectus for a
more detailed discussion of these and other factors that you should consider
before deciding to purchase any common units.

TAX CONSIDERATIONS

We estimate that if you purchase a common unit in this offering and own the
unit through the record date for the distribution for the quarter ending June
30, 2002 (assuming the minimum quarterly distribution is made for each quarter
or portion thereof during that period), then you will be allocated, on a
cumulative basis, an amount of federal taxable income for that period which will
be approximately 20% of the amount of cash distributed to you with respect to
that period.

These estimates are based upon numerous assumptions regarding our business
and operations, including assumptions as to tariffs, capital expenditures, cash
flows and anticipated cash distributions. These estimates and assumptions are
subject to, among other things, numerous business, economic, regulatory and
competitive uncertainties beyond our control and to certain tax reporting
positions that we have adopted or intend to adopt and with which the Internal
Revenue Service could disagree. Accordingly, we cannot assure you that the
estimates will be correct. The actual percentage of distributions that will
constitute taxable income could be higher or lower, and any differences could be
material.

S-10
<PAGE> 13

USE OF PROCEEDS

We intend to use the net proceeds from the offering of approximately $52.9
million to repay $42.0 million outstanding under the bridge loan from Enron and
to repay a portion of the term loan from Enron. If the underwriters exercise
their over-allotment option in full, we intend to use the additional net
proceeds of approximately $7.9 million to repay an additional portion of the
term loan from Enron.

Concurrently with this offering, we are offering $235.0 million aggregate
principal amount of notes to the public. If we complete the notes offering, we
will use the proceeds of both offerings to repay the $42.0 million bridge loan
from Enron, the $175.0 million term loan from Enron, and $50.2 million
outstanding under a working capital facility from Enron, and for fees and
expenses and general partnership purposes. The bridge loan bears interest at the
London Interbank Offering Rate (LIBOR) plus 4.00% increasing every three months
by 0.25% (9.29% for the month ended June 30, 1999), and matures on December 31,
1999. The term loan bears interest at LIBOR plus 3.00% (8.04% for the month
ended June 30, 1999), and matures on December 31, 1999. The working capital
facility bears interest at LIBOR plus 2.50% (7.54% for the month ended June 30,
1999) and matures on December 31, 2001. If we are not able to complete the notes
offering, we will seek other sources of financing to repay or refinance the
remainder of the term loan prior to its maturity.

Substantially all of the debt outstanding under the bridge and term loans
was incurred to fund the acquisitions of the Koch and Texas-New Mexico PipeLine
assets.

The following table illustrates the estimated sources and uses of funds
assuming consummation of both the notes offering and the common unit offering as
of June 30, 1999.

<TABLE>
<CAPTION>
AMOUNT
--------------
(IN THOUSANDS)
<S> <C>
SOURCES:
Notes offering.............................................. $235,000
Common units offering(1).................................... 56,000
--------
Total............................................. $291,000
========
USES:
Repayment of term loan from Enron........................... $175,000
Repayment of bridge loan from Enron......................... 42,000
Repayment of short-term borrowings from Enron............... 50,200
General partnership purposes................................ 13,906
Fees and expenses........................................... 9,894
--------
Total............................................. $291,000
========
</TABLE>

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

(1) Reflects an offering of 3,500,000 common units at $16.00 per unit.

S-11
<PAGE> 14

CAPITALIZATION

The following table sets forth our capitalization on June 30, 1999, and as
adjusted to give effect to (i) the sale of the common units in this offering and
the application of the net proceeds from the sale of the common units, and (ii)
the sale of the common units in this offering and the notes in the concurrent
notes offering and the application of the net proceeds from the sale of the
common units and the notes. See "Use of Proceeds." You should read our
historical financial statements and notes that are incorporated by reference in
this prospectus supplement for additional information about our capital
structure.

<TABLE>
<CAPTION>
JUNE 30, 1999
-----------------------------------------------
ADJUSTED FOR THE ADJUSTED FOR THE
COMMON UNIT COMMON UNIT AND
ACTUAL OFFERING(1) NOTE OFFERINGS
-------- ---------------- ----------------
(IN THOUSANDS)
<S> <C> <C> <C>
Short-term debt:
Term loan from Enron.............................. $175,000 $164,080 $ --
Bridge loan from Enron............................ 42,000 -- --
Short-term borrowings from Enron.................. 50,200 50,200 --
Repurchase agreements............................. 89,998 89,998 89,998
-------- -------- --------
Total short-term debt..................... $357,198 $304,278 $ 89,998
======== ======== ========
Long-term debt...................................... -- -- 235,000
Additional partnership interests.................... 2,547 2,547 2,547
Partners' capital
Common unitholders................................ 41,123 94,043 94,043
Subordinated unitholders.......................... 41,064 41,064 41,064
General partner(2)................................ 7,618 8,153 8,153
-------- -------- --------
Total partners' capital................... $ 89,805 $143,260 $143,260
======== ======== ========
</TABLE>

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

(1) Reflects an offering of 3,500,000 common units at $16.00 per unit, net of a
5.50% underwriting discount.

(2) The adjustment includes a contribution by our general partner in an amount
equal to approximately 1% of the net proceeds from the common unit offering.

S-12
<PAGE> 15

PRICE RANGE OF COMMON UNITS AND DISTRIBUTIONS

As of September 23, 1999, there were 14,976,011 common units outstanding,
held by approximately 9,100 holders, including common units held in street name.
The common units are traded on the NYSE under the symbol "EOT." As of September
23, 1999, there were 9,000,000 subordinated units outstanding held by two
beneficial holders. The subordinated units are not publicly traded. The
following table sets forth, for the periods indicated, the high and low sales
prices for the common units, as reported on the NYSE Composite Transactions
Tape, and quarterly declared distributions thereon.

<TABLE>
<CAPTION>
PRICE RANGE CASH
----------------- DISTRIBUTIONS
HIGH LOW PER COMMON UNIT(1)
------- ------- ------------------
<S> <C> <C> <C>
1997
First Quarter................................... $22.375 $19.750 $0.475
Second Quarter.................................. 21.625 18.375 0.475
Third Quarter................................... 20.000 17.125 0.475
Fourth Quarter.................................. 20.625 14.750 0.475
1998
First Quarter................................... $19.188 $17.250 $0.475
Second Quarter.................................. 18.125 14.375 0.475
Third Quarter................................... 17.000 11.250 0.475
Fourth Quarter.................................. 20.000 15.500 0.475
1999
First Quarter................................... $17.500 $15.375 $0.475
Second Quarter.................................. 18.750 17.000 0.475
Third Quarter (through September 23, 1999)...... 19.250 15.313
</TABLE>

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

(1) Distributions are shown in the quarter paid to common unitholders. We intend
to continue to pay regular quarterly distributions to common unitholders on
the applicable record date within 45 days after the end of each calendar
quarter. However, we cannot assure you that future distributions will
continue at such levels. Future distributions will be at the discretion of
our general partner and will depend on actual cash available for
distribution.

The last reported sale price of common units on the NYSE on September 23,
1999, was $16.00 per common unit.

S-13
<PAGE> 16

SELECTED HISTORICAL FINANCIAL DATA

The following selected historical financial data as of and for each of the
years in the three year period ended December 31, 1998 are derived from our
audited financial statements, which are incorporated by reference herein. The
data as of and for the six month periods ended June 30, 1999 and June 30, 1998
are derived from our unaudited financial statements, which are incorporated by
reference herein.

<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE 30, YEAR ENDED DECEMBER 31,
------------------------- ------------------------------------
1999 1998 1998(1) 1997(2) 1996
----------- ----------- ---------- ---------- ----------
(IN THOUSANDS, EXCEPT PER UNIT DATA)
<S> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Revenue.......................... $3,692,460 $2,571,279 $5,294,697 $7,646,099 $7,469,730
Cost of sales.................... 3,583,967 2,514,576 5,162,092 7,533,054 7,320,203
---------- ---------- ---------- ---------- ----------
Gross margin..................... 108,493 56,703 132,605 113,045 149,527
Operating expenses............... 74,815 46,825 104,425 96,158 101,945
Depreciation and amortization.... 16,490 9,078 20,951 16,518 15,720
Impairment of assets............. -- -- -- 7,961 --
---------- ---------- ---------- ---------- ----------
Operating income (loss).......... 17,188 800 7,229 (7,592) 31,862
Interest and related charges..... (13,820) (3,823) (10,165) (6,661) (3,659)
Other income (expense), net...... 1,348 26 (1,131) (146) 606
---------- ---------- ---------- ---------- ----------
Net income (loss) before
cumulative effect of accounting
change......................... $ 4,716 $ (2,997) $ (4,067) $ (14,399) $ 28,809
========== ========== ========== ========== ==========
Net income (loss)................ $ 6,463 $ (2,997) $ (4,067) $ (14,399) $ 28,809
========== ========== ========== ========== ==========
Basic net income (loss) per unit
before cumulative effect of
accounting change:
- Common....................... $ 0.17 $ (0.15) $ (0.17) $ (0.75) $ 1.50
========== ========== ========== ========== ==========
- Subordinated................. $ 0.24 $ (0.16) $ (0.26) $ (0.75) $ 1.50
========== ========== ========== ========== ==========
Diluted net income (loss) per
unit before cumulative effect
of accounting change........... $ 0.19 $ (0.16) $ (0.21) $ (0.75) $ 1.50
========== ========== ========== ========== ==========
Cash distributions per common
unit........................... $ 0.95 $ 0.95 $ 1.90 $ 1.90 $ 1.90
========== ========== ========== ========== ==========
BALANCE SHEET DATA (AT END OF
PERIOD):
Total assets..................... $1,241,035 $ 684,547 $ 965,820 $ 782,921 $1,026,197
Total debt(3).................... 357,198 157,440 328,313 109,300 62,728
Partners' capital................ 89,805 47,696 75,582 62,093 106,173
Additional partnership
interests(4)................... 2,547 19,452 21,928 12,775 9,091
OTHER FINANCIAL DATA:
Capital expenditures(5).......... 43,064 3,268 266,569 22,837 6,723
Cash distributions to
unitholders.................... 14,168 11,400 22,842 29,681 28,831
</TABLE>

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

(1) Includes one month of results of operations associated with the assets
acquired from Koch on December 1, 1998.

(3) Consists of loans from Enron and crude oil repurchase agreements with a
financial institution.
(footnotes continued on following page)

S-14
<PAGE> 17

(5) Includes $12.0 million in 1997 for the purchase of crude gathering and
pipeline assets from CITGO. Includes $258.1 million in 1998 for the purchase
of crude oil gathering and transportation assets from Koch. The six months
ended June 30, 1999 includes $33.0 million for the purchase of pipeline
assets from Texas-New Mexico PipeLine.

S-15
<PAGE> 18

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

The following discussion of our financial condition and results of
operations should be read in conjunction with the audited consolidated financial
statements and notes thereto and the unaudited condensed consolidated financial
statements and notes thereto, incorporated herein by reference.

OVERVIEW

Through our affiliated limited partnerships, EOTT Energy Operating Limited
Partnership, EOTT Energy Canada Limited Partnership, and EOTT Energy Pipeline
Limited Partnership, we purchase, gather, transport, store and resell crude oil
and other petroleum products. Statement of Financial Accounting Standards No.
131, "Reporting Disaggregated Information About a Business Enterprise," requires
that segment reporting for public companies be measured the same way management
identifies and evaluates information internally. We adopted this standard for
year end 1998 reporting and restated certain information into the following
business segments: North American Crude Oil -- East of Rockies, Pipeline
Operations and West Coast Operations (see note 19 to our audited consolidated
financial statements for certain financial information by business segment). In
late 1997, we decided to exit the East of Rockies refined products business. See
further discussion in note 5 to our audited consolidated financial statements.

Gathering and Marketing Operations

In general, as we purchase crude oil in our gathering and marketing
operations, 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 a future delivery obligation 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.
As a result, changes in the absolute price level for crude oil do not
necessarily impact the margin from gathering and marketing.

Although we generally maintain a balanced position in terms of overall
volumes, some risks cannot be fully hedged, such as a portion of certain basis
risks. Basis risk arises when we acquire crude oil by 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.
We seek to limit our price risk and maintain our margins through a combination
of physical sales, NYMEX hedging activities and exchanges of crude oil with
third parties. It is our policy not to acquire and hold crude oil, futures
contracts or other derivative products for the purpose of speculating on crude
oil price changes.

Our operating results are sensitive to a number of factors including:
grades or 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.

Gross margin from gathering, marketing and pipeline 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 margin 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. In addition to purchasing crude oil at
the wellhead, 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 volumes
and narrow profit margins on purchase and sales transactions, and the absolute
price levels for crude oil do not necessarily bear a relationship to gross
margin, 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 margin for gathering
and marketing operations such changes are not addressed in the following
discussion.

S-16
<PAGE> 19

We operate our 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 margins 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. A majority of the pipeline revenues are generated by transporting
crude oil at published pipeline tariffs for the North American Crude Oil -- East
of Rockies business segment. Approximately 76% of the revenues of the Pipeline
Operations business segment for the three months ended June 30, 1999, were
generated from tariffs charged to the North American Crude Oil -- East of
Rockies business segment. Changes in revenues and pipeline operating costs,
therefore, are relevant to the analysis of financial results of our Pipeline
Operations business segment and are addressed in the following discussions of
our Pipeline Operations business segment.

RECENT DEVELOPMENTS

On May 1, 1999, we acquired crude oil transportation and storage assets in
key oil producing regions from Texas-New Mexico PipeLine Co. which included
approximately 1,800 miles of common carrier crude oil pipelines. We paid $33.0
million in cash and financed the acquisition using short-term borrowings from
Enron.

On December 1, 1998, we purchased crude oil gathering and transportation
assets in key oil producing regions from Koch. The transaction almost tripled
our pipeline mileage and nearly doubled crude oil lease barrels under contract.
The acquisition included approximately 3,900 miles of crude oil pipelines, crude
oil transport trucks, meter stations, vehicles, storage tanks and contracts for
approximately 180,000 lease barrels of crude oil per day from production in 11
central and western states including Texas, Oklahoma, Kansas and California. The
total purchase price was approximately $235.6 million and included consideration
given to Koch of $184.5 million in cash, 2,000,000 common units and 2,000,000
subordinated units. We financed the cash portion of the purchase price through
borrowings from Enron consisting of a $42.0 million bridge loan due December 31,
1999, a $135.7 million term loan due December 31, 1999, and $6.8 million from
our working capital facility with Enron. We also increased our existing credit
facility with Enron to $1.0 billion in order to provide additional working
capital for our expanded operations.

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 10,000,000 common units, (b) changed
the terms of the special units held by Enron so that they became convertible
into common units and (c) resulted in an increase in Enron's cash distribution
support to $29.0 million and an extension of that support through the fourth
quarter of 2001. As a result of the approval of the proposals, Enron contributed
the $21.9 million in additional partnership interests to us in exchange for
common units outstanding as discussed in note 12 to the audited consolidated
financial statements.

Consistent with our acquisition strategy, we are engaged in discussions
with a third party relating to a possible acquisition of contracts and
transportation assets, including trucks, crude oil pipelines and storage
facilities. We have entered into a confidentiality agreement that provides that
the owner of the assets will furnish us with confidential information for use in
our evaluation of the assets. We have the exclusive right to discuss this
possible purchase of the assets with the owner until November 1, 1999, or until
an earlier date on which one of the parties gives written notice to the other
that negotiations between the parties have terminated. We do not expect to
discuss a definitive agreement on the terms of the acquisition until such time
as the due diligence process is completed and we have fully evaluated the
results of our due diligence review.

S-17
<PAGE> 20

We have indicated to the potential seller that we believe that the acquisition
price for the assets would be in the range of $210 million to $240 million, but
we have not reached any agreement regarding the price for the assets or any
other terms of the transaction. If an agreement is reached regarding this
acquisition, we may finance the purchase price through the issuance of
additional common units, the issuance of public or private debt securities or
loans or some combination of the foregoing. We can give you no assurance
regarding when or whether we will reach agreement with the owner on the terms of
the acquisition or that, if we do reach agreement, the acquisition will be
completed.

RESULTS OF OPERATIONS

We reported net income of $6.5 million or $0.26 per diluted unit for the
six months ended June 30, 1999 compared to a net loss of $3.0 million or $0.16
per diluted unit for the six months ended June 30, 1998. The six months ended
June 30, 1999 reflect increased lease volumes and margins associated with the
1998 and 1999 asset acquisitions and the adoption of the conclusions reached by
the Emerging Issues Task Force in Issue No. 98-10 ("Issue 98-10"), "Accounting
for Contracts Involved in Energy Trading and Risk Management Activities." Issue
98-10 requires energy trading contracts (as defined) to be recorded at fair
value on the balance sheet, with the change in fair value included in earnings.
The cumulative effect of adoption of Issue 98-10 in the first quarter of 1999
included a $1.7 million increase in net income as of January 1, 1999. We had
$3.1 million of net unrealized mark-to-market gains for the six months ended
June 30, 1999.

We reported a net loss of $4.1 million or $0.21 per diluted unit for 1998,
a net loss of $14.4 million or $0.75 per diluted unit for 1997, and net income
of $28.8 million or $1.50 per diluted unit for 1996. We reported a net loss of
$4.4 million or $0.23 per diluted unit in 1997 excluding non-recurring charges
of $10.0 million or $0.52 per unit, which consisted primarily of a $6.5 million
impairment of an information systems development project, a $1.5 million
impairment of three Ohio products terminals held for sale and a $2.0 million
severance charge associated with the realignment initiatives discussed further
in the notes to the audited consolidated financial statements.

S-18
<PAGE> 21

Selected financial data for our business segments are summarized below:

<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30, YEAR ENDED DECEMBER 31,
------------------- ------------------------------
1999 1998 1998 1997 1996
-------- -------- -------- -------- --------
(IN MILLIONS)
<S> <C> <C> <C> <C> <C>
Revenues:
North American Crude Oil -- East of
Rockies............................... $3,454.3 $2,123.0 $4,637.8 $6,072.6 $6,029.0
Pipeline Operations...................... 52.6 10.1 31.5 19.4 14.3
West Coast Operations.................... 273.8 355.0 590.1 811.2 770.9
Corporate and Other(1)................... -- 110.6 110.7 760.2 668.6
Intersegment eliminations................ (88.2) (27.4) (75.4) (17.3) (13.1)
-------- -------- -------- -------- --------
Total............................ $3,692.5 $2,571.3 $5,294.7 $7,646.1 $7,469.7
======== ======== ======== ======== ========
Gross margin:
North American Crude Oil -- East of
Rockies (2)........................... $ 42.0 $ 41.8 $ 92.0 $ 82.6 $ 117.2
Pipeline Operations...................... 52.0 9.9 30.9 19.5 13.9
West Coast Operations.................... 14.5 5.0 9.7 9.3 15.5
Corporate and Other(1)................... -- -- -- 1.6 2.9
-------- -------- -------- -------- --------
Total............................ $ 108.5 $ 56.7 $ 132.6 $ 113.0 $ 149.5
======== ======== ======== ======== ========
Operating Income (Loss):
North American Crude Oil -- East of
Rockies (2)........................... $ 1.0 $ 11.5 $ 28.0 $ 19.5 $ 47.1
Pipeline Operations...................... 24.3 0.8 4.3 1.8 1.8
West Coast Operations.................... 4.4 0.4 0.2 0.1 6.8
Corporate and Other(1)................... (12.5) (11.9) (25.3) (29.0) (23.8)
-------- -------- -------- -------- --------
Total............................ $ 17.2 $ 0.8 $ 7.2 $ (7.6) $ 31.9
======== ======== ======== ======== ========
</TABLE>

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

(1) Includes East of Rockies refined products business in 1998, 1997 and 1996,
which we have now exited.

(2) Includes intersegment transportation costs charged by the Pipeline
Operations business segment for the transport of crude oil at published
pipeline tariffs. For the six months ended June 30, 1999 and 1998,
intersegment transportation costs charged by the Pipeline Operations
business segment represented $42.5 million and $6.8 million, respectively.
For 1998, 1997 and 1996, intersegment transportation costs charged by the
Pipeline Operations business segment represented $24.5 million, $13.7
million and $10.2 million, respectively.

Six Months Ended June 30, 1999 Compared with Six Months Ended June 30, 1998

North American Crude Oil -- East of Rockies. Operating income for the North
American Crude Oil -- East of Rockies business segment was $1.0 million for the
first half of 1999, compared to $11.5 million for the same period in 1998. As a
result of the acquisition of assets from Koch, the North American Crude Oil --
East of Rockies business segment is incurring increased transportation costs
charged by the Pipeline Operations business segment due to the significant
increase in the volume of crude oil transported at higher published tariff rates
as well as incurring additional operating costs associated with the asset
acquisitions. Gross margin increased approximately $200,000 to $42.0 million in
the first half of 1999 due primarily to increased margins related to the asset
acquisitions in the second half of 1998 and approximately $2.7 million of
unrealized mark-to-market gains being recorded in the first half of 1999 for
certain energy contracts. These increases were offset by the increase in
transportation costs charged by the Pipeline Operations business segment and by
approximately $3.1 million of higher cost of sales associated with covering
inventory variances in a period of rapidly rising crude oil prices. The
inventory variances, which are a result of actual lease volumes being less than
expected lease volumes, were largely due to the integration of the $235.6
million acquisition of

S-19
<PAGE> 22

assets from Koch, which nearly doubled the amount of lease barrels under
contract. Crude oil lease volumes increased significantly from an average of
270,200 barrels per day for the six months ended June 30, 1998 to an average of
412,900 barrels per day for the six months ended June 30, 1999 due to the
acquisitions of assets from Koch. Operating expenses of $41.0 million for the
first half of 1999 were $10.7 million higher than for the first half of 1998 due
primarily to higher operating costs and employee related costs associated with
the acquisitions of assets from Koch in December 1998.

Pipeline Operations. Pipeline Operations had operating income of $24.3
million for the first half of 1999 compared to operating income of approximately
$800,000 for the same period in 1998. Revenues, which include only two months of
activity related to the assets acquired from Texas-New Mexico PipeLine Co. in
1999, increased $42.5 million to $52.6 million in the first half of 1999 due
primarily to increased activity related to the pipelines acquired from Koch and
Texas-New Mexico PipeLine Co. Approximately $42.5 million and $6.8 million of
revenues for the six months ended June 30, 1999 and 1998, respectively, were
generated from tariffs charged to the North American Crude Oil -- East of
Rockies business segment. Pipeline volumes averaged 448,000 barrels per day for
the six months ended June 30, 1999 compared to 152,100 barrels per day for the
six months ended June 30, 1998. Operating expenses of $27.7 million for the
first half of 1999 were $18.6 million higher than in the first half of 1998 due
to higher employee related costs, operating costs and depreciation associated
with the acquisitions of assets from Koch and Texas-New Mexico PipeLine Co.

West Coast Operations. West Coast Operations had operating income of $4.4
million for the first half of 1999, compared to approximately $400,000 for the
same period in 1998 primarily due to increased margins associated with the crude
oil blending operations acquired from Koch and increased margins in refined
products marketing due to disruptions in supply and demand due to refinery
outages. Operating expenses of $10.1 million for the first half of 1999 were
$5.5 million higher than for the same period in 1998 due to higher employee
related costs, operating costs and depreciation associated with the acquisitions
of assets from Koch.

Corporate and Other. Corporate and Other costs were $12.5 million for the
first half of 1999 compared to $11.9 million in the first half of 1998. The
increase is due primarily to higher system operating costs and insurance costs
partially offset by lower severance costs. Other income (expense), net,
consisting primarily of gains (losses) on transactions denominated in foreign
currency and gains on sales of fixed assets, increased $1.3 million to income of
$1.0 million in the first half of 1999 compared to a loss of approximately
$300,000 in the same period in 1998 primarily due to gains on foreign currency
transactions and gains on sales of fixed assets. Interest and related charges in
the first half of 1999 were $13.8 million compared to $3.8 million for the same
period in 1998. The increase is due to higher average short-term debt in 1999
due to the financing of the acquisitions of assets from Koch and Texas-New
Mexico PipeLine Co.

Twelve Months Ended December 31, 1998 Compared with Twelve Months Ended
December 31, 1997

North American Crude Oil -- East of Rockies. Operating income for the North
American Crude Oil -- East of Rockies business segment was $28.0 million in 1998
compared to $19.5 million in 1997. Gross margin increased $9.4 million to $92.0
million due primarily to renegotiations of uneconomic lease contracts during
1997 and improved crude grade and basis differentials in 1998. North American
Crude Oil -- East of Rockies crude oil lease purchases were up slightly from an
annual average of 282,400 barrels per day for 1997 to an annual average of
285,600 barrels per day in 1998. Operating expenses of $64.0 million for 1998
were approximately $900,000 higher than 1997 due primarily to increased
depreciation and amortization related to the acquisitions of assets from Koch
partially offset by a reduction in employee related costs.

Pipeline Operations. Pipeline Operations had operating income of $4.3
million in 1998 compared to $1.8 million in 1997. Gross margin increased $11.4
million to $30.9 million due primarily to increased activity related to the
acquisition of pipelines from Koch. Pipeline volumes averaged 188,300 barrels
per day in 1998 compared to 142,300 barrels per day in 1997. Operating expenses
of $26.6 million in 1998 were $8.9 million higher than 1997 due primarily to
increased benefits and employee related costs, increased operating costs and
incremental depreciation and amortization associated with the acquisition of
pipelines from Koch.

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<PAGE> 23

West Coast Operations. West Coast Operations had operating income of
approximately $200,000 in 1998 compared to approximately $100,000 in 1997. Gross
margin increased approximately $400,000 to $9.7 million due primarily to the
acquisition of crude oil gathering and natural gas liquid assets from Koch
partially offset by a lower of cost or market adjustment of certain propane
inventories. Operating expenses of $9.5 million in 1998 were approximately
$300,000 higher than 1997 due primarily to higher benefits and other employee
related costs partially offset by reduced operating costs.

Corporate and Other. Corporate and other costs of $25.3 million for 1998
were $3.7 million lower compared to 1997 due primarily to a non-recurring $6.5
million non-cash impairment associated with the termination of an information
system development project and $1.5 million impairment of three Ohio products
terminals held for sale due to the decision in 1997 to exit the East of Rockies
refined products business partially offset by increased legal expenses, system
operating costs, casualty and liability insurance costs, a non-recurring
write-off of certain information system development costs and severance payments
made to a former officer of ours. Interest and related charges for 1998 were
$10.2 million compared to $6.7 million in 1997. The increase is due primarily to
higher average short-term debt required to meet working capital needs, primarily
related to higher crude inventories and debt used to finance the acquisition of
assets from Koch in the third and fourth quarters of 1998. Other income
(expense), net, consisting primarily of gains (losses) on transactions
denominated in foreign currency; gains (losses) on the sale of property, plant
and equipment; and litigation settlements, decreased $1.0 million to a loss of
$1.8 million in 1998 due to an increase in litigation settlements in 1998.

Twelve Months Ended December 31, 1997 Compared with Twelve Months Ended
December 31, 1996.

North American Crude Oil -- East of Rockies. Operating income for the North
American Crude Oil -- East of Rockies business segment was $19.5 million in 1997
compared to $47.1 million in 1996. Gross margin decreased $34.7 million to $82.6
million due primarily to the deterioration in grade and basis differentials in
1997 and 1996 had unusually favorable crude oil market conditions. North
American Crude Oil -- East of Rockies crude lease purchases were up slightly
from an annual average of 278,600 barrels per day for 1996 to an annual average
of 282,400 barrels per day in 1997. Operating expenses of $63.1 million for 1997
were $7.0 million lower than 1996 due to lower benefits and other employee
related costs, partially offset by severance costs associated with the
realignment initiatives discussed in the notes to our consolidated financial
statements.

Pipeline Operations. Pipeline Operations had operating income of $1.8
million in 1997 and in 1996. Gross margin increased $5.6 million to $19.5
million due primarily to increased activity related to the acquisition of
pipeline and related assets from CITGO. Pipeline volumes averaged 142,300
barrels per day in 1997 compared to 103,800 barrels per day in 1996. Operating
expenses of $17.7 million in 1997 were $5.6 million higher than 1996 due
primarily to increased operating costs and incremental depreciation and
amortization associated with the acquisition of pipeline and related assets from
CITGO.

West Coast Operations. West Coast Operations had operating income of
$100,000 in 1997 compared to $6.8 million in 1996. Gross margin decreased $6.2
million to $9.3 million due primarily to unusually favorable market conditions
in 1996. Operating expenses of $9.2 million in 1997 were approximately $500,000
higher than 1996 due primarily to higher operating costs partially offset by
lower benefits and other employee related costs.

Corporate and Other. Corporate and other costs of $29.0 million for 1997
were $5.2 million higher compared to 1996 due primarily to a $6.5 million
non-cash impairment associated with the termination of an information system
development project and a $1.5 million impairment of the Ohio terminals due to
the exit of the East of Rockies refined products business in 1997 partially
offset by lower benefits and other employee related costs, lower liability and
casualty insurance costs, lower systems operating costs and severance charges
associated with the realignment initiatives and the exiting of the East of
Rockies refined products business discussed further in the notes to our
consolidated financial statements. Interest and related charges for 1997 were
$6.7 million compared to $3.7 million in 1996. The increase is due primarily to
higher average short-term debt required to meet working capital needs, primarily
related to higher crude inventories and debt used to

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<PAGE> 24

finance the acquisition of crude oil pipeline assets from CITGO in the first
quarter of 1997. Other income (expense), net, consisting primarily of gains
(losses) on transactions denominated in foreign currency; gains (losses) on the
sale of property, plant and equipment; and litigation settlements, decreased
approximately $900,000 to a loss of approximately $800,000 in 1997 due primarily
to losses on foreign currency transactions.

LIQUIDITY AND CAPITAL RESOURCES

General

Management anticipates that short-term liquidity as well as sustaining
capital expenditures for the foreseeable future will be funded primarily by cash
generated from operations and, when necessary, accessing the $100.0 million
working capital line under the $1.0 billion Enron credit facility, described
below. To the extent we make future significant acquisitions, we may be required
to seek financing from other sources. No assurance can be given that this
financing will be available from Enron or another source.

Cash Flows From Operating Activities

Net cash provided by operating activities totaled $26.2 million for the
first half of 1999 compared to net cash used in operating activities of $41.1
million for the same period in 1998 primarily due to improved operating results
associated with acquisitions from Koch and Texas-New Mexico PipeLine Co.

Cash Flows From Investing Activities

Net cash used in investing activities totaled $42.5 million for the first
half of 1999 compared to $2.6 million used during the same period in 1998. Cash
additions to property, plant, and equipment and acquisitions of $43.1 million in
1999 primarily include $33.0 million representing cash consideration for the
asset acquisition from Texas-New Mexico PipeLine Co., $5.4 million for other
pipeline connections and improvements, and $1.1 million for information systems
development. Proceeds from asset sales were $548,000 in the first half of 1999
compared to $640,000 in the first half of 1998. We estimate that capital
expenditures necessary to maintain the existing asset base at current operating
levels will be $10.0 to $11.0 million each year.

Cash Flows From Financing Activities

Net cash provided by financing activities totaled $17.0 million for the
first half of 1999 compared to net cash provided of $43.1 million for the same
period in 1998. The 1999 amount primarily represents increases in short-term
borrowings for working capital needs and acquisition financing offset by
distributions paid to all common and special unitholders for the period October
1, 1998 through March 31, 1999.

Working Capital and Credit Resources

In 1995, Enron Corp. entered into a credit facility with us to provide
credit support in the form of guarantees, letters of credit, loans and letters
of indemnity. The total amount of the credit support was $600.0 million, and as
amended December 19, 1996, had a maturity of March 31, 1999.

On December 1, 1998, Enron increased its existing credit facility with us
to provide additional credit support in the form of guarantees, letters of
credit and working capital loans through December 31, 2001. The total amount of
the new credit facility is $1.0 billion and contains sublimits on the
availability of credit support of $100.0 million for working capital loans and
$900.0 million for guarantees and letters of credit. As of June 30, 1999, $50.2
million was outstanding under the $100.0 million working capital facility and
$379.4 million of letters of credit and guarantees were outstanding. Letter of
credit fees are based on actual charges by the banks which range from
0.20%-0.375% per annum. Interest on outstanding loans is charged at LIBOR plus
2.50% per annum.

The Enron credit facility is subject to defined borrowing base limitations
relating to our activities and to the maintenance and protection of the
collateral. The credit facility permits distributions to unitholders subject

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<PAGE> 25

to certain limitations based on our earnings and other factors. These covenants
and restrictions are not expected to materially affect our ability to operate
the ongoing partnership business.

At June 30, 1999, we had $175.0 million of debt outstanding under a term
loan with Enron, which was used to fund a portion of the cash consideration paid
to Koch for the assets purchased in 1998 and to refinance indebtedness incurred
in prior acquisitions. The term loan matures on December 31, 1999. The interest
rate on the term loan is LIBOR plus 3.00%.

The Enron credit facility and the term loan are secured by a first priority
lien on and security interest in all of our receivables and inventory. The
borrowing base is the sum of cash and cash equivalents, specified percentages of
eligible receivables, inventory, and products contracted for or delivered but
not billed. The credit facility and the term loan are non-recourse to our
general partner and its assets. We are restricted from entering into additional
financing arrangements without the prior approval of Enron.

In addition, at June 30, 1999, we had $42.0 million of debt outstanding
with Enron under a $100.0 million bridge loan to finance the acquisition of
assets from Koch. The interest rate on the bridge loan is initially LIBOR plus
4.00%. At the end of each three-month period, the spread on the bridge loan will
increase by 0.25%. The bridge loan is unsecured and matures on December 31,
1999.

Our partnership agreement authorizes us to issue additional limited partner
interests, the proceeds from which could be used to provide additional funds for
acquisitions or other partnership needs. We intend to use the proceeds of this
offering to repay $42.0 million outstanding under the bridge loan from Enron and
a portion of the $175.0 million term loan from Enron. If we complete the
concurrent notes offering, we will use the proceeds of both offerings to repay
$42.0 million outstanding under the bridge loan, $175.0 million under the term
loan, $50.2 million outstanding under a working capital facility with Enron and
for fees and expenses and general partnership purposes. If we are not able to
complete the offerings, we will seek other sources of financing to repay or
refinance the bridge loan and the term loan prior to maturity.

If we complete the concurrent notes offering, we will be bound by covenants
that could restrict payments of distributions and the incurrence of additional
indebtedness. We generally will be able to make distributions only if, subject
to certain exceptions, our fixed charge coverage ratio for the four most recent
fiscal quarters is at least 2.0 to 1.0 until December 31, 2001, and 2.25 to 1.0
for the years thereafter. In general, subject to certain exceptions, we would
not be able to incur additional indebtedness unless our fixed charge coverage
ratio for the four most recent fiscal quarters would have been at least 2.0 to
1.0 until December 31, 2001, and 2.25 to 1.0 for the years thereafter,
determined on a pro forma basis, as if the additional indebtedness had been
incurred at the beginning of such four quarter period (including a pro forma
application of the net proceeds from such additional indebtedness). Other
restrictive covenants include, among others, those that would limit our ability
to participate in mergers, sales of assets, sale and lease-back transactions,
transactions with affiliates, and unpermitted business activities.

We believe that the Enron credit facility will be sufficient to support our
crude oil purchasing activities and working capital requirements. No assurance,
however, can be given that we will not be required to 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.

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 in which we engage. Any
significant decrease in our financial strength, regardless of the reason for
such decrease, may increase the number of transactions requiring letters of
credit or other financial support, make it more difficult for us to obtain such
letters of credit, and/or increase the cost of obtaining them. This could in
turn adversely affect our ability to maintain or increase the level of our
purchasing and marketing activities or otherwise adversely affect our
profitability and available cash.

Generally, we will distribute 100% of our available cash within 45 days
after the end of each quarter to unitholders of record and to our general
partner. Available cash is defined in our partnership agreement and consists
generally of all our cash receipts for the quarter adjusted for our cash
disbursements (such as
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<PAGE> 26

payments of principal, premium and interest and capital expenditures) and net
changes to reserves. Our general partner may establish reserves that it
determines in its reasonable discretion are necessary or appropriate to provide
for the proper conduct of our business, to provide funds for distributions with
respect to units for any one or more of the next four calendar quarters or
because distribution of the funds would be prohibited by applicable law or by
any of our loan or other agreements or obligations. Distributions of available
cash to the subordinated unitholders are subject to the prior rights of the
common unitholders to receive the minimum quarterly distribution for each
quarter during the subordination period, and to receive any arrearages in the
distribution of the minimum quarterly distribution on the common units for prior
quarters during the subordination period.

The minimum quarterly distribution is $0.475 per unit ($35.8 million per
year after giving effect to this offering). Enron has committed to provide total
cash distribution support in exchange for additional partnership interests 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 million ($26.5 million of which remains available). We paid distributions
for the second quarter of 1999 to our common unitholders and our general partner
on August 13, 1999 without any distribution support from Enron.

In the normal course of business, we utilize crude oil repurchase
agreements with a financial institution for short-term liquidity needs. The
terms of these agreements are negotiated on an individual basis pursuant to a
master agreement. The crude oil repurchase agreements allow us to finance the
storage of crude oil. We sell crude oil to the financial institution on a spot
basis and agree to repurchase the crude oil at the same price plus a premium
which, in the past, has been approximately LIBOR plus 0.55%. We store the crude
oil we sell as an agent for the financial institution. Each repurchase agreement
is settled at the end of 30 days, and can be renewed monthly; however, either
party may terminate the repurchase agreement. While the repurchase agreements
have default, cross-default, and acceleration provisions, there are no
maintenance or financial covenants associated with the agreements. At December
31, 1998, we had outstanding forward commodity repurchase agreements of
approximately $83.0 million. Pursuant to the agreements, which had terms of
thirty days, we repurchased the crude oil inventory on January 20, 1999 for
approximately $83.4 million. At June 30, 1999, we had outstanding forward
commodity repurchase agreements of approximately $90.0 million. Pursuant to the
agreements, which had terms of 30 days, we repurchased the crude oil inventory
on July 20, 1999 for approximately $90.4 million.

OTHER INFORMATION

Our 1998 Annual Report on Form 10-K and the Quarterly Report on Form 10-Q
for the six months ended June 30, 1999 include additional information in
Management's Discussion and Analysis of Financial Condition and Results of
Operations concerning Year 2000 and certain recent accounting pronouncements.

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<PAGE> 27

BUSINESS

We engage in the following business activities:

BUSINESS STRATEGY

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<PAGE> 28

be accountable as separate profit centers and employees will receive
incentives based on performance and profitability. The business centers
are responsible for implementing the following initiatives:

COMPETITIVE STRENGTHS

We believe that the following competitive strengths will allow us to
successfully execute our business strategy:

- PRESENCE IN ALL MAJOR SUPPLY AND TRADING AREAS IN THE LOWER 48
STATES. Because of our physical presence in all major markets, we have
substantial information on market conditions and are strategically
positioned to react to changes in supply and demand that may occur in a
particular region. In addition, we are less vulnerable to supply
shortages in any one producing area or operating difficulties with any
one producer.

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<PAGE> 29

up to an aggregate of $29.0 million. Enron also provides us with credit
support through a $1.0 billion credit facility. We also have the ability
to consult with Enron on a variety of operational matters, such as
transportation and internal controls, and to receive from Enron
administrative support in areas such as legal and insurance.

BUSINESS SEGMENTS

NORTH AMERICAN CRUDE OIL -- EAST OF ROCKIES

General

Our crude oil gathering and marketing operations consist of purchasing and
gathering crude oil from producers and operators for subsequent sale to refiners
and other customers. Our gathering activities are conducted in 18 states which
represent approximately 97% of the crude oil production in the lower 48 states.
Gathering and marketing of crude oil consists of:

- purchasing lease crude oil from producers and operators at the oil well
and in bulk from aggregators at major pipeline interconnects and
marketing locations,

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

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

- 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 addition, we have a 15 year supply contract at market-based prices with Koch
Oil Company for less than 25% of our lease volumes.

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 our field personnel to purchase and transport the crude oil to market.
We utilize our pipelines and trucks to transport most of the crude oil we
purchase to market.

We engage in several types of purchases, sales and exchanges of crude oil.
Most transactions we enter into are at market responsive prices for a term or
duration of 90 days or less, with a large number of transactions on a 30-day
renewable basis. These purchases are automatically renewable on a month-to-month
basis until terminated by either party. The purchases are typically based on our
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 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 the overall basis risk and variability in our crude oil gathering and
marketing business. See "Business -- Risk Management."

The ten producer customers from which we gathered the most crude oil during
April of 1999 were: UPR Energy, Swift Energy, Continental Resources, Burlington
Resources, Unocal, Ocean Energy, Citation Crude, Sonat Exploration, Titan
Resources and Pioneer Natural Resources.
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<PAGE> 30

The North American Crude Oil -- East of Rockies operation has recently been
reorganized into eight operating regions. Of the 431,300 barrels per day of
lease crude oil we purchased in the second quarter of 1999, approximately
412,200 barrels per day or 96% was gathered in the North American Crude
Oil -- East of Rockies business segment. The remainder of the lease crude oil
was gathered in the West Coast region.

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 NYMEX. This process enables us to hedge against price fluctuations until we
make physical delivery of the crude oil. After 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 our lease crude oil volumes. Throughout the process, we
seek to maintain a substantially balanced position at all times with respect to
lease volumes; however, we have certain risks which 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. It is our policy not to hold any inventory for
the purpose of speculating on price changes.

The ten refinery customers to which we marketed the most crude oil during
April of 1999 were: Koch Petroleum, Conoco, Coastal States, Crown Central,
Williams, Ultramar Diamond Shamrock, Pennzoil-Quaker State, Mobil, Marathon
Ashland, and CITGO Petroleum.

Market conditions have a direct effect on our marketing strategy. 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.

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 our
ability to offer enhanced customer services to producers and operators is an
important factor in maintaining lease purchase volumes and in obtaining new
volumes. Services we offer include gathering capabilities, timely pickup of
crude oil from producers' tanks at the lease or production point, accurate
measurement of crude oil volumes delivered, avoidance of spills and certain
accounting and administrative services. Accounting and administrative services
include processing division orders (dividing payments among the several holders
of interests in a lease), providing statements of the crude oil purchased 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 correctly 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 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. Typically, lease crude oil purchased in conjunction with producer
services provide us with higher margins since we are able to charge the producer
a premium for these services.
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PIPELINE OPERATIONS

Our pipeline operations provide the vital link between our crude oil
purchasing activities and our marketing activities. We own and operate
approximately 8,300 miles of crude oil gathering and transmission pipelines
covering thirteen states, including approximately 7,400 miles of regulated
intrastate and interstate common carrier pipeline systems. There are
approximately 15.1 million barrels of storage capacity associated with field
tanks. By state, our pipeline assets are as follows:

<TABLE>
<CAPTION>
EOTT COMMON CARRIER PIPELINE MILES BY STATE EOTT PROPRIETARY PIPELINE MILES BY STATE
- ------------------------------------------- ----------------------------------------
MILES MILES
<S> <C> <C> <C>
Alabama.......................... 56 Alabama......................... 38
Arkansas......................... -- Arkansas........................ 2
California....................... 16 California...................... 159
Colorado......................... 332 Colorado........................ --
Kansas........................... 795 Kansas.......................... --
Louisiana........................ 412 Louisiana....................... 131
Mississippi...................... 293 Mississippi..................... 267
Montana.......................... 118 Montana......................... --
Nebraska......................... 56 Nebraska........................ --
New Mexico....................... 1,174 New Mexico...................... 158
North Dakota..................... 489 North Dakota.................... --
Oklahoma......................... 1,389 Oklahoma........................ 33
Texas............................ 2,256 Texas........................... 82
----- ---
Total.................. 7,386 Total........................... 870
===== ===
</TABLE>

Through these pipeline systems, we transport crude oil for our North
American Crude Oil -- East of Rockies and West Coast business segments and third
party customers pursuant to published tariff rates regulated by the Federal
Energy Regulatory Commission 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. In the second quarter of 1999, our pipeline operations
transported approximately 512,800 barrels per day through our regulated pipeline
systems. Pipeline revenues are primarily a function of the level of crude oil
transported through the pipeline, known as throughput, and the applicable
pipeline tariffs. Approximately 76% of the revenues from the Pipeline Operations
business segment for the three months ended June 30, 1999, were generated from
tariffs charged to the North American Crude Oil -- East of Rockies business
segment. The operating income from our Pipeline Operations business segment is
generated by the difference between the published tariff and the fixed and
variable costs of operating the pipelines.

We believe that pipelines provide the lowest-cost method of transportation,
and accordingly, we have focused on increasing the percentage of barrels
transported on 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, 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.

WEST COAST OPERATIONS

We conduct a number of business activities in the petroleum market on the
West Coast, including the following: (i) crude oil blending; (ii) lease crude
oil gathering and marketing; (iii) natural gas liquids marketing; and (iv)
refined petroleum products marketing. These business activities are operated as
an integrated business, with our lease crude oil and gas fractionation
operations being the primary components in our crude oil blending operations.

We acquired assets from Koch that improved the transportation economics of
our blending and marketing activities and greatly expanded our existing natural
gas liquids marketing business on the West Coast. These assets primarily
included a gas processing plant with 20 million cubic feet per day of gas
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<PAGE> 32

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 distribution facilities.

The primary function of lease crude oil gathering on the West Coast is to
support the crude blending operation. We purchase crude oil from a number of
producers on the West Coast, ranging from small independents to major oil
companies. Our West Coast lease crude oil volumes are transported by a variety
of pipeline gathering systems as well as by truck, either owned by us or through
third parties.

Our acquisition of the fractionation plant from Koch has given us the
ability to produce natural gasoline, which is a valuable component of our crude
blending operation. The fractionator and the associated five million gallon
refrigerated storage facility has also turned us into a major participant in the
wholesale marketing of propane on the West Coast.

The bulk of our profitability in the West Coast market is derived from
crude oil blending. Our margins for the West Coast crude oil business are
primarily tied to our ability to upgrade heavy sour crude into a medium gravity,
Alaskan North Slope type of crude oil, called Line 63. To accomplish this, we
gather crude oil by truck and pipeline and deliver it to proprietary blend
stations strategically placed along our gathering system.

In addition, the West Coast Operations include a refined petroleum products
marketing business. This business specializes mostly in marketing distillate and
gasoline at terminals located between Seattle and San Diego.

RISK MANAGEMENT

We attempt to minimize our exposure to commodity prices. Generally, as we
purchase lease crude oil at prevailing market prices, we enter into
corresponding sale 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. This process gives us the opportunity to profit
on the transaction at the time of purchase and to effect a substantially
balanced position, thereby minimizing or reducing our exposure to price
fluctuations that may occur after the initial purchase.

Sophisticated 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 our 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 position at all times. It
is our policy not to acquire and hold crude oil, other petroleum products,
futures contracts or other derivative products for the purpose of speculating on
price changes. Nevertheless, 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 the transactions are entered into. In such cases we
are subject to the risk that prices may change or that price changes will not
occur as anticipated. Our ability to maintain or increase our gross margins and
to protect our company 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 POLICIES

Credit review and analysis are also integral to our lease purchases.
Payment for all or substantially all of the monthly lease production gathered is
sometimes 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

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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.

When we market crude oil, we determine the amount, if any, of the line of
credit to be extended to any given customer. We use a proprietary credit rating
system that analyzes credit suitability and determines the amount of credit
extended. Since typical sales transactions can involve tens of thousands of
barrels of crude oil, the risk of non-payment and non-performance by customers
is a major consideration in our business. As a result, we reserve for bad debts;
however, beginning with our first full year of operations, 1995, our loss
experience has totaled less than $1.0 million per fiscal year. We believe our
sales are made to creditworthy entities or entities with adequate credit
support, of which approximately two-thirds have investment grade credit ratings.

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 major structural
and economic changes impacting all of our market segments that are driving new
customer needs, changing competitor dynamics and, consequently, creating new
challenges and opportunities for responsive market participants. The decline in
domestic crude oil production has made competition among gatherers and marketers
even more intense.

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 are Scurlock Permian Oil Corporation
(now owned by Plains All American), Equiva (formerly Texaco Trading &
Transportation Co., Inc.), Amoco Oil Company, Genesis Energy, L.P., Sun Refining
& Marketing and TEPPCO Partners, L.P.

EMPLOYEES

Our general partner employs approximately 1,400 people. None of these
employees is represented by a labor union, and our general partner believes that
its relationships with these employees are good.

S-31
<PAGE> 34

MANAGEMENT

As is common with publicly traded limited partnerships, we do not employ
any of the persons responsible for managing or operating our business, but
instead we reimburse our general partner for their services. Set forth below is
certain information concerning the directors and executive officers of the
general partner. All directors of the general partner are elected annually by
and may be removed by Enron Liquids Holding Corp., a wholly owned subsidiary of
Enron Corp., as the sole shareholder of the general partner. All executive
officers serve at the discretion of the board of directors of the general
partner.

<TABLE>
<CAPTION>
YEARS EMPLOYED
BY ENRON OR ITS
NAME AGE SUBSIDIARIES POSITION
- ---- --- --------------- --------
<S> <C> <C> <C>
Edward O. Gaylord............. 67 Director and Chairman of the
Board
Michael D. Burke.............. 54 1 Director, Chief Executive
Officer and President
Dana R. Gibbs................. 40 7 Executive Vice President
Mary Ellen Coombe............. 48 18 Vice President, Human
Resources and Administration
Stephen W. Duffy.............. 46 11 Vice President and General
Counsel
Douglas P. Huth............... 52 7 Vice President, Operations
Lori L. Maddox................ 34 2 Controller
Susan C. Ralph................ 49 8 Treasurer
John H. Duncan................ 70 Director
Dee S. Osborne................ 68 Director
Daniel P. Whitty.............. 67 Director
Kenneth L. Lay................ 56 20 Director
Stanley C. Horton............. 48 25 Director
</TABLE>

Edward O. Gaylord has served as a member of the board of directors since
January 1993. Mr. Gaylord was elected Chairman of the Board of EOTT Energy Corp.
in February 1993. He was elected in December 1995 as a member of the Audit
Committee. Prior to joining EOTT Energy Corp., Mr. Gaylord owned and managed
Gaylord & Company, a private venture capital firm, and he has owned interests in
and managed various trucking, storage and manufacturing entities in his career
of more than 30 years. Mr. Gaylord serves on the board of directors of Imperial
Holly Corporation, Seneca Foods Corporation, Federal Reserve Bank of
Dallas -- Houston Branch, and the general partner of Kinder Morgan Energy
Partners, L.P.

Michael D. Burke joined EOTT Energy Corp. as President and Chief Executive
Officer in May 1998. He was also elected to the board of directors in May 1998.
Prior to joining EOTT Energy Corp., Mr. Burke was a management consultant and
served as President and CEO of M.D. Burke & Co. Mr. Burke was previously
associated with Tesoro Petroleum Corporation as President and CEO from 1992 to
1995, and he was President and CEO of TEPPCO Partners L.P. from 1990 to 1992.

Dana R. Gibbs joined EOTT Energy Corp. as Executive Vice
President -- Commercial in April 1999. Prior to joining EOTT Energy Corp., Mr.
Gibbs was Vice President -- Global Trading with Enron Capital & Trade Resources
responsible for worldwide crude oil, petroleum products, petrochemicals, natural
gas liquids, and plastics trading. Mr. Gibbs joined Enron Capital & Trade
Resources in 1992 and held several executive positions in the trading controls,
structuring, and controller departments. From 1990 to 1992, Mr. Gibbs was the
Vice President -- Finance of MG Natural Gas Corp. and from 1982 to 1990 was with
Arthur Andersen & Co.

Mary Ellen Coombe has served as Vice President, Human Resources and
Administration since December 1992. She served as Senior Vice President, Human
Resources and Administration for Enron Liquid Fuels (including EOTT Energy
Corp.) from January 1992 until December 1992.

S-32
<PAGE> 35

Stephen W. Duffy has served as Vice President and General Counsel since
December 1992. He served as Assistant General Counsel for EOTT Energy Corp. from
December 1990 to December 1992 and as Senior Counsel from October 1988 to
December 1990.

Douglas P. Huth has served as Vice President, Operations of EOTT Energy
Corp. since December 1992. Mr. Huth serves as Vice Chairman on the board of
directors of the National Private Truck Council. From July 1992 to December
1992, Mr. Huth served as Senior Vice President and General Manager of Enron Gas
Processing Company's Western/Bushton Business Development and Operations Region.

Lori L. Maddox has served as Controller 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 from 1982 to
September 1996.

Susan C. Ralph joined EOTT Energy Corp. in 1991 and has served as Treasurer
since 1996. Prior to joining EOTT Energy Corp., Ms. Ralph served as Vice
President of Finance for TW Oil Houston, Inc and Vice President and Director of
Gorges Foodservices, Inc. Prior to 1979, Ms. Ralph held various positions in the
commercial banking industry.

John H. Duncan was elected to the EOTT Energy Corp. board of directors in
January 1993 and appointed to the Compensation Committee in February 1993. Since
1990, Mr. Duncan's principal occupation has been investments. Mr. Duncan is also
a director of Enron Corp. and Chase of Texas, N. A.

Dee S. Osborne was elected to the EOTT Energy Corp. board of directors and
appointed to the Audit Committee and Compensation Committee in February 1993.
Mr. Osborne serves as President of Crest Investment Company, Chairman of Digital
and Wireless Communications, L.L.C. and Vice Chairman of Jacintoport Terminal
Company. He is a director of Ocean Energy, Inc. and Trustee of Scott & White
Memorial Hospital.

Daniel P. Whitty was elected to the EOTT Energy Corp. board of directors in
January 1993 and appointed to the Audit Committee and the Compensation Committee
in February 1993. Mr. Whitty is an independent financial consultant and serves
as the Chairman of the Audit Committee of Northern Border Partners, L.P. and as
a director of Enron Equity Corp. He has also served as a director of Methodist
Retirement Communities, Inc. and a Trustee of the Methodist Retirement Trust.
Until his retirement in 1988, Mr. Whitty served 35 years with Arthur Andersen
LLP and was elected to its worldwide partnership in 1962.

Kenneth L. Lay was elected to the EOTT Energy Corp. board of directors in
January 1993 and for over five years has served as Chairman of the Board and
Chief Executive Officer of Enron Corp. Mr. Lay is also a director of Enron
Corp., Trust Company of the West, Eli Lilly and Company, and Compaq Computer
Corporation.

Stanley C. Horton was elected to the EOTT Energy Corp. Board of Directors
in May 1998. Mr. Horton is the Chairman and Chief Executive Officer of Enron Gas
Pipeline Group and has held that position since January 1997. From February 1996
to January 1997, he was Co-Chairman and Chief Operating Officer of Enron
Operations Corp. From June 1993 to February 1996, he was President and Chief
Operating Officer of Enron Pipeline and Liquids Group. Mr. Horton was appointed
to the Partnership Policy Committee of Northern Border Partners, L.P. in
December 1998. Mr. Horton serves on the Board of Directors of the Interstate
Natural Gas Association. He also serves as Second Vice Chairman and Treasurer of
Gas Industry Standards Board and as Vice Chairman of Gas Research Institute.

S-33
<PAGE> 36

PRINCIPAL UNITHOLDERS

Our general partner knows of no person who beneficially owns in excess of
five percent of our common units except as set forth in the table below.

<TABLE>
<CAPTION>
AMOUNT AND NATURE
NAME AND ADDRESS OF BENEFICIAL OWNERSHIP PERCENT PRO FORMA
OF BENEFICIAL OWNER TITLE OF CLASS AS OF JUNE 30, 1999 OF CLASS PERCENT OF CLASS(1)
- ------------------- -------------- ----------------------- -------- -------------------
<S> <C> <C> <C> <C>
Enron Corp........................ Common Units 3,276,811 21.88% 17.74%
1400 Smith Street Subordinated Units(2) 7,000,000 77.78 77.78
Houston, Texas 77002 General Partner Interest(3) 1 100.0 100.0
Koch Pipeline Company............. Common Units 1,700,000 11.35 9.20
4111 East 37th Street N. Subordinated Units 2,000,000 22.22 22.22
Wichita, Kansas 67220
</TABLE>

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

(1) Pro forma percent of class represents the percent of class as of June 30,
1999 adjusted to give effect to the sale of 3,500,000 common units (assuming
the over-allotment option is not exercised).

(2) Held by our general partner, an indirect subsidiary of Enron Corp.

(3) The reporting of the general partner interest is not a concession that the
interest represents a security.

S-34
<PAGE> 37

UNDERWRITING

Under the terms and subject to the conditions contained in an underwriting
agreement dated September 23, 1999, the underwriters named below, for whom
PaineWebber Incorporated, Lehman Brothers Inc., Dain Rauscher Wessels, a
division of Dain Rauscher Incorporated and ING Barings LLC are acting as
representatives, have agreed to purchase from us and we have agreed to sell, the
following number of common units:

<TABLE>
<CAPTION>
UNDERWRITER NUMBER OF COMMON UNITS
- ----------- ----------------------
<S> <C>
PaineWebber Incorporated.................................... 1,750,000
Lehman Brothers Inc......................................... 1,050,000
Dain Rauscher Wessels, a division of Dain Rauscher
Incorporated.............................................. 525,000
ING Barings LLC............................................. 175,000
---------
Total............................................. 3,500,000
=========
</TABLE>

The underwriters propose to offer the common units at the offering price
shown on the cover page of this prospectus, and in part to specified securities
dealers, who may include the underwriters, at a price less a concession not in
excess of $0.50 per common unit, and the underwriters and those dealers may
reallot to specified dealers a discount not in excess of $0.10 per common unit.
The common units are offered subject to receipt and acceptance by the
underwriters, and to other conditions, including the right to reject orders in
whole or in part.

We have granted the underwriters an option to purchase up to 525,000
additional common units, exercisable for 30 days after the date of this
prospectus, to cover over-allotments, if any, at the public offering price less
the underwriting discount and commissions. The underwriters may purchase those
common units only to cover over-allotments made for this offering. If the
underwriters exercise this option, each underwriter will be committed, subject
to specified conditions, to purchase an additional number of common units
proportionate to that underwriter's initial commitment.

The following table shows the underwriting discounts and commissions to be
paid to the underwriters in connection with this offering. These amounts are
shown assuming both no exercise and full exercise of the underwriters'
over-allotment option to purchase additional common units:

<TABLE>
<CAPTION>
WITHOUT EXERCISE OF WITH FULL EXERCISE OF
OVER-ALLOTMENT OPTION OVER-ALLOTMENT OPTION
--------------------- ---------------------
<S> <C> <C>
Per common unit.................................. $ 0.88 $ 0.88
Total............................................ $ 3,080,000 $ 3,542,000
</TABLE>

EOTT Energy Partners, L.P., on behalf of itself and its affiliates, our
general partner, Enron and certain executives and other persons have agreed, for
a period of 90 days from the date of this prospectus, not to, without the prior
written consent of PaineWebber Incorporated directly or indirectly, offer,
pledge, sell, contract to sell any option or contract to purchase, purchase any
option or contract to sell, grant any option, right or warrant to purchase,
enter into any swap or other arrangement that transfers to another, in whole or
in part, any of the economic consequences of ownership or otherwise transfer or
dispose of any common units, subordinated units, rights to acquire common units
or subordinated units or any security convertible into or exercisable or
exchangeable for common units or subordinated units, including, without
limitation, common units or subordinated units that may be deemed to be
beneficially owned in accordance with the rules and regulations of the SEC,
other than the common units subject to the underwriters' over-allotment option,
subject to specified limited exceptions.

We estimate our expenses incurred in connection with this offering to be
approximately $469,000. We and our general partner have agreed to indemnify the
underwriters against certain liabilities, including liabilities under the
Securities Act of 1933, or to contribute to payments the underwriters may be
required to make in respect thereof.

S-35
<PAGE> 38

Because the National Association of Securities Dealers, Inc. ("NASD") views
the common units offered hereby as interests in a direct participation program,
this offering is being made in compliance with Rule 2810 of the NASD's Conduct
Rules. Investor suitability of the common units should be judged similarly to
the suitability of other securities which are listed for trading on a national
securities exchange. The underwriters do not intend to confirm sales to any
accounts over which they exercise discretionary authority without the prior
written approval of the transaction by the customer.

For this offering, the underwriters may purchase and sell common units in
the open market. These transactions may include over-allotment and stabilizing
transactions and purchases to cover syndicate short positions created for this
offering. Stabilizing transactions consist of certain bids or purchases for the
purpose of preventing or retarding a decline in the market price of the common
units; and syndicate short positions involve the sale by the underwriters of a
greater number of common units than they are required to purchase from us in
this offering. The underwriters may also impose a penalty bid, whereby selling
concessions allowed to syndicate members or other broker-dealers in respect of
the common units sold in this offering for their account may be reclaimed by the
syndicate if those common units are repurchased by the syndicate in stabilizing
or covering transactions. These activities may stabilize, maintain or otherwise
affect the market price of the common units, which may be higher than the price
that might otherwise prevail in the open market; and these activities, if
commenced, may be discontinued at any time without notice. These transactions
may be effected on the New York Stock Exchange or otherwise.

Neither we nor the underwriters make any representation or prediction as to
the direction or magnitude of any effect that the transactions described above
may have on the price of the common units. In addition, neither we nor the
underwriters make any representation that the underwriters will engage in these
transactions or that these transactions, once begun, will not be discontinued
without notice.

The underwriters have performed certain investment banking and advisory
services for us and for our affiliates from time to time for which they have
received customary fees and expenses. The underwriters may, from time to time,
engage in transactions with and perform services for us and for our affiliates
in the ordinary course of their business.

LEGAL MATTERS

Vinson & Elkins L.L.P., will pass upon the validity of the common units
offered in this prospectus supplement. Andrews & Kurth L.L.P. will advise the
underwriters about other issues relating to the offering.

EXPERTS

The audited consolidated financial statements and schedule of EOTT Energy
Partners, L.P. as of December 31, 1998 and 1997, and for the three years in the
period ended December 31, 1998, incorporated by reference in this prospectus
supplement and elsewhere in the registration statement have been audited by
Arthur Andersen LLP, independent public accountants, as indicated in their
report with respect thereto, and are included herein in reliance upon the
authority of said firm as experts in accounting and auditing in giving said
report.

S-36
<PAGE> 39

THE INFORMATION IN THIS PROSPECTUS IS NOT COMPLETE AND MAY BE CHANGED. WE MAY
NOT SELL THESE SECURITIES UNTIL THE REGISTRATION STATEMENT FILED WITH THE
SECURITIES AND EXCHANGE COMMISSION IS EFFECTIVE. THIS PROSPECTUS IS NOT AN OFFER
TO SELL THESE SECURITIES AND IT IS NOT SOLICITING AN OFFER TO BUY THESE
SECURITIES IN ANY STATE WHERE THE OFFER OR SALE IS NOT PERMITTED.

FILED PURSUANT TO RULE 424(b)(2)

REGISTRATION NO. 333-82269

REGISTRATION NO. 333-82269-01

REGISTRATION NO. 333-82269-02

REGISTRATION NO. 333-82269-03

REGISTRATION NO. 333-82269-04

PROSPECTUS

$500,000,000

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

COMMON UNITS
DEBT SECURITIES

EOTT ENERGY PARTNERS, L.P.
EOTT ENERGY FINANCE CORP.

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

We are EOTT Energy Partners, L.P., a publicly traded limited partnership
engaged in the purchasing, gathering, transporting, storage and resale of crude
oil, refined petroleum products and natural gas liquids and in related
activities. We are the issuer of the common units and debt securities offered by
means of this prospectus. EOTT Energy Finance Corp. may act as co-issuer of debt
securities.

We currently have 14,976,011 common units outstanding. Our common units are
traded on the New York Stock Exchange under the symbol "EOT."

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

WE WILL PROVIDE SPECIFIC TERMS OF OFFERINGS OF OUR SECURITIES IN PROSPECTUS
SUPPLEMENTS. YOU SHOULD READ THIS PROSPECTUS AND ANY SUPPLEMENT TO THIS
PROSPECTUS CAREFULLY BEFORE YOU INVEST. YOU SHOULD ALSO READ THE DOCUMENTS WE
HAVE REFERRED YOU TO IN THE "WHERE YOU CAN FIND MORE INFORMATION" SECTION OF
THIS PROSPECTUS FOR INFORMATION ON US AND FOR OUR FINANCIAL STATEMENTS. TOGETHER
THESE DOCUMENTS WILL PROVIDE YOU WITH THE SPECIFIC TERMS OF THE OFFERINGS. THIS
PROSPECTUS MAY NOT BE USED TO SELL OUR SECURITIES UNLESS IT IS ACCOMPANIED BY A
PROSPECTUS SUPPLEMENT.

LIMITED PARTNER INTERESTS ARE INHERENTLY DIFFERENT FROM CAPITAL STOCK OF A
CORPORATION. PURCHASERS OF OUR SECURITIES SHOULD CONSIDER EACH OF THE FACTORS
DESCRIBED UNDER "RISK FACTORS," ON PAGE 2, IN EVALUATING AN INVESTMENT IN US.

NEITHER THE SEC NOR ANY STATE SECURITIES COMMISSION HAS APPROVED OR
DISAPPROVED OF OUR SECURITIES. THIS MEANS THAT NEITHER THE SEC NOR ANY STATE
SECURITIES COMMISSION HAS PASSED UPON THE ACCURACY, ADEQUACY OR COMPLETENESS OF
THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.

THE DATE OF THIS PROSPECTUS IS SEPTEMBER 2, 1999.

<PAGE> 40

TABLE OF CONTENTS

<TABLE>
<CAPTION>
PAGE NO.
--------
<S> <C>
ABOUT THIS PROSPECTUS....................................... ii
WHERE YOU CAN FIND MORE INFORMATION......................... ii
CAUTIONARY STATEMENT REGARDING FORWARD LOOKING STATEMENTS... iii
WHO WE ARE.................................................. 1
RISK FACTORS................................................ 2
CONFLICTS OF INTEREST AND FIDUCIARY RESPONSIBILITIES........ 7
USE OF PROCEEDS............................................. 8
DESCRIPTION OF THE DEBT SECURITIES.......................... 8
RATIO OF EARNINGS TO FIXED CHARGES.......................... 13
DESCRIPTION OF OUR COMMON UNITS............................. 13
CASH DISTRIBUTION POLICY.................................... 15
DESCRIPTION OF OUR PARTNERSHIP AGREEMENT.................... 16
TAX CONSIDERATIONS.......................................... 19
PLAN OF DISTRIBUTION........................................ 34
LEGAL MATTERS............................................... 35
EXPERTS..................................................... 35
</TABLE>

i
<PAGE> 41

ABOUT THIS PROSPECTUS

This prospectus is part of a registration statement that we filed with the
SEC using a "shelf" registration process. Under this shelf process, we may offer
from time to time up to $500,000,000 of our securities. Each time we offer our
securities, we will provide you with a prospectus supplement that will describe,
among other things, the specific amounts and prices of the securities being
offered and the terms of the offering including, in the case of debt securities,
the specific terms of the securities. The prospectus supplement may also add,
update or change information contained in this prospectus. Therefore, before you
invest in our securities, you should read this prospectus, any prospectus
supplements and all additional information referenced in the next section.

WHERE YOU CAN FIND MORE INFORMATION

We file annual, quarterly and current reports and other information with
the SEC. You may read and copy any document we file at the SEC's public
reference room at Room 1024, Judiciary Plaza, 450 Fifth Street, N.W.,
Washington, D.C. 20549 and at the SEC's public reference rooms in New York, New
York and Chicago, Illinois. Please call the SEC at 1-800-SEC-0330 for further
information on the public reference rooms. In addition, the SEC maintains a web
site that contains reports, information statements and other information
regarding issuers that file electronically. Our SEC filings are also available
on this web site at http://www.sec.gov. You can also obtain information about us
at the offices of the New York Stock Exchange, 20 Broad Street, New York, New
York, 10005.

The SEC allows us to incorporate by reference information we file with it
into this prospectus. This procedure means that we can disclose important
information to you by referring you to documents on file or to be filed with the
SEC. The information we incorporate by reference is part of this prospectus and
later information that we file with the SEC will automatically update and
supersede this information. Therefore, before you decide to invest in a
particular offering under this shelf registration, you should always check for
SEC reports we may have filed after the date of this prospectus. We incorporate
by reference the documents listed below and any future filings made with the SEC
under Section 13(a), 13(c), 14 or 15(d) of the Securities Exchange Act of 1934
until all offerings under this shelf registration are completed:

- Annual Report on Form 10-K for the year ended December 31, 1998;

- Quarterly Reports on Form 10-Q for the quarters ended March 31, 1999 and
June 30, 1999; and

- the description of our common units contained in our Form 8-A/A dated
March 14, 1994.

You may request a copy of these filings at no cost by making written or
telephone requests for copies to:
EOTT Energy Corp.
1400 Smith Street
Houston, Texas 77002
Attention: Shareholder Relations
Telephone: (713) 853-6161

You should rely only on the information incorporated by reference or
provided in this prospectus or any prospectus supplement. We have not authorized
anyone else to provide you with any information. You should not assume that the
information in this prospectus or any prospectus supplement is accurate as of
any date other than the date on the front of each document.

ii
<PAGE> 42

CAUTIONARY STATEMENT REGARDING FORWARD LOOKING STATEMENTS

This prospectus contains statements that constitute "forward looking
statements" within the meaning of Section 27A of the Securities Act and Section
21E of the Securities Exchange Act of 1934. In general, any statement other than
a statement of historical fact is a forward looking statement. We caution that
our actual results may differ materially from those anticipated or projected
forward looking statements. Any differences could result from a variety of
factors, including the following:

- our ability to maintain existing volumes of crude oil purchased at the
lease and to obtain additional volumes of crude oil;

- our success in hedging our positions;

- industry conditions;

- prices and demand for crude oil;

- economic, political and administrative developments that impact federal,
state and local departments and agencies that regulate the oil industry;

- the effect of competition;

- conditions of the capital markets;

- our ability to successfully acquire and efficiently integrate new assets;
and

- our ability to successfully implement our Year 2000 readiness program.

The information we set forth under the heading "Risk Factors" details these
and other facts that could affect our operating results. You should carefully
consider all this information before you invest.

iii
<PAGE> 43

WHO WE ARE

We are EOTT Energy Partners, L.P., and we purchase, gather, transport,
store and resell crude oil, refined petroleum products and natural gas liquids.
As an intermediary, 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
who can most benefit from the particular crude oil type. Through our crude oil
gathering and marketing operations, we purchase crude oil produced from
approximately 40,000 leases owned by many of the largest integrated and
independent crude oil producers in the United States and Canada. We purchase
approximately 87% of our lease crude oil from independent oil producers and
approximately 13% from major integrated oil companies. We market the crude oil
to major oil companies and independent refiners throughout the United States and
Canada. In addition to our gathering and marketing operations, we have pipeline
operations in which we transport crude oil on our intrastate and interstate
pipelines based on regulated published tariffs.

On December 1, 1998, we purchased crude oil gathering and transportation
assets in key oil producing regions in a transaction that almost tripled our
pipeline mileage and almost doubled our crude oil lease barrels under contract.
The acquisition included approximately 3,900 miles of crude oil pipelines, crude
oil transport trucks, meter stations, vehicles, storage tanks and contracts for
approximately 180,000 lease barrels of crude oil per day from production in 11
central and western states including Texas, Oklahoma, Kansas and California. On
May 3, 1999, we purchased crude oil transportation and storage assets that
included approximately 2,000 miles of common carrier crude oil pipelines in
Southeast New Mexico and West Texas, bringing our crude oil pipeline mileage to
a total of approximately 8,200 miles.

We are a Delaware limited partnership. EOTT Energy Corp., a Delaware
corporation and an indirect wholly-owned subsidiary of Enron Corp. ("Enron"),
serves as our sole general partner. Our operations are conducted through, and
the operating assets are owned by, EOTT Energy Operating Limited Partnership,
EOTT Energy Canada Limited Partnership and EOTT Energy Pipeline Limited
Partnership, each of which is a Delaware limited partnership. Our general
partner is also the general partner of our operating partnerships. EOTT Energy
Finance Corp., a Delaware corporation, is a wholly-owned subsidiary of EOTT
Energy Partners, L.P. and has been organized for the sole purpose of co-issuing
debt securities.

1
<PAGE> 44

RISK FACTORS

In addition to the other information in, or incorporated by reference in
this prospectus and any accompanying prospectus supplement, you should carefully
consider and evaluate all of the information relating to the risk factors set
forth below.

RISKS RELATED TO OUR BUSINESS

ECONOMIC AND INDUSTRY FACTORS BEYOND OUR CONTROL, INCLUDING PRODUCTION
LEVELS OF CRUDE OIL, CAN ADVERSELY AFFECT OUR GROSS MARGIN.

- 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; and

- 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.

The absolute price levels for crude oil do not necessarily bear a direct
relationship to our gross margins per barrel, and our gross margins per barrel
cannot be projected with any level of certainty. Due to the volatility of crude
oil prices and the decline in crude oil production, crude oil gathering margins
have suffered industry wide over the last few years. Although there has been
improvement in crude oil margins since 1997, margins have not returned to
historical levels.

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.

2
<PAGE> 45

OUR PERFORMANCE DEPENDS ON OUR ABILITY TO MINIMIZE BAD DEBTS AND LEGAL
LIABILITY WHEN EXTENDING CREDIT TO OPERATORS AND CUSTOMERS.

When we purchase crude oil at the lease, we often make payment to an
operator who is responsible for the correct payment and distribution of the
proceeds to other parties. If the operator does not have sufficient resources to
indemnify and defend us in case of a protest, action or complaint by those other
parties, our costs could rise. In addition, because we may extend credit to some
customers in large amounts, it is important that our credit review, evaluation
and control mechanisms work properly. Even if our mechanisms work properly, we
cannot assure you that our customers will not experience losses in dealings with
other parties, in which case we could be adversely affected.

A REDUCTION IN OUR CREDIT STANDING OR ABILITY TO ACCESS CAPITAL WOULD
ADVERSELY AFFECT OUR BASIC PURCHASING AND MARKETING ACTIVITIES.

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 revolving credit facility will be
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 revolving credit facility;

- make it more difficult to renew our revolving credit facility upon its
expiration; or

- increase the cost of obtaining letters of credit.

If we do experience a decrease in financial strength, or if our general partner
is unsuccessful in managing our working capital position, we may be unable to
maintain or increase the level of our purchasing and marketing activities. We
cannot assure you that our revolving 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.

OUR ABILITY TO MAINTAIN OR INCREASE OUR GROSS MARGINS IS DEPENDENT ON THE
SUCCESS OF OUR PRICE RISK MANAGEMENT STRATEGIES.

Sophisticated price risk management strategies, including those involving
price hedges using New York Mercantile Exchange futures contracts, are very
important in maintaining or increasing our gross margins. Hedging techniques
require significant resources dedicated to the management of futures positions
and physical inventories. We cannot assure you that our price risk management
strategies will be successful in protecting us from risks or in maintaining our
gross margins at desirable levels. Furthermore, we have certain basis risks (the
risk that price relationships between delivery points, grades of crude oil or
delivery periods will change) that cannot be completely hedged, 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 the sale prices are not fixed at the time the transactions are
entered into. In these cases we are subject to the risk that prices may change
or that price changes will not occur as anticipated.

Our ability to increase our profitability and cash flow will depend to a
large extent on our success in making wise decisions regarding sources of supply
and demand for crude oil, our skill in handling the transportation and storage
of crude oil and our ability to respond to changes in the markets. The marketing
of crude oil is complex and requires detailed current knowledge of crude oil
sources and outlets and a familiarity with a number of factors including:

- types of crude oil;

- individual refinery demand for specific grades of crude oil;
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- 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.

TECHNICAL AND STRUCTURAL IMPROVEMENTS IN THE MARKETS FOR CRUDE OIL MAY HAVE
AN ADVERSE EFFECT ON OUR PERFORMANCE.

We realize margins because of our ability to take advantage of our
gathering, storage and transportation assets and our ability to effect
transactions at many different delivery points. Developments in the markets for
crude oil or petroleum products, such as the development of more accurate price
reporting mechanisms or the introduction of additional futures contracts
involving new delivery locations and products, may adversely affect our margins.

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 regulatory
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.

We are subject to numerous laws and regulations governing the discharge of
materials into the environment or otherwise relating to environmental
protection. If an accidental leak or spill occurs in one of our pipelines or at
a storage facility, 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. Proper maintenance of pipelines is important for the
avoidance of accidental leaks and spills. The average age of our pipelines is
approximately 40 years, and we have acquired approximately 80% of our pipelines
in the past four years. While we believe we have adequately maintained our
pipelines during our ownership, we cannot assure you that these pipelines have
received proper maintenance at all times prior to our ownership. 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. In addition, we cannot assure you
that in the future regulatory agencies with jurisdiction over us will not enact
additional environmental regulations that will negatively affect our
profitability, cash flow and financial condition.

Our pipelines are subject to rate regulation as well as laws relating to
safety and the environment. Federal and state agencies could change the tariffs
we may charge for common carrier pipeline transportation or impose additional
safety or environmental requirements, any of which could affect our
profitability, cash flow and financial condition.

In connection with our recent asset acquisitions from Koch and Texas-New
Mexico PipeLine Co., the parties agreed to allocate responsibilities for
environmental liabilities associated with the pipelines and other assets
included in these transactions. In the Koch transactions, we agreed to be
responsible for certain environmental matters. For the cleanup of pre-closing
contamination which was unknown on the closing date, we agreed to pay up to
$250,000 for each incident, subject to an overall cap of $13 million on all such
incidents in the aggregate. In the Texas-New Mexico PipeLine transaction, we
generally agreed to assume responsibility for the seller's existing cleanup
obligations. In order to minimize our exposure for remediation costs in the
Texas-New Mexico PipeLine transaction, we obtained $20 million in special
insurance coverage for known and unknown cleanup liabilities. In connection with
that insurance coverage, we, as between ourself and our insurance carrier,
remain responsible for all claims in excess of the

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$20 million, subject to certain deductibles, including a $4 million EOTT
retained liability and a $5 million cap on insurance coverage for known
contamination. Although we believe that we have adequately identified the
anticipated environmental liabilities associated with the Koch and Texas-New
Mexico PipeLine acquisitions, we cannot assure you that there will not be any
material liabilities identified at some future time or that we would be
successful in making indemnity claims, if any. Any claims submitted by us under
any environmental insurance policy will be subject to standard claims review by
the applicable insurance carrier. Should an insurance carrier or an indemnifying
party refuse to honor any claim, or be unable to pay any claim, we would remain
liable for payment.

WE ARE SUBJECT TO RISKS IN PREPARING FOR THE YEAR 2000 PROBLEM.

We estimate that our critical systems will be Year 2000-ready substantially
before January 1, 2000. However, we cannot assure you that our plan to be ready
for the Year 2000 will succeed in accomplishing its purpose or that unforeseen
circumstances will not arise during the implementation of the plan that would
materially adversely affect us.

We are taking reasonable steps to identify, assess, and, where appropriate,
to replace devices that contain embedded chips. Despite these reasonable
efforts, we anticipate that we will not be able to find and remediate all
embedded chips in our systems. Further, we anticipate that third parties on whom
we depend also will not be able to find and remediate all embedded chips in
their systems. Some of the embedded chips that fail to operate or that produce
anomalous results may create system disruptions or failures. Some of these
disruptions or failures may spread from the systems in which they are located to
other systems in a cascade. These cascading failures may have adverse effects
upon our ability to maintain safe operations, and may also have adverse effects
upon our ability to serve our customers and otherwise to fulfill certain
contractual and other legal obligations. The embedded chip problem is widely
recognized as one of the more difficult aspects of the Year 2000 problem across
industries and throughout the world.

Our operations are regulated in part by governmental authorities. We expect
to satisfy these regulatory authorities' requirements for achieving Year 2000
readiness. If our reasonable expectations in this regard are in error, and if a
regulatory authority should order the temporary cessation of our operations in
one or more of these areas, the adverse effect could be material. Other
companies with whom we transact business could face similar problems that
materially adversely affect us.

We cannot assure you that suppliers upon which we depend for essential
goods and services will convert and test their mission-critical systems and
processes in a timely manner. Failure or delay by all or some of these entities,
including the U.S. and state or local governments and foreign governments, could
create substantial disruptions having a material adverse affect on our business.

OUR RAPID GROWTH MAY CAUSE DIFFICULTIES INTEGRATING NEW OPERATIONS.

Part of our business strategy includes acquiring additional assets that
will allow us to increase distributions to unitholders. In the last few years,
we have made several acquisitions that significantly increased our asset base.
Unexpected costs or challenges may arise whenever assets with different
operations are combined. Successful acquisitions require management and other
personnel to devote significant amounts of time to integrating the acquired
assets with existing operations. These efforts may temporarily distract their
attention from day-to-day business, the development or acquisition of new
properties and other business opportunities.

RISKS RELATED TO OUR PARTNERSHIP STRUCTURE

CASH DISTRIBUTIONS TO OUR UNITHOLDERS ARE NOT GUARANTEED AND MAY FLUCTUATE;
ENRON'S COMMITMENT TO SUPPORT CASH DISTRIBUTIONS ON COMMON UNITS WILL EXPIRE
AFTER 2001.

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minimum quarterly distribution. However, Enron's commitment to support the
minimum quarterly distribution extends only to quarters through December 31,
2001.

OUR UNITHOLDERS WILL HAVE LIMITED VOTING RIGHTS AND WILL NOT CONTROL OUR
GENERAL PARTNER.

We are a limited partnership, operated under the direction of our general
partner. This structure affects our common unitholders in various ways
including:

- 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.

WE DO NOT HAVE THE SAME FLEXIBILITY AS CORPORATIONS TO ACCUMULATE CASH AND
EQUITY TO PROTECT AGAINST ILLIQUIDITY IN THE FUTURE.

Unlike a corporation, our partnership agreement requires us to make
quarterly distributions to our partners of all available cash, consisting of all
cash receipts less disbursements and any amounts reserved for commitments and
contingencies, including capital and operating costs and debt covenants. The
value of our common units is likely to decrease if the amount we distribute per
unit decreases. Accordingly, if we experience a liquidity problem in the future
and are required to reduce distributions on our common units, we may not be able
to issue equity on favorable terms.

OUR PARTNERSHIP AGREEMENT MODIFIES THE FIDUCIARY DUTIES OF OUR GENERAL
PARTNER UNDER DELAWARE LAW.

Our partnership agreement modifies fiduciary duties of our general partner
to the limited partners under Delaware law. These modifications of state law
standards of fiduciary duty may limit the ability of unitholders to challenge
successfully the actions of the general partner as being a breach of what would
otherwise have been a fiduciary duty.

UNITHOLDERS MAY HAVE NEGATIVE TAX CONSEQUENCES IF WE DEFAULT ON OUR DEBT OR
SELL ASSETS.

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

OUR GENERAL PARTNER HAS A LIMITED CALL RIGHT.

RISKS RELATED TO OUR CAPITAL STRUCTURE

FURTHER ISSUANCES OF UNITS BY US COULD RESULT IN DILUTION FOR UNITHOLDERS
OR HINDER ANY OF OUR FUTURE FINANCINGS.

The market price of our common units could drop as a result of sales of a
large number of common units in the market or the perception that sales of
common units could occur. These factors could also make it more difficult for us
to raise funds through future offerings of common units. In this respect you
should consider several factors.

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First, on February 12, 1999, our unitholders approved a proposal that
authorized us to issue an additional 10 million common units for any business
purpose. These units may be issued on terms and conditions established by our
general partner in its sole discretion without further approval of any limited
partners. Our partnership agreement also authorizes us to issue other limited
partner interests and other equity under the conditions specified in our
partnership agreement.

Second, our general partner has the right, which it may from time to time
assign in whole or in part to any of its affiliates, to purchase common units,
subordinated units or other equity securities from us whenever, and on the same
terms that, we issue securities to persons other than our general partner and
its affiliates, to the extent necessary to maintain the percentage interest of
our general partner and its affiliates in us that existed immediately prior to
each issuance.

Third, if some or all of our outstanding subordinated units are converted
into common units, the amount of available cash necessary to pay the minimum
quarterly distribution with respect to all of our common units would be
increased proportionately, thereby resulting in a dilution of the interest of
existing common unitholders in our cash distributions.

Fourth, if we issue more units, Enron's commitment to support our minimum
quarterly distributions will not increase, thereby resulting in a dilution of
the support obligation per unit.

Finally, a holder of 1,700,000 outstanding common units is entitled to
certain registration rights that allow it to cause us to register its units for
future sale. This unitholder has agreed for our benefit that it will not
exercise its registration rights until the earlier of March 1, 2000 and 180 days
following an underwritten offering of common units pursuant to this prospectus.

OUR INDEBTEDNESS COULD ADVERSELY AFFECT OUR FINANCIAL CONDITION.

Of our total debt, at June 30, 1999, we had approximately $217 million
payable to Enron by December 31, 1999. We must repay or refinance this debt to
avoid a material adverse effect on our financial condition.

CONFLICTS OF INTEREST AND FIDUCIARY RESPONSIBILITIES

We have extensive ongoing relationships with Enron and its affiliates.
Enron's wholly owned subsidiary, EOTT Energy Corp., serves as our general
partner. Our general partner's employees participate in some employee benefit
plans administered by Enron. Our general partner owns, in addition to its
approximately 2% general partner interest, subordinated units representing
approximately a 29% interest in us, and Enron owns common units representing
approximately a 14% interest in us. The members of the board of directors of our
general partner are elected by a wholly-owned subsidiary of Enron. Our interests
could conflict with the 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.

Unless otherwise provided for in a 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. Because of the competing interests
identified above, our partnership agreement contains provisions that modify some
of these fiduciary duties. For example, our partnership agreement states that
our general partner, its affiliates and its officers and directors will not be
liable for monetary damages to us, our limited partners or their assignees for
errors of judgment or for any acts or omissions if our general partner and they
acted in good faith. Our partnership agreement allows our general partner and
its board of directors to take into account the interests of parties in addition
to ours in resolving conflicts of interest. Our partnership agreement provides
that our general partner will not be in breach of its obligations under our
partnership agreement or its duties to us or our unitholders if the resolution
of a conflict is fair and reasonable to us. The latitude given in our
partnership agreement in connection with resolving conflicts of interest may
significantly limit the ability of a unitholder to challenge what might
otherwise be a breach of fiduciary duty. Our partnership agreement provides that
a purchaser of common units is deemed to have consented to conflicts of interest
and actions of our general partner and its affiliates that might otherwise be
prohibited and to have agreed that the
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conflicts of interest and actions do not constitute a breach by our general
partner of any duty stated or implied by law or equity. Our audit committee
(which is composed of persons who are not officers or employees of our general
partner or any of its affiliates) will, at the request of our general partner,
review conflicts of interest that may arise between our general partner and its
affiliates, on the one hand, and our unitholders or us, on the other. Any
resolution of a conflict approved by our audit committee is conclusively deemed
fair and reasonable to us. 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 in good faith and in a manner
reasonably believed to be in or (in the case of a person other than our general
partner) not opposed to, our best interests and, with respect to any criminal
proceedings, had no reasonable cause to believe the conduct was unlawful.

Our extensive ongoing relationships with Enron include:

- an Ancillary Agreement pursuant to which Enron has committed to
contribute to us up to $29 million ($26.5 million of which remains
available) if necessary to support our ability to pay the minimum
quarterly distribution on our common units with respect to quarters
ending on or prior to December 31, 2001;

- a Corporate Services Agreement pursuant to which Enron has agreed to
provide corporate staff and support services to us;

- agreements with Enron affiliates regarding the gathering and purchase by
us of volumes of crude oil and condensate; and

- a $1 billion credit facility provided by Enron to us and approximately
$217 million, at June 30, 1999, in other indebtedness to Enron for
borrowed money.

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, transportation
and marketing of crude oil and refined petroleum products.

USE OF PROCEEDS

Unless otherwise indicated to the contrary in an accompanying prospectus
supplement, we will use the net proceeds from the sale of securities covered by
this shelf registration for general corporate purposes, which may include
repayment of indebtedness, the acquisition of businesses and other capital
expenditures and additions to working capital.

DESCRIPTION OF THE DEBT SECURITIES

DESCRIPTION OF DEBT SECURITIES

The following are the general terms and conditions that could apply to debt
securities we may issue under this shelf registration statement. If and when we
offer debt securities, a prospectus supplement will state the particular terms
and conditions that actually apply to the debt securities included under the
prospectus supplement. The debt securities will be our unsecured general
obligations and either senior debt securities or subordinated debt securities.

EOTT Energy Finance Corp. may be co-issuer of any series of debt
securities. The co-issuer was incorporated under the laws of the State of
Delaware on July 1, 1999 and is wholly-owned by us. The

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co-issuer has no material assets or any liabilities other than as co-issuer of
debt securities. The co-issuer's activities will be limited to co-issuing debt
securities and engaging in other activities incidental thereto.

If we offer senior debt securities or subordinated debt securities, we will
issue them under an indenture that we refer to in this prospectus as an
"indenture". We will enter into the indentures with a trustee that is qualified
to act under the Trust Indenture Act of 1939 (together with any other trustee(s)
chosen by us and appointed in a supplemental indenture with respect to a
particular series of debt securities, the "Trustee"). We will identify the
Trustee for each series of debt securities in the applicable prospectus
supplement. These filings will be available for inspection at the corporate
trust office of the Trustee, or as described above under "Where You Can Find
More Information." The indenture will be subject to, and governed by, the Trust
Indenture Act.

SPECIFIC TERMS OF EACH SERIES OF DEBT SECURITIES IN THE PROSPECTUS SUPPLEMENT

A prospectus supplement relating to any series of debt securities we offer
will describe the specific terms of those debt securities. These terms will
include some or all of the following:

- the designation, aggregate principal amount and authorized denominations;

- whether the debt securities are senior debt securities or subordinated
debt securities;

- the maturity date;

- the interest rate, if any, and the method for calculating the interest
rate;

- the interest payment dates and the record dates for the interest
payments;

- the portion of the principal amount that will be payable if the maturity
of the debt securities is accelerated;

- any guaranties of the debt securities by any of our affiliated limited
partnerships or others, or other forms of credit support for the debt
securities;

- any mandatory or optional redemption terms or prepayment, conversion,
sinking fund or exchangeability or convertibility provisions;

- the place where principal and interest will be payable;

- if other than denominations of $1,000 or multiples of $1,000, the
denominations the debt securities will be issued in;

- whether the debt securities will be issued in the form of global
securities or certificates;

- the currency or currencies, if other than the currency of the United
States, in which principal and interest will be payable;

- whether the debt securities will be issuable in registered form or bearer
form or both and, if bearer securities are issuable, any restrictions
applicable to the exchange of one form for another and the offer, sale
and delivery of bearer securities;

- the dates on which premium, if any, will be payable;

- our right, if any, to defer payment of interest and the maximum length of
the deferral period;

- any listing on a securities exchange;

- the initial public offering price; and

- other specific terms, including events of default and covenants provided
for with respect to the debt securities.

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Any particular series of debt securities may contain covenants limiting:

- the incurrence of additional debt (including guarantees) by us and our
affiliated limited partnerships;

- the making of certain payments by us and our affiliated limited
partnerships;

- our business activities and those of our affiliated limited partnerships;

- the issuance of other securities by our affiliated limited partnerships;

- asset dispositions;

- transactions with our affiliated limited partnerships and other
affiliates;

- a change of control;

- the incurrence of liens; and

- certain mergers and consolidations involving us and our affiliated
limited partnerships.

PROVISIONS RELATING ONLY TO THE SENIOR DEBT SECURITIES

The senior debt securities will rank equally in right of payment with all
of our other senior and unsubordinated debt and senior in right of payment to
any of our subordinated debt (including the subordinated debt securities). The
senior debt securities will be effectively subordinated to all of our secured
debt. We will disclose the amount of our secured debt in the prospectus
supplement

PROVISIONS RELATING ONLY TO THE SUBORDINATED DEBT SECURITIES

SUBORDINATION TO SENIOR DEBT

The subordinated debt securities will rank junior in right of payment to
all of our senior debt. "Senior debt" will be defined to include all notes or
other evidences of debt, including our guarantees for money we borrowed, not
expressed to be subordinate or junior in right of payment to any other of our
debt.

PAYMENT BLOCKAGES

The indenture may provide that no cash payment of principal, interest and
any premium on the subordinated debt securities may be made:

- if we fail to pay when due any amounts on any senior debt;

- if our property or we are involved in any voluntary or involuntary
liquidation or bankruptcy; and

- in other instances specified in the indenture.

MODIFICATION OF INDENTURE

Under the indenture, generally we and the Trustee will be able to modify
our rights and obligations and the rights of the holders with the consent of the
holders of a specified percentage of the outstanding holders of each series of
debt affected by the modification. No modification of the principal or interest
payment terms, and no modification reducing the percentage required for
modifications, will be effective against any holder without its consent. In
addition, we and the Trustee will be able to amend the indenture without the
consent of any holder of the debt securities to make technical changes.

NO PERSONAL LIABILITY OF OUR GENERAL PARTNER

Our general partner and its directors, officers, employees and shareholders
will not have any liability for our obligations under the indenture or the debt
securities. By accepting a debt security, you waive and release these parties
from this liability. Your waiver and release are part of the consideration for
the issuance of the debt securities.

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PAYMENT AND TRANSFER

Principal, interest and any premium on fully registered securities will be
paid at the office of the paying agent that we may designate. We will make
payment by check mailed to persons in whose names the debt securities are
registered on days specified in the indentures or any prospectus supplement.
Debt security payments in other forms will be paid at a place designated by us
and specified in a prospectus supplement.

Fully registered securities may be transferred or exchanged at the
corporate trust office of the trustee or at any other office or agency
maintained by us for these purposes, without payment of any service charge,
except for any tax or governmental charge.

DISCHARGING OUR OBLIGATIONS

Except as may otherwise be set forth in any prospectus supplement, we may
choose to either discharge our obligations on the debt securities of any series
in a legal defeasance or release ourselves from our covenant restrictions on the
debt securities of any series in a covenant defeasance. We may do so at any time
prior to the stated maturity or redemption of the debt securities of the series
if, among other conditions,

- we deposit with the trustee sufficient cash or U.S. government securities
to pay the principal, interest, any premium and any other sums due to the
stated maturity date or redemption date of the debt securities of the
series; and

- we provide an opinion of our counsel that holders of the debt securities
will not be affected for U.S. federal income tax purposes by the
defeasance.

If we choose the legal defeasance option, holders of the debt securities of
that series will not be entitled to the benefits of the indenture except for
registration of transfer and exchange of debt securities, replacement of lost,
stolen or mutilated debt securities, any required conversion or exchange of debt
securities, any required sinking fund payments and receipt of principal and
interest on the original stated due dates or specified redemption dates.

REGISTRATION OF DEBT SECURITIES; GLOBAL SECURITIES

We may issue debt securities of a series in whole or part in registered,
bearer, coupon or global form. A global security is a security, typically held
by a depository, that represents the beneficial interest of a number of
purchasers of the security.

BOOK ENTRY, DELIVERY AND FORM

Unless otherwise stated in any prospectus supplement, The Depository Trust
Company, New York, New York ("DTC") will act as depositary. Book-entry debt
securities of a series will be issued in the form of a global debt security that
will be deposited with DTC. This means that we will not issue certificates to
each holder. One global debt security will be issued to DTC who will keep a
computerized record of its participants (for example, your broker) whose clients
have purchased the debt securities. The participant will then keep a record of
its clients who purchased the debt securities. Unless it is exchanged in whole
or in part for a certificate debt security, a global debt security may not be
transferred; except that DTC, its nominees and their successors may transfer a
global debt security as a whole to one another.

Beneficial interests in global debt securities will be shown on, and
transfers of global debt securities will be made only through, records
maintained by DTC and its participants.

DTC has provided us the following information: DTC is a limited-purpose
trust company organized under the New York Banking Law, a "banking organization"
within the meaning of the New York Banking Law, a member of the United States
Federal Reserve System, a "clearing corporation" within the meaning of the New
York Uniform Commercial Code and a "clearing agency" registered under the

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provisions of Section 17A of the Securities Exchange Act of 1934. DTC holds
securities that its participants ("Direct Participants") deposit with DTC. DTC
also records the settlement among Direct Participants of securities
transactions, such as transfers and pledges, in deposited securities through
computerized records for Direct Participant's accounts. This eliminates the need
to exchange certificates. Direct Participants include securities brokers and
dealers, banks, trust companies, clearing corporations and some other
organizations.

DTC's book-entry system is also used by other organizations such as
securities brokers and dealers, banks and trust companies that work through a
Direct Participant. The rules that apply to DTC and its participants are on file
with the SEC.

DTC is owned by a number of its Direct Participants and by the New York
Stock Exchange, Inc., The American Stock Exchange, Inc. and the National
Association of Securities Dealers, Inc.

We will wire principal and interest payments to DTC's nominee. We and the
Trustee will treat DTC's nominee as the owner of the global debt securities for
all purposes. Accordingly, we, the Trustee and any paying agent will have no
direct responsibility or liability to pay amounts due on the global debt
securities to owners of beneficial interests in the global debt securities.

It is DTC's current practice, upon receipt of any payment of principal or
interest, to credit Direct Participants' accounts on the payment date according
to their respective holdings of beneficial interests in the global debt
securities as shown on DTC's records. In addition, it is DTC's current practice
to assign any consenting or voting rights to Direct Participants whose accounts
are credited with debt securities on a record date, by using an omnibus proxy.
Payments by participants to owners of beneficial interests in the global debt
securities, and voting by participants, will be governed by the customary
practices between the participants and owners of beneficial interests, as is the
case with debt securities held for the account of customers registered in
"street name." However, payments will be the responsibility of the participants
and not of DTC, the Trustee or us.

Debt securities represented by a global debt security will be exchangeable
for certificated debt securities with the same terms in authorized denominations
only if:

- DTC notifies us that it is unwilling or unable to continue as depositary
or if DTC ceases to be a clearing agency registered under applicable law
and a successor depositary is not appointed by us within 90 days; or

- We determine not to require all of the debt securities of a series to be
represented by a global debt security and notify the Trustee of our
decision.

THE TRUSTEE

The indenture will govern the duties, responsibilities and rights of the
trustee, including the following:

RESIGNATION OR REMOVAL OF TRUSTEE

Under provisions of the indenture and the Trust Indenture Act governing
trustee conflicts of interest, any uncured event of default under any series of
senior debt securities will force the trustee to resign as trustee for either
the subordinated debt securities or the senior debt securities. Also, any
uncured event of default under any series of subordinated debt securities will
force the trustee to resign as trustee for either the senior debt securities or
the subordinated debt securities. Any resignation of the trustee will require
the appointment of a successor trustee for the applicable debt securities in
accordance with the terms and conditions of the indenture.

The trustee may resign or be removed by us for one or more series of debt
securities and a successor trustee be appointed to act for that series. The
holders of a majority in aggregate principal amount of a series of debt
securities may remove the trustee for that series.

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LIMITATIONS ON TRUSTEE IF IT IS OUR CREDITOR

If the trustee becomes our creditor, the indenture will limit the trustee's
right to obtain payment of claims in some circumstances, or to realize on
certain property received in respect of those claims as security or otherwise.

ANNUAL TRUSTEE REPORT TO HOLDERS OF DEBT SECURITIES

The indenture will require the trustee to submit an annual report to the
holders of the debt securities regarding, among other things, the trustee's
eligibility to serve, the priority of the trustee's claims regarding advances
made by it and any action taken by the trustee materially affecting those debt
securities.

CERTIFICATE AND OPINIONS TO BE FURNISHED TO TRUSTEE

The indenture will provide that every application by us for action by the
trustee requires an officers' certificate and an opinion of counsel stating
that, in the opinion of the signers, we have complied with all conditions
precedent to the action.

GOVERNING LAW

The indenture and the debt securities will be governed by and construed in
accordance with the laws of the State of New York.

RATIO OF EARNINGS TO FIXED CHARGES

<TABLE>
<CAPTION>
SIX MONTHS
ENDED
JUNE 30, YEAR ENDED DECEMBER 31,
------------- ----------------------------------------
1999 1998 1998 1997 1996 1995 1994
---- ---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C> <C>
Ratio of Earnings to Fixed
Charges........................... 1.30 n/a(1) n/a(1) n/a(1) 5.06 1.88 3.52
</TABLE>

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

(1) Earnings are insufficient to cover fixed charges for the six months ended
June 30, 1998 by $2,997,000 and for the years ended December 31, 1998 and
1997 by $4,067,000 and $14,399,000, respectively.

These computations include us, EOTT Energy Operating Limited Partnership, EOTT
Energy Canada Limited Partnership and EOTT Energy Pipeline Limited Partnership,
on a consolidated basis. For these ratios, "earnings" is the amount resulting
from adding the following items:

- income from continuing operations; and

- fixed charges.

The term "fixed charges" means the sum of the following:

- interest expense; and

- an estimate of the interest within rental expenses.

DESCRIPTION OF OUR COMMON UNITS

Generally, our common units represent limited partner interests that
entitle the holders to participate in our cash distributions and to exercise the
rights or privileges available to limited partners under our partnership
agreement. For a description of the relative rights and preferences of holders
of common units, holders of subordinated units and our general partner in and to
cash distributions, together with a description of the circumstances under which
subordinated units convert into common units, see "Cash Distribution Policy."
Our limited partners are the holders of the 14,976,011 common units and the
holders of the 9,000,000 subordinated units.

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<PAGE> 56

Our outstanding common units are listed on the NYSE under the symbol "EOT."
Any additional common units we issue will also be listed on the NYSE.

The transfer agent and registrar for our common units is the First Chicago
Trust Company of New York.

MEETINGS/VOTING

Each holder of common units is entitled to one vote for each common unit on
all matters submitted to a vote of the unitholders.

STATUS AS LIMITED PARTNER OR ASSIGNEE

Except as described below under "-- Limited Liability," the common units
will be fully paid, and unitholders will not be required to make additional
capital contributions to us.

Each purchaser of common units offered by this prospectus must execute a
Transfer Application (the form of which is attached as Appendix I to this
prospectus) whereby the purchaser requests admission as a substituted limited
partner and makes representations and agrees to provisions stated in the
Transfer Application. If this action is not taken, a purchaser will not be
registered as a record holder of common units on the books of our transfer agent
or issued a common unit certificate. Purchasers may hold common units in nominee
accounts.

An assignee, pending its admission as a substituted limited partner, is
entitled to an interest in us equivalent to that of a limited partner with
respect to the right to share in allocations and distributions, including
liquidating distributions. Our general partner will vote and exercise other
powers attributable to common units owned by an assignee who has not become a
substituted limited partner at the written direction of the assignee.
Transferees who do not execute and deliver transfer applications will be treated
neither as assignees nor as record holders of common units and will not receive
cash distributions, federal income tax allocations or reports furnished to
record holders of common units. The only right the transferees will have is the
right to admission as a substituted limited partner in respect of the
transferred common units upon execution of a transfer application in respect of
the common units. A nominee or broker who has executed a transfer application
with respect to common units held in street name or nominee accounts will
receive distributions and reports pertaining to its common units.

LIMITED LIABILITY

Assuming that a limited partner does not participate in the control of our
business within the meaning of the Delaware Revised Uniform Limited Partnership
Act (the "Delaware Act") and that he otherwise acts in conformity with the
provisions of our partnership agreement, his liability under the Delaware Act
will be limited, subject to some possible exceptions, generally to the amount of
capital he is obligated to contribute to us in respect of his units plus his
share of any undistributed profits and assets.

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

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<PAGE> 57

REPORTS AND RECORDS

As soon as practicable, but in no event later than 120 days after the close
of each fiscal year, our general partner will furnish each unitholder of record
(as of a record date selected by our general partner) an annual report
containing our audited financial statements for the past fiscal year. These
financial statements will be prepared in accordance with generally accepted
accounting principles. In addition, no later than 90 days after the close of
each quarter, (except the fourth quarter) our general partner will furnish each
unitholder of record (as of a record date selected by our general partner) a
report containing our unaudited financial statements and any other information
required by law.

Our general partner will use all reasonable efforts to furnish each
unitholder of record information reasonably required for tax reporting purposes
within 90 days after the close of each fiscal year. Our general partner's
ability to furnish this summary tax information will depend on the cooperation
of unitholders in supplying information to our general partner. Each unitholder
will receive information to assist him in determining his U.S. federal and state
and Canadian federal and provincial tax liability and filing his U.S. federal
and state and Canadian federal and provincial income tax returns.

A limited partner can, for a purpose reasonably related to the limited
partner's interest as a limited partner, upon reasonable demand and at his own
expense, have furnished to him:

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

- a copy of our tax returns;

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

- copies of our partnership agreement, our certificate of limited
partnership, amendments to either of them and powers of attorney which
have been executed under our partnership agreement;

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

- any other information regarding our affairs as is just and reasonable.

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

CASH DISTRIBUTION POLICY

One of our principal objectives is to generate cash from our operations and
to distribute cash to our partners each quarter. We are required to distribute
to our partners 100% of our available cash each quarter. Our available cash is
defined in our partnership agreement and is generally the sum of the cash we
receive in a quarter less cash disbursements, adjusted for net changes in
reserves.

During a subordination period the holders of our common units are entitled
to receive each quarter a minimum quarterly distribution of $0.475 per unit
($1.90 annualized) prior to any distribution of available cash to holders of our
subordinated units. The subordination period is defined generally as the period
that will end if we have distributed at least the minimum quarterly distribution
on all outstanding units each quarter for four consecutive quarters and our
adjusted available cash constituting cash from operations, as defined in our
partnership agreement, for such four quarter period in the aggregate and each of
the last two quarters of such four quarter period was at least 110% of the
amount that would have been sufficient to enable us to distribute the minimum
quarterly distribution on all outstanding units on a fully diluted basis.

During the subordination period, our cash is distributed first 98% to the
holders of common units and 2% to our general partner until there has been
distributed to the holders of common units an amount equal

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<PAGE> 58

to the minimum quarterly distribution and any arrearages. Any additional cash is
distributed 98% to the holders of subordinated units and 2% to our general
partner until there has been distributed to the holders of subordinated units an
amount equal to the minimum quarterly distribution. If the subordination period
ends, the rights of the holders of subordinated units will no longer be
subordinated to the rights of the holders of common units and such units may be
converted into common units.

Our general partner is entitled to incentive distributions if the amount we
distribute with respect to any quarter exceeds levels specified in our
partnership agreement. Under the quarterly, incentive distribution provisions,
generally our general partner is entitled to 15% of amounts we distribute in
excess of $0.525 per common unit, 25% of amounts we distribute in excess of
$0.625 per common unit and 50% of amounts we distribute in excess of $0.725 per
common unit.

The minimum quarterly distribution and the amounts that trigger incentive
distributions at various levels are subject to adjustment, as described in our
partnership agreement. Our partnership agreement characterizes cash
distributions as either distributions of cash from operations or distributions
of cash from interim capital transactions. Generally, cash from operations
refers to cash generated by the operation of our business after deducting
related cash expenditures, reserves, debt service and other items specified in
our partnership agreement, and cash from interim capital transactions refers to
cash generated from borrowings, sales of debt and equity securities and sales or
other dispositions of assets for cash, with some exceptions. To avoid the
difficulty of trying to determine whether available cash distributed is cash
from operations or cash from interim capital transactions, our partnership
agreement provides that all cash distributed will be considered cash from
operations unless the amount distributed exceeds the cash generated from our
operations since June 30, 1995. Any excess will be considered cash from interim
capital transactions. We do not anticipate that we will distribute significant
amounts of cash from interim capital transactions, but if we do distribute cash
from interim capital transactions the distribution will be treated as a return
of capital, and the minimum quarterly distribution amount and the amounts that
trigger incentive distributions will be adjusted downward. In that case the
adjusted minimum quarterly distribution will be $0.475 multiplied by a fraction,
the numerator of which is $20 less the total per unit cash from interim capital
transactions distributed and the denominator of which is $20. The amounts that
trigger incentive distributions at various levels will also be adjusted to the
levels described above multiplied by the same fraction.

Enron has committed to contribute to us up to $29 million ($26.5 million of
which remains available) if necessary to support our ability to pay the minimum
quarterly distribution on our common units with respect to quarters ending on or
prior to December 31, 2001. In exchange for contributions under Enron's support
obligation, we will issue additional partnership interests that are not entitled
to cash distributions or voting rights. These additional partnership interests
must be redeemed by us, at Enron's option, with any available cash in excess of
the amount needed to pay the minimum quarterly distribution on all units plus
any arrearages in the minimum quarterly distribution on common units during the
subordination period. After Enron's obligation to provide distribution support
expires, actual quarterly distributions of available cash will depend solely on
our performance.

DESCRIPTION OF OUR PARTNERSHIP AGREEMENT

The following is a summary of the material provisions of our partnership
agreement. Our partnership agreement and all amendments thereto have been filed
as exhibits to our Form 10-K, which is incorporated by reference in this
prospectus. The following provisions of our partnership agreement are summarized
elsewhere in this prospectus:

- distributions of our available cash are described under "Cash
Distribution Policy;"

- allocations of taxable income and other tax matters are described under
"Tax Considerations;" and

- rights of holders of common units, are described under "Description of
Our Common Units."

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<PAGE> 59

PURPOSE

Our purpose under our partnership agreement is limited to serving as the
limited partner of our operating partnerships and engaging in any business
activities that may be engaged in by our operating partnership or that is
approved by our general partner. The partnership agreements of our operating
partnerships provide that they may engage in any activity that was engaged in by
our predecessors at the time of our initial public offering or reasonably
related thereto and any other activity approved by our general partner.

POWER OF ATTORNEY

Each limited partner, and each person who acquires a unit from a unitholder
and executes and delivers a transfer application, grants to our general partner
and, if appointed, a liquidator, a power of attorney to, among other things,
execute and file documents required for our qualification, continuance or
dissolution. The power of attorney also grants the authority for the amendment
of, and to make consents and waivers under, our partnership agreement.

CAPITAL CONTRIBUTIONS

Unitholders are not obligated to make additional capital contributions,
except as described below under "Description of Our Common Units -- Limited
Liability."

REIMBURSEMENT OF OUR GENERAL PARTNER

Our general partner does not receive any compensation for its services as
our general partner. It is, however, entitled to be reimbursed for all of its
costs incurred in managing and operating our business. Our partnership agreement
provides that our general partner will determine the expenses that are allocable
to us in any reasonable manner determined by our general partner in its sole
discretion.

ISSUANCE OF ADDITIONAL SECURITIES

Our partnership agreement authorizes us to issue an unlimited number of
additional limited partner interests and other equity securities that are equal
in rank with or junior to our common units on terms and conditions established
by our general partner in its sole discretion without the approval of any
limited partners. During the subordination period, however, except as set forth
in the following paragraph, we may not issue an aggregate of more than
approximately 10 million additional common units or an equivalent number of
units that are equal in rank with our common units, in each case, without the
approval of the holders of at least two-thirds of our outstanding common units.

During the subordination period, we may issue an unlimited number of common
units to finance an acquisition or a capital improvement that would have
resulted, on a pro forma basis, in an increase in per unit adjusted available
cash constituting cash from operations, as provided in our partnership
agreement.

In no event may we issue partnership interests that are senior to our
common units without the approval of the holders of at least two-thirds of our
outstanding common units.

It is possible that we will fund acquisitions through the issuance of
additional common units or other equity securities. Holders of any additional
common units we issue will be entitled to share equally with the then-existing
holders of common units in our cash distributions. In addition, the issuance of
additional partnership interests may dilute the value of the interests of the
then-existing holders of common units in our net assets.

In accordance with Delaware law and the provisions of our partnership
agreement, we may also issue additional partnership interests that, in the sole
discretion of our general partner, may have special voting rights to which
common units are not entitled.

Our general partner has the right, which it may from time to time assign in
whole or in part to any of its affiliates, to purchase common units,
subordinated units or other equity securities whenever, and on the
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<PAGE> 60

same terms that, we issue those securities to persons other than our general
partner and its affiliates, to the extent necessary to maintain their percentage
interests in us that existed immediately prior to the issuance. The holders of
common units will not have preemptive rights to acquire additional common units
or other partnership interests in us.

AMENDMENTS TO OUR PARTNERSHIP AGREEMENT

Amendments to our partnership agreement may be proposed only by our general
partner. In general, proposed amendments must be approved by holders of at least
two-thirds of our outstanding units. However, in some limited circumstances,
more particularly described in our partnership agreement, our general partner
may make amendments to our partnership agreement without the approval of our
limited partners or assignees.

Any amendment that materially and adversely affects the rights or
preferences of any type or class of limited partner interests in relation to
other types of classes of limited partner interest or our general partner
interest will require the approval of at least a majority of the type or class
of limited partner interest so affected (excluding any limited partner interests
held by our general partner or its affiliates).

WITHDRAWAL OR REMOVAL OF OUR GENERAL PARTNER

Except as described below, our general partner has agreed not to withdraw
voluntarily as our general partner prior to April 1, 2004 without obtaining the
approval of the holders of at least two-thirds of our outstanding units,
excluding those held by our general partner and its affiliates, and furnishing
an opinion of counsel regarding limited liability and tax matters. On or after
April 1, 2004, our general partner may withdraw as general partner without first
obtaining approval of any unitholder by giving 90 days' written notice, and that
withdrawal will not constitute a violation of our partnership agreement. In
addition, our general partner may withdraw without unitholder approval upon 90
days' notice to our limited partners if at least 50% of our outstanding common
units are held or controlled by one person and its affiliates other than our
general partner and its affiliates. In addition, our partnership agreement
permits our general partner in some limited instances to sell or otherwise
transfer all of its general partner interest without the approval of our
unitholders. There are no restrictions on Enron's ability to sell the capital
stock of our general partner.

Upon the withdrawal of our general partner under any circumstances, the
holders of a majority of our outstanding units (other than those owned by the
withdrawing general partner), may select a successor to that withdrawing general
partner. If a successor is not elected, or is elected but an opinion of counsel
regarding limited liability and tax matters cannot be obtained, we will be
dissolved, wound up and liquidated, unless within 180 days after that
withdrawal, the holders of a majority of our outstanding units agree in writing
to continue our business and to appoint a successor general partner.

Our general partner may not be removed unless that removal is approved by
the vote of the holders of not less than two-thirds of our outstanding units,
excluding units held by our general partner and its affiliates, and we receive
an opinion of counsel regarding limited liability and tax matters. Any removal
of this kind is also subject to the approval of a successor general partner by
the vote of the holders of a majority of our outstanding units, excluding those
held by our withdrawing general partner and its affiliates.

Our partnership agreement also provides that if our general partner is
removed under circumstances where cause does not exist, the subordination period
will end, any outstanding additional partnership interests will be redeemable at
Enron's option and Enron's obligation to support distributions on common units
will terminate.

LIQUIDATION AND DISTRIBUTION OF PROCEEDS

Upon our dissolution, unless we are reconstituted and continued as a new
limited partnership, the person authorized to wind up our affairs (the
liquidator) will, acting with all the powers of our general

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<PAGE> 61

partner that the liquidator deems necessary or desirable in its good faith
judgment, liquidate our assets. The proceeds of the liquidation will be applied
as follows: (i) first, towards the payment of all of our creditors and the
creation of a reserve for contingent liabilities and (ii) then, to all partners
in accordance with the positive balance in the respective capital accounts.
Under some circumstances and subject to some limitations, the liquidator may
defer liquidation or distribution of our assets for a reasonable period of time.
If the liquidator determines that a sale would be impractical or would cause
loss to the partners, our general partner may distribute assets to partners in
kind.

CHANGE OF MANAGEMENT PROVISIONS

Our partnership agreement contains specific provisions that are intended to
discourage a person or group from attempting to remove our general partner or
otherwise change management.

LIMITED CALL RIGHT

If at any time our general partner and its affiliates own 80% or more of
the issued and outstanding limited partner interests of any class, our general
partner will have the right to purchase all, but not less than all, of the
outstanding limited partner interests of that class that are held by
non-affiliated persons. The record date for determining ownership of the limited
partner interests would be selected by our general partner on at least 10 but
not more than 60 days' notice. The purchase price in the event of a purchase
under these provisions would be the greater of (i) the current market price (as
defined in our partnership agreement) of the limited partner interests of the
class as of the date five days prior to the mailing of written notice of its
election to purchase the units and (ii) the highest cash price paid by our
general partner or any of its affiliates for any limited partner interest of the
class purchased within the 90 days preceding the date our general partner mails
notice of its election to purchase the units.

INDEMNIFICATION

Under our partnership agreement, in most circumstances, we will indemnify
our general partner, its affiliates and their officers and directors to the
fullest extent permitted by law, from and against all losses, claims or damages
any of them may suffer by reason of their status as general partner, officer or
director, as long as the person seeking indemnity acted in good faith and in a
manner believed to be in or not opposed to our best interest. Any
indemnification under these provisions will only be out of our assets. Our
general partner shall not be personally liable for, or have any obligation to
contribute or loan funds or assets to us to enable us to effectuate
indemnification. We are authorized to purchase insurance against liabilities
asserted against and expenses incurred by persons for our activities, regardless
of whether we would have the power to indemnify the person against liabilities
under our partnership agreement.

REGISTRATION RIGHTS

Under our partnership agreement, we have agreed to register for resale
under the Securities Act and applicable state securities laws any common units,
subordinated units or other partnership securities proposed to be sold by our
general partner or any of its affiliates or their assignees if an exemption from
the registration requirements is not otherwise available. We are obligated to
pay all expenses incidental to the registration, excluding underwriting
discounts and commissions.

TAX CONSIDERATIONS

This section is a summary of all of the material federal income tax
considerations that may be relevant to you and, to the extent set forth below
under "-- Legal Opinions and Advice," represents the opinion of our counsel
Vinson & Elkins L.L.P. ("Counsel"), insofar as it relates to matters of United
States federal income tax law and legal conclusions. This section is based upon
current provisions of the Internal Revenue Code of 1986 (the "Code"), existing
and proposed regulations thereunder and current administrative rulings and court
decisions, all of which are subject to change. Subsequent changes may cause the
tax consequences to vary substantially from the consequences described below.
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<PAGE> 62

We have made no attempt in the following discussion to comment on all
federal income tax matters affecting our unitholders or us. Moreover, the
discussion focuses on our unitholders who are individual citizens or residents
of the United States and has only limited application to corporations, estates,
trusts or non-resident aliens. Accordingly, you should consult, and should
depend on, your own tax advisor in analyzing the federal, state, local and
foreign tax consequences to you of the ownership or disposition of common units.

LEGAL OPINIONS AND ADVICE

Counsel has expressed its opinion that, based on the accuracy of
representations and subject to the qualifications set forth in the detailed
discussion that follows, for federal income tax purposes: we and our operating
limited partnerships will each be treated as a partnership; and owners of common
units (with some exceptions, as described in "-- Limited Partner Status" below)
will be treated as our partners (but not partners of the operating limited
partnerships). In addition, all statements as to matters of law and legal
conclusions contained in this section, unless otherwise noted, reflect the
opinion of Counsel. Counsel has also advised us that, based on current law, the
following general description of the principal federal income tax consequences
that should arise from the ownership and disposition of common units, insofar as
it relates to matters of law and legal conclusions, addresses all material tax
consequences to our unitholders who are individual citizens or residents of the
United States.

We have not requested any ruling from the Internal Revenue Service (the
"IRS") with respect to the foregoing issues or any other matter affecting our
unitholders or us. An opinion of counsel represents only counsel's best legal
judgment and does not bind the IRS or the courts. Thus, we cannot assure you
that the opinions and statements set forth in this prospectus would be sustained
by a court if contested by the IRS. The costs of any contest with the IRS will
be borne directly or indirectly by our unitholders and our general partner.
Furthermore, we cannot assure you that our treatment or an investment in us will
not be significantly modified by future legislative or administrative changes or
court decisions. Any modification may or may not be retroactively applied.

PARTNERSHIP STATUS

A partnership is not a taxable entity and incurs no federal income tax
liability. Instead, each partner is required to take into account his allocable
share of items of our income, gain, loss, deduction and credit in computing his
federal income tax liability, regardless of whether cash distributions are made.
Distributions by us to a unitholder are generally not taxable unless the amount
of any cash distributed is in excess of his adjusted basis in his partnership
interest.

Pursuant to certain Treasury Regulations effective January 1, 1997 (the
"Check-the-Box Regulations"), an entity in existence on January 1, 1997, will
generally retain its current classification for federal income tax purposes. As
of January 1, 1997, each of our operating limited partnerships and we were
classified and taxed as a partnership. Pursuant to the Check-the-Box
Regulations, this prior classification will be respected for all periods prior
to January 1, 1997, if:

- the entity had a reasonable basis for the claimed classification;

- the entity recognized the federal tax consequences of any change in
classification within five years prior to January 1, 1997; and

- the entity was not notified prior to May 8, 1996 that the entity
classification was under examination.

Based on these regulations and the applicable federal income tax law, Counsel
has opined that we and each of our operating limited partnerships have been and
will be classified as a partnership for federal income tax purposes. In
rendering its opinion, Counsel has relied on factual representations and
covenants made by our general partner and us:

- neither we nor any of our operating limited partnerships have elected or
will elect to be treated as an association taxable as a corporation;
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<PAGE> 63

- except as otherwise required by Section 704 of the Code and regulations
promulgated thereunder, our general partner has had and will have, in the
aggregate, an interest in each material item of our income, gain, loss,
deduction or credit equal to at least 1% at all times during our
existence;

- a representation and covenant of our general partner that our general
partner has and will maintain, in the aggregate, a minimum capital
account balance in us equal to 1% of our total positive capital account
balances;

- for each taxable year, less than 10% of our gross income has been and
will be derived from sources other than (i) the exploration, development,
mining or production, processing, refining, transportation or marketing
of any mineral or natural resource, including oil, gas or products
thereof and naturally occurring carbon dioxide or (ii) other items of
income as to which Counsel has opined or will opine will be "qualifying
income" within the meaning of Section 7704(d) of the Code; and

- we and each of our operating limited partnerships are organized and will
be operated in accordance with (i) all applicable partnership statutes,
(ii) its or our respective partnership agreement and (iii) its or our
description in this Registration Statement.

Counsel's opinion as to our partnership classification in the event of a change
in our general partner is based upon the assumption that the new general partner
will satisfy the foregoing representations and covenants.

Section 7704 of the Code provides that publicly-traded partnerships will,
as a general rule, be taxed as corporations. However, an exception (the "Natural
Resource Exception") exists with respect to publicly-traded partnerships 90% or
more of the gross income of which for every taxable year consists of "qualifying
income." Qualifying income includes income and gains derived from the
transportation and trading of oil and petroleum products and natural gas
processing as conducted by us. Other types of qualifying income include interest
(from other than a financial business), dividends, gains from the sale of real
property and gains from the sale or other disposition of capital assets held for
the production of income that otherwise constitutes qualifying income. We
estimate that less than 5% of our gross income is not qualifying income under
this test; however, this estimate could change from time to time. Based upon and
subject to that estimate, the factual representations made by us and the general
partner and a review of the applicable legal authorities, Counsel is of the
opinion that at least 95% of our gross income constitutes qualifying income.

If we fail to meet the Natural Resource Exception (other than a failure
determined by the IRS to be inadvertent that is cured within a reasonable time
after discovery), we will be treated as if we had transferred all of our assets
(subject to liabilities) to a newly-formed corporation (on the first day we fail
to meet the Natural Resource Exception) in return for stock in the corporation,
and then distributed the stock to our unitholders in liquidation of their
interests in us. This contribution and liquidation should be tax-free to our
unitholders and us, so long as we, at such time, do not have liabilities in
excess of the basis of our assets. Thereafter, we would be treated as a
corporation for federal income tax purposes.

If we were treated as an association or otherwise taxable as a corporation
in any taxable year, as a result of a failure to meet the Natural Resource
Exception or otherwise, our items of income, gain, loss, deduction and credit
would be reflected only on our tax return rather than being passed through to
our unitholders, and our net income would be taxed at the entity level at
corporate rates. In addition, any distribution made to our unitholders would be
treated as either taxable dividend income (to the extent of our current or
accumulated earnings and profits), in the absence of earnings and profits as a
nontaxable return of capital (to the extent of his basis in his common units) or
taxable capital gain (after his basis in the common units is reduced to zero).
Accordingly, our treatment as an association taxable as a corporation would
result in a material reduction in a unitholder's cash flow and after-tax return.

The discussion below is based on the assumption that we will be classified
as a partnership for federal income tax purposes.

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LIMITED PARTNER STATUS

Our unitholders who have become limited partners will be treated as
partners for federal income tax purposes. Moreover, the IRS has ruled that
assignees of partnership interests who have not been admitted to a partnership
as partners, but who have the capacity to exercise substantial dominion and
control over the assigned partnership interests, will be treated as partners for
federal income tax purposes. On the basis of this ruling, except as otherwise
described herein, Counsel is of the opinion that (a) assignees who have executed
and delivered Transfer Applications and are awaiting admission as limited
partners and (b) our unitholders whose common units are held in street name or
by a nominee and who have the right to direct the nominee in the exercise of all
substantive rights attendant to the ownership of their common units will be
treated as partners for federal income tax purposes. As this ruling does not
extend, on its facts, to assignees of common units who are entitled to execute
and deliver Transfer Applications and thereby become entitled to direct the
exercise of attendant rights, but who fail to execute and deliver Transfer
Applications, Counsel's opinion does not extend to these persons. Income, gain,
deductions, losses or credits would not appear to be reportable by these
unitholders, and any cash distributions received by these unitholders would
therefore be fully taxable as ordinary income. These holders should consult
their own tax advisors with respect to their status as partners for federal
income tax purposes. A purchaser or other transferee of common units who does
not execute and deliver a Transfer Application may not receive federal income
tax information or reports furnished to record holders of common units unless
the common units are held in a nominee or street name account and the nominee or
broker has executed and delivered a Transfer Application with respect to the
common units.

A beneficial owner of common units whose common units have been transferred
to a short seller to complete a short sale would appear to lose his status as a
partner for federal income tax purposes with respect to the common units sold
short. See "-- Tax Treatment of Our Operations -- Treatment of Short Sales."

TAX CONSEQUENCES OF COMMON UNIT OWNERSHIP

FLOW-THROUGH OF TAXABLE INCOME

We will pay no federal income tax. Instead, each of our unitholders will be
required to report on his income tax return his allocable share of our income,
gains, losses and deductions without regard to whether corresponding cash
distributions are received by him. Consequently, we may allocate income to our
unitholders although they have not received a cash distribution in respect of
that income.

TREATMENT OF PARTNERSHIP DISTRIBUTIONS

Our distributions to any of our unitholders will not be taxable for federal
income tax purposes to the extent of his basis in his common units immediately
before the distribution. Cash distributions in excess of a common unitholder's
basis generally will be considered to be gain from the sale or exchange of the
common units, taxable in accordance with the rules described under "-- Tax
Consequences of Common Unit Ownership -- Disposition of Common Units." Any
reduction in a common unitholder's share of our liabilities for which no
partner, including our general partner, bears the economic risk of loss
("nonrecourse liabilities") will be treated as a distribution of cash to that
unitholder.

BASIS OF COMMON UNITS

A unitholder's initial tax basis for his common units will be the amount
paid for the common unit plus his share of our nonrecourse liabilities. The
initial tax basis for a common unit will be increased by the unitholder's share
of our income and by any increase in the unitholder's share of our nonrecourse
liabilities. The basis for a common unit will be decreased (but not below zero)
by our distributions, including any decrease in the unitholder's share of our
nonrecourse liabilities, by the unitholder's share of our losses and by the
unitholder's share of our expenditures that are not deductible in computing his
taxable income and are not required to be capitalized. A unitholder's share of
our nonrecourse liabilities will be generally based on the unitholder's share of
our profits.

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LIMITATIONS ON DEDUCTIBILITY OF OUR LOSSES

To the extent we incur losses, a unitholder's share of deductions for the
losses will be limited to the tax basis of the unitholder's common units or, in
the case of an individual unitholder or a corporate unitholder if more than 50%
of the value of his stock is owned directly or indirectly by five or fewer
individuals or some tax-exempt organizations, to the amount that the unitholder
is considered to be "at risk" with respect to our activities, if that is less
than the unitholder's basis. A unitholder must recapture losses deducted in
previous years to the extent that our distributions cause the unitholder's at
risk amount to be less than zero at the end of any taxable year. Losses
disallowed to a unitholder or recaptured as a result of these limitations will
carry forward and will be allowable to the extent that the unitholder's basis or
at risk amount (whichever is the limiting factor) is increased.

In general, a unitholder will be at risk to the extent of the purchase
price of his common units, but this will be less than the unitholder's basis for
his common units by the amount of the unitholder's share of any of our
nonrecourse liabilities. A unitholder's at risk amount will increase or decrease
as the basis of the unitholder's common units increases or decreases except that
changes in our nonrecourse liabilities will not increase or decrease the at risk
amount.

The passive loss limitations generally provide that individuals, estates,
trusts and some closely held corporations and personal service corporations can
only deduct losses from passive activities (generally, activities in which the
taxpayer does not materially participate) that are not in excess of the
taxpayer's income from passive activities or investments. The passive loss
limitations are applied separately with respect to each publicly-traded
partnership. Consequently, any losses generated by us will only be available to
offset future income that we generate and will not be available to offset income
from other passive activities or investments (including other publicly-traded
partnerships) or salary or active business income. Passive losses that are not
deductible because they exceed the unitholder's income that we generate may be
deducted in full when the unitholder disposes of his entire investment in us in
a fully taxable transaction to an unrelated party. The passive activity loss
rules are applied after other applicable limitations on deductions such as the
at risk rules and the basis limitation.

A unitholder's share of our net income may be offset by any of our
suspended passive losses, but it may not be offset by any other current or
carryover losses from other passive activities, including those attributable to
other publicly-traded partnerships. The IRS has announced that Treasury
Regulations will be issued that characterize net passive income from a
publicly-traded partnership as investment income for purposes of the limitations
on the deductibility of investment interest.

LIMITATIONS ON INTEREST DEDUCTIONS

The deductibility of a non-corporate taxpayer's "investment interest
expense" is generally limited to the amount of the taxpayer's "net investment
income." As noted, a unitholder's share of our net passive income will be
treated as investment income for this purpose. In addition, the unitholder's
share of our portfolio income will be treated as investment income. Investment
interest expense includes:

- interest on indebtedness properly allocable to property held for
investment;

- our interest expense attributed to portfolio income; and

- the portion of interest expense incurred to purchase or carry an interest
in a passive activity to the extent attributable to portfolio income.

The computation of a unitholder's investment interest expense will take
into account interest on any margin account borrowing or other loan incurred to
purchase or carry a common unit to the extent attributable to his portfolio
income. Net investment income includes gross income from property held for
investment, gain attributable to the disposition of property held for investment
and amounts treated as portfolio income pursuant to the passive loss rules less
deductible expenses (other than interest) directly connected with the production
of investment income.

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ALLOCATION OF OUR INCOME, GAIN, LOSS AND DEDUCTION

Our partnership agreement provides that a capital account be maintained for
each partner, that the capital accounts generally be maintained in accordance
with the applicable tax accounting principles set forth in applicable Treasury
Regulations and that all allocations to a partner be reflected by an appropriate
increase or decrease in his capital account. Distributions upon our liquidation
are generally to be made in accordance with positive capital account balances.

In general, if we have a net profit, items of income, gain, loss and
deduction will be allocated among our general partner and our unitholders in
accordance with their respective percentage interests in us. A class of our
unitholders that receives more cash than another class, on a per unit basis,
with respect to a year, will be allocated additional income equal to that
excess. If we have a net loss, items of income, gain, loss and deduction will
generally be allocated for both book and tax purposes (1) first, to our general
partner and our unitholders in accordance with their respective percentage
interests to the extent of their positive capital accounts and (2) second, to
our general partner.

Notwithstanding the above, as required by Section 704(c) of the Code, some
items of our income, deduction, gain and loss will be specially allocated to
account for the difference between the tax basis and fair market value of
property contributed to us ("Contributed Property") or owned by us at the time
new units are sold by us ("Adjusted Property"). In addition, some items of
recapture income will be allocated to the extent possible to the partner
allocated the deduction giving rise to the treatment of the gain as recapture
income in order to minimize the recognition of ordinary income by some of our
unitholders. Although we believe that these allocations will be respected under
recently adopted Treasury Regulation, if they are not respected, the amount of
the income or gain allocated to a unitholder will not change, but instead a
change in the character of the income allocated to a unitholder would result.
Finally, although we do not expect that our operations will result in the
creation of negative capital accounts, if negative capital accounts nevertheless
result, items of our income and gain will be allocated in an amount and manner
sufficient to eliminate the negative balance as quickly as possible.

Regulations provide that an allocation of items of our income, gain, loss,
deduction or credit, other than an allocation required by Section 704(c) of the
Code to eliminate the disparity between a partner's "book" capital account
(credited with the fair market value of Contributed Property and credited or
debited with any gain or loss attributable to an Adjusted Property) and "tax"
capital account (credited with the tax basis of Contributed Property) (the
"Book-Tax Disparity"), will generally be given effect for federal income tax
purposes in determining a partner's distributive share of an item of income,
gain, loss or deduction only if the allocation has substantial economic effect.
In any other case, a partner's distributive share of an item will be determined
on the basis of the partner's interest in us, which will be determined by taking
into account all the facts and circumstances, including the partner's relative
contributions to us, the interests of the partners in economic profits and
losses, the interests of the partners in cash flow and other non-liquidating
distributions and rights of the partners to distributions of capital upon
liquidation.

Under the Code, the partners in a partnership cannot be allocated more
depreciation, gain or loss than the total amount of the item recognized by that
partnership in a particular taxable period. This rule, often referred to as the
"ceiling limitation," is not expected to have significant application to
allocations with respect to Contributed Properties or Adjusted Properties and
thus, is not expected to prevent our unitholders from receiving allocations of
depreciation, gain or loss from our properties equal to that which they would
have received had our properties actually had a basis equal to fair market value
at the outset or at the time new units are issued by us. However, to the extent
the ceiling limitation is or becomes applicable, our partnership agreement
requires that some items of income and deduction be allocated in a way designed
to effectively "cure" this problem and eliminate the impact of the ceiling
limitations. These allocations will not have substantial economic effect because
they will not be reflected in the capital accounts of our unitholders.

The legislative history of Section 704(c) states that Congress anticipated
that Treasury Regulations would permit partners to agree to a more rapid
elimination of Book-Tax Disparities than required provided there is no tax
avoidance potential. Further, under Treasury Regulations under Section 704(c),
allocations
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similar to the curative allocations would be allowed. However, since the final
Treasury Regulations are not applicable to us, Counsel is unable to opine on the
validity of the curative allocations.

Counsel is of the opinion that, with the exception of curative allocations
and the allocation of recapture income discussed above and the deduction for
amortizable goodwill discussed below (see "-- Tax Treatment of Our
Operations -- Initial Tax Basis, Depreciation and Amortization"), allocations
under our partnership agreement will be given effect for federal income tax
purposes in determining a partner's distributive share of an item of income,
gain, loss or deduction. There are, however, uncertainties in the Treasury
Regulations relating to allocations of partnership income, and investors should
be aware that some of the allocations in our partnership agreement may be
successfully challenged by the IRS.

TAX TREATMENT OF OUR OPERATIONS

Accounting Method and Taxable Year

We use the calendar year as our taxable year and adopt the accrual method
of accounting for federal income tax purposes.

Initial Tax Basis, Depreciation and Amortization

The tax basis established for our various assets will be used for purposes
of computing depreciation and cost recovery deductions and, ultimately, gain or
loss on the disposition of those assets. Our assets initially had an aggregate
tax basis equal to the sum of each unitholder's tax basis in his common units or
subordinated units and the tax basis of our general partner in its general
partner interest.

The IRS may challenge the method adopted by us to allocate this aggregate
tax basis among our assets and our treatment of certain amortizable intangible
assets. The IRS may (i) challenge either the fair market values or the useful
lives assigned to our assets or (ii) seek to characterize intangible assets as
non-amortizable goodwill. If the challenge or characterization were successful,
the deductions allocated to a common unitholder in respect of our assets would
be reduced, and a unitholder's share of taxable income received from us would be
increased accordingly. Any increase could be material.

To the extent allowable, our general partner may elect to use the
depreciation and cost recovery methods that will result in the largest
depreciation deductions in our early years. Property that we subsequently
acquire or construct may be depreciated using accelerated methods permitted by
the Code.

If we dispose of depreciable property by sale, foreclosure or otherwise,
all or a portion of any gain (determined by reference to the amount of
depreciation previously deducted and the nature of the property) may be subject
to the recapture rules and taxed as ordinary income rather than capital gain.
Similarly, a partner who has taken cost recovery or depreciation deductions with
respect to property owned by us may be required to recapture deductions upon a
sale of his interest. See "-- Tax Consequences of Common Unit
Ownership -- Allocation of Our Income, Gain, Loss and Deduction" and "-- Tax
Consequences of Common Unit Ownership -- Disposition of Common
Units -- Recognition of Gain or Loss."

Costs we incurred in organizing may be amortized over any period we select
not shorter than 60 months. The costs incurred in promoting the issuance of
units must be capitalized and cannot be deducted currently, ratably or upon our
termination. There are uncertainties regarding the classification of costs as
organization expenses, that may be amortized, and as syndication expenses which
may not be amortized.

Section 754 Election

We previously made the election permitted by Section 754 of the Code. This
election is irrevocable without the consent of the IRS. The election generally
permits a purchaser of common units to adjust his share of the basis in our
properties ("inside basis") pursuant to Section 743(b) of the Code to fair
market value (as reflected by his common unit price). See "Tax
Considerations -- Allocation of Our Income,

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Gain, Loss and Deduction." The Section 743(b) adjustment is attributed solely to
a purchaser of units and is not added to the basis of our assets associated with
all of our unitholders. (For purposes of this discussion, a partner's inside
basis in our assets will be considered to have two components: (1) his share of
our actual basis in our assets (the "Common Basis"); and (2) his Section 743(b)
adjustment allocated to each of our assets.)

Proposed Treasury Regulation Section 1.197-2(g)(3) generally requires that
the 743(b) adjustment attributable to amortizable intangible assets under
Section 197 should be treated as a newly-acquired asset placed in service on the
date when the transfer occurs. Under Treasury Regulation Section 1.167(c)-
1(a)(6), a Section 743(b) adjustment attributable to property subject to
depreciation under Section 167 of the Code rather than cost recovery deductions
under Section 168 is generally required to be depreciated using either the
straight-line method or the 150% declining balance method. We intend to utilize
the 150% declining balance method on our property subject to depreciation under
Section 167. Although the proposed regulations under Section 743 will likely
eliminate many of the problems if finalized in their current form, the
depreciation method and useful lives associated with the Section 743(b)
adjustment may differ from the method and useful lives generally used to
depreciate the Common Basis in our properties. Pursuant to our partnership
agreement, our general partner is authorized to adopt a convention to preserve
the uniformity of common units even if that convention is not consistent with
Treasury Regulation Section 1.167(c)-1(a)(6) or 1.197-2(g)(3). See "-- Tax
Consequences of Common Unit Ownership -- Uniformity of Common Units."

Although Counsel is unable to opine as to the validity of this approach, we
intend to depreciate the portion of a Section 743(b) adjustment attributable to
unrealized appreciation in the value of Contributed Property or Adjusted
Property (to the extent of any unamortized Book-Tax Disparity) using a rate of
depreciation or amortization derived from the depreciation or amortization
method and useful life applied to the Common Basis of our property. This method
is consistent with the proposed regulations under Section 743 but is arguably
inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6) or Proposed
Treasury Regulation Section 1.197-2(g)(3). To the extent that the Section 743(b)
adjustment is attributable to appreciation in value in excess of the unamortized
Book-Tax Disparity, we will apply the rules described in the Treasury
Regulations and legislative history. If we determine that this position cannot
reasonably be taken, we may adopt a depreciation or amortization convention
under which all purchasers acquiring common units in the same month would
receive depreciation or amortization, whether attributable to the Common Basis
or the Section 743(b) basis, based upon the same applicable rate as if they had
purchased a direct interest in our property. This aggregate approach may result
in lower annual depreciation or amortization deductions than would otherwise be
allowable to some of our unitholders. See "-- Tax Consequences of Common Unit
Ownership -- Uniformity of Common Units."

The allocation of the Section 743(b) adjustment must be made in accordance
with the principles of Section 1060 of the Code. Based on these principles, the
IRS may seek to reallocate some or all of any Section 743(b) adjustment not so
allocated by us to goodwill. Alternatively, it is possible that the IRS may seek
to treat the portion of the Section 743(b) adjustment attributable to the
Underwriter's discount as if allocable to a non-deductible syndication cost.

A Section 754 election is advantageous if the transferee's basis in his
common units is higher than his common units' share of the aggregate basis of
our assets immediately prior to the transfer. In that case, pursuant to the
election, the transferee would take a new and higher basis in his share of our
assets for purposes of calculating, among other items, his depreciation
deductions and his share of any gain or loss on a sale of our assets.
Conversely, a Section 754 election is disadvantageous if the transferee's basis
in his common units is lower than his common units' share of the aggregate basis
of our assets immediately prior to the transfer. Thus, the amount that a
unitholder will be able to obtain upon the sale of his common units may be
affected either favorably or adversely by the election.

The calculations involved in the Section 754 election are complex and we
will make them on the basis of some assumptions as to the value of our assets
and other matters. There is no assurance that the determinations we make will
not be successfully challenged by the IRS and that the deductions

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attributable to them will not be disallowed or reduced. Should the IRS require a
different basis adjustment to be made, and should, in our general partner's
opinion, the expense of compliance exceed the benefit of the election, our
general partner may seek permission from the IRS to revoke our Section 754
election. If permission is granted, a purchaser of common units subsequent to
the revocation probably will incur increased tax liability.

Alternative Minimum Tax

Each unitholder will be required to take into account his distributive
share of any items of our income, gain or loss for purposes of the alternative
minimum tax. A portion of our depreciation deductions may be treated as an item
of tax preference for this purpose.

A unitholder's alternative minimum taxable income derived from us may be
higher than his share of our net income because we may use more accelerated
methods of depreciation for purposes of computing federal taxable income or
loss. The minimum tax rate for individuals is 26% on the first $175,000 of
alternative minimum taxable income in excess of the exemption amount and to 28%
on any additional alternative minimum taxable income. You should consult with
your tax advisors as to the impact of an investment in common units on your
liability under the alternative minimum tax.

Valuation of Our Property

The federal income tax consequences of the ownership and disposition of
common units will depend in part on our estimates of the relative fair market
values, and determinations of the initial tax basis, of our assets. Although we
may from time to time consult with professional appraisers with respect to
valuation matters, many of the relative fair market value estimates will be made
solely by us. These estimates are subject to challenge and will not be binding
on the IRS or the courts. In the event the determinations of fair market value
are subsequently found to be incorrect, the character and amount of items of
income, gain, loss, deductions or credits previously reported by our unitholders
might change, and our unitholders might be required to amend their previously
filed tax returns or to file claims for refunds.

Treatment of Short Sales

A unitholder who engages in a short sale (or a transaction having the same
effect) with respect to common units will be required to recognize the gain (but
not the loss) inherent in the common units that are sold short. See "-- Tax
Consequences of Common Unit Ownership -- Disposition of Common Units." In
addition, it would appear that a unitholder whose common units are loaned to a
"short seller" to cover a short sale of common units would be considered as
having transferred beneficial ownership of those common units and would, thus,
no longer be a partner with respect to those common units during the period of
the loan. As a result, during this period, any of our income, gain, deduction,
loss or credit with respect to those common units would appear not to be
reportable by the unitholder, any cash distributions received by the unitholder
with respect to those common units would be fully taxable and all of those
distributions would appear to be treated as ordinary income. The IRS may also
contend that a loan of common units to a "short seller" constitutes a taxable
exchange. If the IRS successfully made this contention, the lending unitholder
may be required to recognize gain or loss. Unitholders desiring to assure their
status as partners should modify any of their brokerage account agreements to
prohibit their brokers from borrowing their common units.

DISPOSITION OF COMMON UNITS

Recognition of Gain or Loss

Gain or loss will be recognized on a sale of common units equal to the
difference between the amount realized and the unitholder's tax basis for the
common units sold. A unitholder's amount realized will be measured by the sum of
the cash or the fair market value of other property received plus his share of
our nonrecourse liabilities. Since the amount realized includes a unitholder's
share of our nonrecourse

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liabilities, the gain recognized on the sale of common units may result in a tax
liability in excess of any cash received from the sale.

Gain or loss recognized by a unitholder (other than a "dealer" in common
units) on the sale or exchange of a common unit held for more than twelve months
will generally be taxable as long-term capital gain or loss. A substantial
portion of this gain or loss, however, will be separately computed and taxed as
ordinary income or loss under section 751 of the Code to the extent attributable
to assets giving rise to depreciation recapture or other "unrealized
receivables" or to inventory we own. The term "unrealized receivables" includes
potential recapture items, including depreciation recapture. Ordinary income
attributable to unrealized receivables, inventory and deprecation recapture may
exceed net taxable gain realized upon the sale of the common unit and may be
recognized even if there is a net taxable loss realized upon the sale of the
common unit. Any loss recognized on the sale of common units will generally be a
capital loss. Thus, a unitholder may recognize both ordinary income and a
capital loss upon a disposition of common units. Net capital loss may offset no
more than $3,000 of ordinary income in the case of individuals and may only be
used to offset capital gain in the case of a corporation.

The IRS has ruled that a partner acquiring interests in a partnership in
separate transactions at different prices must maintain an aggregate adjusted
tax basis in a single partnership interest and that, upon sale or other
disposition of some of the interests, a portion of the aggregate tax basis must
be allocated to the interests sold on the basis of some equitable apportionment
method. This ruling is unclear as to how the holding period is affected by this
aggregation concept. If this ruling is applicable to you, the aggregation of
your tax basis effectively prohibits you from choosing among common units with
varying amounts of unrealized gain or loss as would be possible in a stock
transaction. Thus, the ruling may result in an acceleration of gain or deferral
of loss on a sale of a portion of your common units. It is not clear whether the
ruling applies to publicly-traded partnerships, such as us, the interests in
which are evidenced by separate interests, and accordingly Counsel is unable to
opine as to the effect this ruling will have on you. If you are considering the
purchase of additional common units or a sale of common units purchased at
differing prices, you should consult your tax advisor as to the possible
consequences of this ruling.

Allocations Between Transferors and Transferees

In general, our taxable income and losses will be determined annually and
will be prorated on a monthly basis and subsequently apportioned among our
unitholders in proportion to the number of common units they owned as of the
close of business on the last day of the preceding month. However, gain or loss
realized on a sale or other disposition of our assets other than in the ordinary
course of business will be allocated among our unitholders of record as of the
opening of the New York Stock Exchange on the first business day of the month in
which the gain or loss is recognized. As a result of this allocation procedure,
a unitholder transferring common units in the open market may be allocated
income, gain, loss, deduction, and credit accrued after the transfer.

The use of the allocation procedure discussed above may not be permitted by
existing Treasury Regulations and, accordingly, Counsel is unable to opine on
the validity of the method of allocating income and deductions between the
transferors and the transferees of common units. If an allocation procedure is
not allowed by the Treasury Regulations (or only applies to transfers of less
than all of a unitholder's interest), our taxable income or losses might be
reallocated among our unitholders. We are authorized to revise our method of
allocation between transferors and transferees (as well as among partners whose
interests otherwise vary during a taxable period) to conform to a method
permitted by future Treasury Regulations.

A unitholder who owns common units at any time during a quarter and who
disposes of his common units prior to the record date set for a distribution
with respect to that quarter will be allocated items of our income and gain
attributable to the quarter during which his common units were owned but will
not be entitled to receive cash distributions with respect to that quarter.

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Notification Requirements

A unitholder who sells or exchanges common units is required to notify us
in writing of the sale or exchange within 30 days of the sale or exchange and,
in any event, no later than January 15 of the year following the calendar year
that the sale or exchange occurred. We are required to notify the IRS of the
transaction and to furnish specific information to the transferor and
transferee. However, these reporting requirements do not apply with respect to a
sale by an individual who is a citizen of the United States and who effects the
sale through a broker. Additionally, a transferor and a transferee of a common
unit will be required to furnish statements to the IRS, filed with their income
tax returns for the taxable year in which the sale or exchange occurred, that
set forth the amount of the consideration received for the common unit that is
allocated to our goodwill or going concern value. Failure to satisfy these
reporting obligations may lead to the imposition of substantial penalties.

Constructive Termination

We will be considered to be terminated if there is a sale or exchange of
50% or more of the total interests in partnership capital and profits within a
12-month period. A constructive termination results in the closing of a
partnership's taxable year for all partners. A termination could result in the
non-uniformity of common units for federal income tax purposes. Our constructive
termination will cause a termination of our operating limited partnerships. A
termination could also result in penalties or loss of basis adjustments under
the Code if we were unable to determine that the termination had occurred.

In the case of a unitholder reporting on a fiscal year other than a
calendar year, the closing of our tax year may result in more than 12 months of
our taxable income or loss being includable in our taxable income for the year
of termination. In addition, each unitholder will realize taxable gain to the
extent that any money constructively distributed to him (including any net
reduction in his share of partnership nonrecourse liabilities) exceeds the
adjusted basis on his common units. New tax elections we are required to make,
including a new election under Section 754 of the Code, must be made subsequent
to the constructive termination. A constructive termination would also result in
a deferral of our deductions for depreciation. In addition, a termination might
either accelerate the application of or subject us to any tax legislation
enacted with effective dates after the closing of the offering made hereby.

ENTITY LEVEL COLLECTIONS

If we are required under applicable law to pay any federal, state or local
income tax on behalf of any unitholder, our general partner or any former
unitholder, we are authorized to pay those taxes from our funds. The payments,
if made, will be deemed current distributions of cash to our unitholders and our
general partner. Our general partner is authorized to amend our partnership
agreement in the manner necessary to maintain uniformity of intrinsic tax
characteristics of common units and to adjust subsequent distributions so that
after giving effect to the deemed distributions, the priority and
characterization of distributions otherwise applicable under our partnership
agreement is maintained as nearly as is practicable. These payments could give
rise to an overpayment of tax on behalf of an individual partner in which event
the partner could file a claim for credit or refund.

UNIFORMITY OF COMMON UNITS

Since we cannot match transferors and transferees of common units,
uniformity of the economic and tax characteristics of the common units to a
purchaser of common units must be maintained. In the absence of uniformity,
compliance with a number of federal income tax requirements, both statutory and
regulatory, could be substantially diminished. A lack of uniformity can result
from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6) or
Proposed Treasury Regulation Section 1.197-2(g)(3) and from the application of
the "ceiling limitation" on our ability to make allocations to eliminate Book-
Tax Disparities attributable to Contributed Properties and Adjusted Properties.
Any non-uniformity could have a negative impact on the value of a unitholder's
interest in us.

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We intend to depreciate the portion of a Section 743(b) adjustment
attributable to unrealized appreciation in the value of Contributed Property or
Adjusted Property (to the extent of any unamortized Book-Tax Disparity) using
the rate of depreciation derived from the depreciation method and useful life
applied to the Common Basis of our property, consistent with the proposed
regulations under Section 743, but despite its inconsistency with Treasury
Regulation Section 1.167(c)-1(a)(6) or Proposed Treasury Regulation Section
1.197-2(g)(3). See "-- Tax Consequences of Common Stock Ownership -- Tax
Treatment of Operations -- Section 754 Election." To the extent that the Section
743(b) adjustment is attributable to appreciation in value in excess of the
unamortized Book-Tax Disparity, we will apply the rules described in the
Treasury Regulation and legislative history. If we determine that this position
cannot reasonably be taken, we may adopt depreciation and amortization
conventions under which all purchasers acquiring common units in the same month
would receive depreciation and amortization deductions, whether attributable to
the Common Basis or the Section 743(b) basis, based upon the same applicable
rate as if they had purchased a direct interest in our property. If this
aggregate approach is adopted, it may result in lower annual depreciation and
amortization deductions than would otherwise be allowable to some of our
unitholders and risk the loss of depreciation and amortization deductions not
taken in the year that the deductions are otherwise allowable. We will not adopt
this convention if we determine that the loss of depreciation and amortization
deductions will have a material adverse effect on our unitholders. If we choose
not to utilize this aggregate method, we may use any other reasonable
depreciation and amortization convention to preserve the uniformity of the
intrinsic tax characteristics of any common units that would not have a material
adverse effect on our unitholders. The IRS may challenge any method of
depreciating or amortizing the Section 743(b) adjustment described in this
paragraph. If this challenge were sustained, the uniformity of common units
might be affected.

Items of income and deduction will be specially allocated in a manner that
is intended to preserve the uniformity of intrinsic tax characteristics among
all common units, despite the application of the "ceiling limitation" to
Contributed Properties and Adjusted Properties. These special allocations will
be made solely for federal income tax purposes. See "-- Tax Consequences of
Common Unit Ownership" and "-- Tax Consequences of Common Unit
Ownership -- Allocation of Our Income, Gain, Loss and Deduction."

TAX-EXEMPT ORGANIZATIONS AND SOME OTHER INVESTORS

Ownership of common units by employee benefit plans, other tax-exempt
organizations, non-resident aliens, foreign corporations, other foreign persons
and regulated investment companies raises issues unique to these persons and, as
described below, may have substantially adverse tax consequences.

Employee benefit plans and most other organizations exempt from federal
income tax (including individual retirement accounts and other retirement plans)
are subject to federal income tax on unrelated business taxable income.
Virtually all of the taxable income derived by these organizations from the
ownership of common units will be unrelated business taxable income, and thus
will be taxable to these unitholders.

Regulated investment companies are required to derive 90% or more of their
gross income from interest, dividends, gains from the sale of stocks or
securities or foreign currency or some related sources. It is not anticipated
that any significant amount of our gross income will qualify as income from
these sources.

Non-resident aliens and foreign corporations, trusts or estates that
acquire common units will be considered to be engaged in business in the United
States on account of their ownership of common units, and as a consequence they
will be required to file federal tax returns in respect of their distributive
shares of our income, gain, loss deduction or credit and pay federal income tax
at regular rates on our income. Generally, a partnership is required to pay a
withholding tax on the portion of the Partnership's income that is effectively
connected with the conduct of a United States trade or business and which is
allocable to the foreign partners, regardless of whether any actual
distributions have been made to our partners. However, under rules applicable to
publicly-traded partnerships, we will withhold at the rate of 39.6% on

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actual cash distributions made quarterly to foreign unitholders. Each foreign
unitholder must obtain a taxpayer identification number from the IRS and submit
that number to our Transfer Agent on a Form W-8 in order to obtain credit for
the taxes withheld. Subsequent adoption of Treasury Regulations or the issuance
of other administrative pronouncements may require us to change these
procedures.

Because a foreign corporation that owns common units will be treated as
engaged in a United States trade or business, it may be subject to United States
branch profits tax at a rate of 30%, in addition to regular federal income tax,
on its allocable share of our earnings and profits (as adjusted for changes in
the foreign corporation's "U.S. net equity") that are effectively connected with
the conduct of a United States trade or business. This tax may be reduced or
eliminated by an income tax treaty between the United States and the country
with respect to which the foreign corporate unitholder is a "qualified
resident."

Under a ruling of the IRS, a foreign unitholder who sells or otherwise
disposes of a common unit will be subject to federal income tax on any gain
realized on the disposition of his common unit to the extent that the gain is
effectively connected with a United States trade or business of the foreign
unitholder. Apart from the ruling, a foreign unitholder will not be taxed upon
the disposition of a common unit if that foreign unitholder has held less than
5% in value of the common units during the five-year period ending on the date
of the disposition and if the common units are regularly traded on an
established securities market at the time of the disposition.

ADMINISTRATIVE MATTERS

Our Information Returns and Audit Procedures

We intend to furnish to each of our unitholders, within 90 days after the
close of each taxable year, tax information, including a Schedule K-1, that sets
forth each of our unitholders' allocable shares of our income, gain, loss,
deduction and credit. In preparing this information that will generally not be
reviewed by Counsel, we will use various accounting and reporting conventions,
some of which have been mentioned in the previous discussion, to determine the
respective unitholders' allocable share of income, gain, loss, deduction and
credits. There is no assurance that any of these conventions will yield a result
that conforms to the requirements of the Code, regulations or administrative
interpretations of the IRS. We cannot assure prospective unitholders that the
IRS will not successfully contend in court that these accounting and reporting
conventions are impermissible.

The federal income tax information returns we filed may be audited by the
IRS. Adjustments resulting from any IRS audit may require some or all of our
unitholders to file amended tax returns, and possibly may result in an audit of
unitholders' own returns. Any audit of a unitholder's return could result in
adjustments of non-partnership as well as partnership items.

Partnerships generally are treated as separate entities for purposes of
federal tax audits, judicial review of administrative adjustments by the IRS and
tax settlement proceedings. The tax treatment of partnership items of income,
gain, loss, deduction and credit are determined at the partnership level in a
unified partnership proceeding rather than in separate proceedings with the
partners. The Code provides for one partner to be designated as the "Tax Matters
Partner" for these purposes. Our partnership agreement appoints our general
partner as the Tax Matters Partner.

The Tax Matters Partner will make elections on our behalf and our
unitholders' behalf and can extend the statute of limitations for assessment of
tax deficiencies against our unitholders with respect to our items. The Tax
Matters Partner may bind a unitholder with less than a 1% profits interest in us
to a settlement with the IRS unless the unitholder elects, by filing a statement
with the IRS, not to give that authority to the Tax Matters Partner. The Tax
Matters Partner may seek judicial review (to which all of our unitholders are
bound) of a final partnership administrative adjustment and, if the Tax Matters
Partner fails to seek judicial review, the review may be sought by any of our
unitholders having at least 1% interest in our profits and by our unitholders
having in the aggregate at least a 5% profits interest. However, only one action
for judicial review will go forward, and each unitholder with an interest in the
outcome may participate.
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A unitholder must file a statement with the IRS identifying the treatment
of any item on his federal income tax return that is not consistent with the
treatment of the item on our return to avoid the requirement that all items be
treated consistently on both returns. Intentional or negligent disregard of the
consistency requirement may subject a unitholder to substantial penalties.

Nominee Reporting

Persons who hold an interest in us as a nominee for another person are
required to furnish to us:

- the name, address and taxpayer identification number of the beneficial
owners and the nominee;

- whether the beneficial owner is (i) a person that is not a United States
person, (ii) a foreign government, an international organization or any
wholly-owned agency or instrumentality of either of the foregoing or
(iii) a tax-exempt entity;

- the amount and description of common units held, acquired or transferred
for the beneficial owner; and

- other information including the dates of acquisitions and transfers,
means of acquisitions and transfers and acquisition cost for purchases,
as well as the amount of net proceeds from sales.

Brokers and financial institutions are required to furnish additional
information, including whether they are United States persons and information on
common units they acquire, hold or transfer for their own account. A penalty of
$50 per failure (up to a maximum of $100,000 per calendar year) is imposed by
the Code for failure to report this information to us. The nominee is required
to supply the beneficial owner of the common units with the information
furnished to us.

Registration as a Tax Shelter

The Code requires that "tax shelters" be registered with the Secretary of
the Treasury. The temporary Treasury Regulations interpreting the tax shelter
registration provisions of the Code are extremely broad. It is arguable that we
are not subject to the registration requirement on the basis that (i) we do not
constitute a tax shelter or (ii) we constitute a projected income investment
exempt from registration. However, we have registered as a tax shelter with the
IRS because of the absence of assurance that we will not be subject to tax
shelter registration and in light of the substantial penalties that might be
imposed if registration is required and not undertaken. ISSUANCE OF THE
REGISTRATION NUMBER DOES NOT INDICATE THAT AN INVESTMENT IN US OR THE CLAIMED
TAX BENEFITS HAVE BEEN REVIEWED, EXAMINED OR APPROVED BY THE IRS. Our tax
shelter registration number is 94130000154. A unitholder who sells or otherwise
transfers a common unit in a subsequent transaction must furnish the
registration number to the transferee. The penalty for failure of the transferor
of a common unit to furnish the registration number to the transferee is $100
for each failure. The unitholders must disclose our tax shelter registration
number on Form 8271 to be attached to the tax return on which any deduction,
loss, credit or other benefit we generate is claimed or income received from us
is included. A unitholder who fails to disclose the tax shelter registration
number on his return, without reasonable cause for the failure, will be subject
to a $50 penalty for each failure. Any penalties discussed herein are not
deductible for federal income tax purposes.

ACCURACY-RELATED PENALTIES

An additional tax equal to 20% of the amount of any portion of an
underpayment of tax that is attributable to one or more of the listed causes,
including substantial understatements of income tax and substantial valuation
misstatements, is imposed by the Code. No penalty will be imposed, however, with
respect to any portion of an underpayment if it is shown that there was a
reasonable cause for that portion and that the taxpayer acted in good faith with
respect to that portion.

A substantial understatement of income tax in any taxable year exists if
the amount of the understatement exceeds the greater of 10% of the tax required
to be shown on the return for the taxable year or $5,000 ($10,000 for most
corporations). The amount of any understatement subject to penalty
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generally is reduced if any portion is attributable to a position adopted on the
return (i) with respect to which there is or was, "substantial authority" or
(ii) as to which there is a reasonable basis and the pertinent facts of the
position are disclosed on the return. More stringent rules apply to "tax
shelters," a term that does not appear to include us. If any item of our income,
gain, loss, deduction or credit included in the distributive shares of our
unitholders might result in an "understatement" of income for which no
substantial authority exists, we must disclose the pertinent facts on our
return. In addition, we will make a reasonable effort to furnish sufficient
information for our unitholders to make adequate disclosure on their returns to
avoid liability for this penalty.

A substantial valuation misstatement exists if the value of any property
(or the adjusted basis of any property) claimed on a tax return is 200% or more
of the amount determined to be the correct amount of the valuation or adjusted
basis. No penalty is imposed unless the portion of the underpayment attributable
to a substantial valuation misstatement exceeds $5,000 ($10,000 for most
corporations). If the valuation claimed on a return is 400% or more than the
correct valuation, the penalty imposed increases to 40%.

OTHER TAX CONSIDERATIONS

In addition to federal income taxes, you may be subject to other taxes,
such as state and local and Canadian federal and provincial taxes,
unincorporated business taxes, and estate, inheritance or intangible taxes that
may be imposed by the various jurisdictions in which the we do business or own
property. Although an analysis of those various taxes is not presented here,
each prospective unitholder should consider their potential impact on his
investment in us. We will own property or conduct business in Canada and in most
states of the United States. A unitholder may be required to file Canadian
federal income tax returns and to pay Canadian federal and provincial income
taxes and to file state income tax returns and to pay taxes in various states
and may be subject to penalties for failure to comply with such requirements. We
anticipate that most of our U.S. income will be generated in approximately
thirteen (13) states: Alabama, California, Illinois, Indiana, Kansas, Louisiana,
Mississippi, Montana, New Mexico, North Dakota, Oklahoma, Texas and Wyoming.
Based on EOTT's income apportionment for 1998 state income tax purposes, our
general partner estimates that no other state will account for more than 1% of
our income. Of the thirteen states in which our general partner anticipates that
most of our U.S. income will be generated, Texas and Wyoming do not currently
impose personal income tax. In certain states, tax losses may not produce a tax
benefit in the year incurred (if, for example, we have no income from sources
within that state) and also may not be available to offset income in subsequent
taxable years. Some of the states may require us to withhold a percentage of
income from amounts to be distributed to a unitholder who is not a resident of
the state. Withholding, the amount which may be greater or less than a
particular unitholder's income tax liability to the state, generally does not
relieve the non-resident unitholder from the obligation to file an income tax
return. Amounts withheld will be treated as if distributed to unitholders for
purposes of determining the amount distributed by us. Based on current law and
our estimate of future operations, the general partner anticipates that any
amounts required to be withheld will not be material. We may also own property
or do business in other states in the future.

It is the responsibility of each unitholder to investigate the legal and
tax consequences, under the laws of pertinent states, localities, Canadian
provinces and Canada, of his investment in us. Accordingly, each prospective
unitholder should consult, and must depend upon, his own tax counsel or other
advisor with regard to those matters. Further, it is the responsibility of each
unitholder to file all Canadian, Canadian province, state and local, as well as
federal, tax returns that may be required of him. Counsel has not rendered an
opinion on the Canadian federal, Canadian provincial, state or local tax
consequences of an investment in us.

TAX CONSEQUENCES OF OWNERSHIP OF DEBT SECURITIES

A description of the material federal income tax consequences of the
acquisition, ownership and disposition of debt securities will be set forth in
the prospectus supplement relating to the offering of debt securities.

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PLAN OF DISTRIBUTION

Under this prospectus, we intend to offer our securities to the public:

- through one or more broker-dealers;

- through underwriters; or

- directly to investors.

We will fix a price or prices, and we may change the price of the
securities offered from time to time:

- at market prices prevailing at the time of any sale under this
registration statement;

- prices related to market prices; or

- negotiated prices.

We will pay or allow distributors' or sellers' commissions that will not
exceed those customary in the types of transactions involved. Broker-dealers may
act as agent or may purchase securities as principal and thereafter resell the
securities from time to time:

- in or through one or more transactions (which may involve crosses and
block transactions) or distributions;

- on the New York Stock Exchange;

- in the over-the-counter market; or

- in private transactions.

Broker-dealers or underwriters may receive compensation in the form of
underwriting discounts or commissions and may receive commissions from
purchasers of the securities for whom they may act as agents. If any
broker-dealer purchases the securities as principal, it may effect resales of
the securities from time to time to or through other broker-dealers, and other
broker-dealers may receive compensation in the form of concessions or
commissions from the purchasers of securities for whom they may act as agents.

To the extent required, the names of the specific managing underwriter or
underwriters, if any, as well as other important information, will be set forth
in prospectus supplements. In that event, the discounts and commissions we will
allow or pay to the underwriters, if any, and the discounts and commissions the
underwriters may allow or pay to dealers or agents, if any, will be set forth
in, or may be calculated from, the prospectus supplements.

Any underwriters, brokers, dealers and agents who participate in any sale
of the securities may also engage in transactions with, or perform services for,
us or our affiliates in the ordinary course of their businesses.

In connection with offerings under this shelf registration and in
compliance with applicable law, underwriters, brokers or dealers may engage in
transactions which stabilize or maintain the market price of the securities at
levels above those which might otherwise prevail in the open market.
Specifically, underwriters, brokers or dealers may over-allot in connection with
offerings, creating a short position in the securities for their own accounts.
For the purposes of covering a syndicate short position or stabilizing the price
of the securities, the underwriters, brokers or dealers may place bids for the
securities or effect purchases of the securities in the open market. Finally,
the underwriters may impose a penalty bid whereby selling concessions allowed to
syndicate members or other brokers or dealers for distribution the securities in
offerings may be reclaimed by the syndicate if the syndicate repurchases
previously distributed securities in transactions to cover short positions, in
stabilization transactions or otherwise. These activities may stabilize,
maintain or otherwise affect the market price of the securities, which may be
higher than the price that might otherwise prevail in the open market, and, if
commenced, may be discontinued at any time.

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LEGAL MATTERS

Vinson & Elkins L.L.P., will pass upon the validity of the securities
offered in this prospectus. The underwriters' own legal counsel will advise them
about other issues relating to any offering.

EXPERTS

The audited consolidated financial statements and schedule of EOTT Energy
Partners, L.P. as of December 31, 1998 and 1997, and for the three years in the
period ended December 31, 1998 incorporated by reference in this prospectus and
elsewhere in the registration statement have been audited by Arthur Andersen
LLP, independent public accountants, as indicated in their report with respect
thereto, and are included herein in reliance upon the authority of said firm as
experts in accounting and auditing in giving said report.

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WE HAVE NOT AUTHORIZED ANYONE TO PROVIDE INFORMATION DIFFERENT FROM THAT
CONTAINED IN THIS PROSPECTUS SUPPLEMENT AND THE ACCOMPANYING PROSPECTUS. NEITHER
THE DELIVERY OF THIS PROSPECTUS SUPPLEMENT AND THE ACCOMPANYING PROSPECTUS NOR
THE SALE OF COMMON UNITS MEANS THAT INFORMATION CONTAINED IN THIS PROSPECTUS
SUPPLEMENT AND THE ACCOMPANYING PROSPECTUS IS CORRECT AFTER THE DATES OF THIS
PROSPECTS SUPPLEMENT AND THE ACCOMPANYING PROSPECTUS. THIS PROSPECTUS SUPPLEMENT
AND THE ACCOMPANYING PROSPECTUS IS NOT AN OFFER TO SELL OR A SOLICITATION OF AN
OFFER TO BUY THESE COMMON UNITS IN ANY CIRCUMSTANCES UNDER WHICH THE OFFER OR
SOLICITATION IS UNLAWFUL.

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TABLE OF CONTENTS

<TABLE>
<CAPTION>
PAGE
----
<S> <C>
PROSPECTUS SUPPLEMENT

Summary................................ S-1
Use of Proceeds........................ S-11
Capitalization......................... S-12
Price Range of Common Units and
Distributions........................ S-13
Selected Historical Financial Data..... S-14
Management's Discussion and Analysis of
Financial Condition and Results of
Operations........................... S-16
Business............................... S-25
Management............................. S-32
Principal Unitholders.................. S-34
Underwriting........................... S-35
Legal Matters.......................... S-36
Experts................................ S-36

PROSPECTUS

About This Prospectus.................. ii
Where You Can Find More Information.... ii
Cautionary Statement Regarding Forward
Looking Statements................... iii
Who We Are............................. 1
Risk Factors........................... 2
Conflicts of Interest and Fiduciary
Responsibilities..................... 7
Use of Proceeds........................ 8
Description of the Debt Securities..... 8
Ratio of Earnings to Fixed Charges..... 13
Description of Our Common Units........ 13
Cash Distribution Policy............... 15
Description of Our Partnership
Agreement............................ 16
Tax Considerations..................... 19
Plan of Distribution................... 34
Legal Matters.......................... 35
Experts................................ 35
</TABLE>

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3,500,000 COMMON UNITS
EOTT ENERGY PARTNERS, L.P.
REPRESENTING
LIMITED PARTNER INTERESTS
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PROSPECTUS SUPPLEMENT

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PAINEWEBBER INCORPORATED

LEHMAN BROTHERS

DAIN RAUSCHER WESSELS
A DIVISION OF DAIN RAUSCHER INCORPORATED
ING BARINGS

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SEPTEMBER 23, 1999

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