Edgar Filing: ENTERPRISE PRODUCTS PARTNERS L P

FILED PURSUANT TO RULE 424B2
REGISTRATION NO. 333-56082

PROSPECTUS SUPPLEMENT
(TO PROSPECTUS DATED MARCH 27, 2001)

[ENTERPRISE PRODUCTS PARTNERS L.P. LOGO]

ENTERPRISE PRODUCTS PARTNERS L.P.

9,800,000 COMMON UNITS

REPRESENTING LIMITED PARTNER INTERESTS
--------------------------------------------------------------------------------

We are offering to sell 9,800,000 common units, including 1,800,000 common units
to be offered to entities controlled by Dan L. Duncan, the Chairman of our
general partner, and to O.S. Andras, the President and Chief Executive Officer
of our general partner. Our common units trade on the New York Stock Exchange
under the symbol "EPD." The last reported sales price of our common units on the
NYSE on October 2, 2002 was $18.99 per common unit.

INVESTING IN THE COMMON UNITS INVOLVES RISK. "RISK FACTORS" BEGIN ON PAGE S-9 OF
THIS PROSPECTUS SUPPLEMENT AND ON PAGE 3 OF THE ACCOMPANYING PROSPECTUS.

PER COMMON UNIT
--------------- TOTAL

Public offering price...................................... $18.99 $186,102,000
Underwriting discount (1).................................. $ 0.81 $ 6,472,548
Proceeds to Enterprise Products Partners (before
expenses)................................................ $18.18 $179,629,452

---------------
(1) The underwriters will receive no underwriting discount or commission on the
sale of the 1,800,000 common units described above or on the sale of 9,200
common units to other members of our senior management.

We have granted the underwriters a 30-day option to purchase up to 1,470,000
common units on the same terms and conditions as set forth above to cover
over-allotments of common units, if any.

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.

Lehman Brothers, on behalf of the underwriters, expects to deliver the common
units on or about October 8, 2002.

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

LEHMAN BROTHERS
GOLDMAN, SACHS & CO.
UBS WARBURG
RBC CAPITAL MARKETS
WACHOVIA SECURITIES
MCDONALD INVESTMENTS INC.
RAYMOND JAMES
SANDERS MORRIS HARRIS

October 2, 2002

[INSIDE COVER ART]

This document is in two parts. The first part is this prospectus
supplement, which describes the terms of this offering of common units. The
second part is the accompanying prospectus, which gives more general
information, some of which may not apply to the common units.

You should rely only on the information contained or incorporated by
reference in this prospectus supplement or the accompanying prospectus. We have
not authorized anyone to provide you with different information. We are not
making an offer of these securities in any state where the offer is not
permitted. You should not assume that the information contained in this
prospectus supplement or the accompanying prospectus is accurate as of any date
other than the date on the front of these documents or that any information we
have incorporated by reference is accurate as of any date other than the date of
the document incorporated by reference.

TABLE OF CONTENTS

PAGE
----

PROSPECTUS SUPPLEMENT
Summary..................................................... S-1
Risk Factors................................................ S-9
Use of Proceeds............................................. S-16
Price Range of Common Units and Distributions............... S-16
Capitalization.............................................. S-17
Selected Historical and Pro Forma Financial and Operating
Data...................................................... S-18
Management's Discussion and Analysis of Financial Condition
and Results of Operations................................. S-21
Business.................................................... S-42
Management.................................................. S-62
Tax Considerations.......................................... S-64
Underwriting................................................ S-65
Incorporation of Certain Documents by Reference............. S-68
Legal Matters............................................... S-68
Experts..................................................... S-68
Glossary.................................................... S-69
Index to Financial Statements............................... F-1
PROSPECTUS
Forward-Looking Statements.................................. 1
Where You Can Find More Information......................... 2
Incorporation of Certain Documents by Reference............. 2
The Company................................................. 2
Risk Factors................................................ 3
Use of Proceeds............................................. 6
Ratio of Earnings to Fixed Charges.......................... 6
Description of Debt Securities.............................. 6
Description of Common Units................................. 17
Tax Considerations.......................................... 23
Selling Unitholders......................................... 34
Plan of Distribution........................................ 34
Legal Matters............................................... 36
Experts..................................................... 36

SUMMARY

This summary highlights information contained elsewhere in this prospectus
supplement. You should read carefully the entire prospectus supplement, the
accompanying prospectus, the documents incorporated by reference and the other
documents to which we refer for a more complete understanding of this offering.
You should read "Risk Factors" beginning on page S-9 of this prospectus
supplement and on page 3 of the accompanying prospectus for more information
about important risks that you should consider before buying common units in
this offering. We have provided definitions for some of the industry terms,
names of companies and other abbreviations used in this prospectus supplement in
the "Glossary" beginning on page S-69 of this prospectus supplement. The
information presented in this prospectus supplement assumes that the
underwriters do not exercise their over-allotment option. All references in this
prospectus supplement to numbers of units, earnings per unit or unit price give
effect to our two-for-one unit split on May 15, 2002. All references in the
accompanying prospectus to numbers of units, earnings per unit or unit price do
not give effect to the two-for-one unit split. Pro forma financial results
presented in this prospectus supplement give effect to material acquisitions we
completed in 2002. For a more complete explanation of our pro forma financial
results, please read "Enterprise Products Partners L.P. Unaudited Pro Forma
Consolidated Financial Statements" beginning on page F-2.

ENTERPRISE PRODUCTS PARTNERS L.P.

We are a leading North American midstream energy company that provides a
wide range of services to producers and consumers of natural gas and natural gas
liquids, or NGLs. NGLs are used by the petrochemical and refining industries to
produce plastics, motor gasoline and other industrial and consumer products and
also are used as residential, agricultural and industrial fuels. Our asset
platform in the Gulf Coast region, combined with our recently acquired
Mid-America and Seminole pipeline systems, creates the only integrated natural
gas and NGL transportation, fractionation, processing, storage and import/export
network in North America. We provide integrated services to our customers and
generate fee-based cash flow from multiple sources along our natural gas and NGL
"value chain."

For the year ended December 31, 2001, we had revenues of $3.2 billion,
operating margin of $376.8 million and net income of $242.2 million. On a pro
forma basis for the year ended December 31, 2001, we had revenues of $4.0
billion, operating margin of $556.2 million and net income of $251.7 million.
Our business has five reportable segments:

Pipelines. Our Pipelines segment includes approximately 14,000 miles of
NGL, petrochemical and natural gas pipelines located primarily in the Rocky
Mountain, Mid-Continent and Gulf Coast regions of the United States. This
segment also includes our storage and import/export terminalling businesses.

Fractionation. Our Fractionation segment includes eight NGL fractionators,
the largest commercial isomerization complex in the United States and four
propylene fractionation facilities. NGL fractionators separate mixed NGL streams
produced as by-products of natural gas production and crude oil refining into
discrete NGL products: ethane, propane, isobutane, normal butane and natural
gasoline. Our isomerization complex converts normal butane into mixed butane,
which is subsequently fractionated into normal butane, isobutane and high purity
isobutane. Our propylene fractionators separate refinery-sourced
propane/propylene mix into propane, propylene and mixed butane.

Processing. Our Processing segment is comprised of our natural gas
processing business and related merchant activities. At the core of our natural
gas processing business are 13 gas plants, located primarily in south Louisiana,
that process raw natural gas into a product that meets pipeline and industry
specifications by removing NGLs and impurities. In connection with our
processing businesses, we receive a portion of the NGL production from these gas
plants. This equity NGL production, together with the NGLs we purchase, supports
the merchant activities included in this operating segment.

Octane Enhancement and Other. Our Octane Enhancement segment consists of a
33.3% equity investment in BEF, which owns a facility that produces motor
gasoline additives used to enhance octane. Our Other segment consists primarily
of fee-based marketing services.

S-1

We completed the initial public offering of our common units in July 1998
at a unit price of $11.00 per unit. On September 12, 2002, we announced that the
board of directors of our general partner approved an increase in our quarterly
distribution rate to $0.345 per unit, or $1.38 on an annualized basis, which
represents an approximate 53% increase in our quarterly distribution rate since
our initial public offering. Since our initial public offering, we have
completed investments with a combined value of over $3.1 billion. As
demonstrated by our July 2002 acquisitions of the Mid-America and Seminole
pipeline systems, we are committed to growing our fee-based businesses. We
believe that these acquisitions will increase our gross margins derived from
fee-based businesses to between 85% and 90% of total gross margin, based on
average natural gas and NGL product prices for the last ten years.

RECENT SIGNIFICANT ACQUISITIONS

Acquisition of Mid-America and Seminole Pipeline Systems. On July 31,
2002, we completed the acquisition of a 98% interest in the Mid-America pipeline
system and a 78% interest in the Seminole pipeline system from The Williams
Companies, Inc. for approximately $1.2 billion in cash. Mid-America is a 7,226-
mile NGL pipeline system connecting the Hobbs hub located on the Texas-New
Mexico border with supply regions in the Rocky Mountains and with supply regions
and markets in the Midwest. The Mid-America pipeline system is comprised of
three major segments: the Conway North pipeline, the Conway South pipeline and
the Rocky Mountain pipeline. In 2001, average transportation volumes on the
Mid-America pipeline system were approximately 641 MBPD. Seminole is a
1,281-mile pipeline system that interconnects with the Mid-America pipeline
system and transports mixed NGLs and NGL products from the Hobbs hub and the
Permian basin to Mont Belvieu, Texas. In 2001, average transportation volumes on
the Seminole pipeline system were approximately 241 MBPD, of which approximately
32% were transported to our Mont Belvieu facilities for fractionation, storage
and distribution. Major customers utilizing the Mid-America and Seminole
pipeline systems include BP, Burlington, ConocoPhillips, Duke, Equistar and
Williams.

The acquisition of the Mid-America and Seminole pipeline systems
significantly enhances our existing asset base by:

- accessing NGL-rich natural gas production in major North American natural
gas producing regions;

- expanding our integrated natural gas and NGL network;

- providing access to new end markets for NGL products; and

- increasing our gross margins from fee-based businesses.

In addition to our current strategic position in the Gulf of Mexico, we now have
access to major supply basins throughout North America, including the Rocky
Mountain Overthrust, the San Juan and Permian basins, the Mid-Continent region
and, through third-party pipeline connections, north into Canada's Western
Sedimentary basin. The combination of these assets with our existing assets also
creates a significant link between Mont Belvieu, Texas and Conway, Kansas, the
two largest NGL hubs in the United States, and provides additional access to new
end markets for NGL products. The Conway South segment of the Mid-America
pipeline system connects Conway to the Hobbs hub, which is, in turn, connected
to Mont Belvieu via the Seminole pipeline system. The 2,740-mile Conway North
pipeline links the market hub in Conway with petrochemical and refining
customers and propane markets in the upper Midwest.

Acquisition of Propylene Fractionation Business. In February 2002, we
completed the purchase of various propylene fractionation assets and certain
inventories of propylene and propane from Diamond-Koch for approximately $239
million in cash. The acquisition includes a 66.7% interest in a polymer grade
propylene fractionation facility located in Mont Belvieu, Texas, a 50% interest
in a polymer grade propylene export terminal located on the Houston Ship Channel
and varying interests in several supporting distribution pipelines and related
equipment. This Mont Belvieu facility has the capacity to produce approximately
41 MBPD of polymer grade propylene.

S-2

Acquisition of Storage Business. In January 2002, we completed the
purchase of various NGL and petrochemical storage assets from Diamond-Koch for
approximately $130 million in cash. These storage facilities consist of 30 salt
dome storage caverns located in Mont Belvieu, Texas with a useable capacity of
68 million barrels, local distribution pipelines and related equipment. The
facilities provide storage services for mixed NGL products and olefins, such as
ethylene and propylene. The facilities, together with our existing storage
facilities, serve the largest concentration of petrochemical and refinery
facilities in the United States and represent the largest NGL and petrochemical
underground storage operation in the world.

OUR BUSINESS STRATEGY

Our business strategy is to:

- capitalize on expected increases in natural gas and NGL production
resulting from development activities in the deepwater and continental
shelf areas of the Gulf of Mexico and the Rocky Mountain region;

- develop and invest in joint venture projects with strategic partners that
will provide the raw materials for these projects or purchase the
projects' end products;

- expand our asset base through accretive acquisitions of complementary
midstream energy assets; and

- increase our fee-based cash flows by investing in pipelines and other
fee-based businesses.

COMPETITIVE STRENGTHS

We believe that our integrated network of midstream energy assets is
well-positioned to benefit from demand for our services from producers and
consumers of natural gas, NGLs and petrochemicals. Our most significant
competitive strengths are:

Strategic locations. Our operations are strategically located to serve the
major supply basins of NGL-rich natural gas, the major NGL markets and storage
hubs in North America and international markets. Our location in these markets
ensures continued access to natural gas, NGL and petrochemical supply volumes,
anticipated demand growth and business expansion opportunities.

Integrated platform of assets. Our assets are physically linked to form
the only integrated system connecting the largest supply basins to the largest
consuming markets, both domestic and international.

Relationships with major oil, natural gas and petrochemical companies. We
have long-term relationships with many of our suppliers and customers, including
BP, ChevronTexaco, Dow Chemical, Exxon Mobil, Lyondell and Shell. We jointly own
facilities with many of these customers, which either provide raw materials to
or consume the end products produced from our facilities.

Large-scale, low-cost integrated operations. We believe the operating
costs of our large-scale facilities are either competitive with or significantly
lower than those of our competitors.

Experienced operator. We have historically operated our largest natural
gas processing and fractionation facilities and most of our pipelines.

Experienced management team. Our senior management team averages more than
27 years of industry experience. Through our acquisition of Shell's midstream
energy business and the Diamond-Koch propylene fractionation business, we have
broadened and deepened our senior management team.

S-3

OUR RELATIONSHIP WITH SHELL

One of our significant strengths is our extensive relationship with Shell.
Over the last three years, we have made several acquisitions from Shell,
including our $529 million acquisition of TNGL, our $100 million acquisition of
the Lou-Tex propylene pipeline system and our $244 million acquisition of
Acadian Gas. Following this offering, Shell will own an approximate 21.8%
limited partner interest in us and 30% of our general partner. Shell currently
owns a 45.4% equity interest in one of our propylene fractionators at our Mont
Belvieu complex, a 66% interest in our Nemo natural gas pipeline system and a
50% interest in each of our Nautilus, Manta Ray, Stingray and Triton natural gas
pipeline systems. During 2001, Shell generated $333.3 million, or 10.5%, of our
revenues.

PARTNERSHIP STRUCTURE AND MANAGEMENT

Our operations are conducted through, and our operating assets are owned
by, our subsidiaries. The chart on the following page depicts our organizational
and ownership structure after giving effect to this offering. Upon consummation
of the offering of our common units:

- there will be 29,085,964 publicly held common units outstanding,
representing a 15.5% limited partner interest in us;

- EPCO and its affiliated entities will own 81,608,802 common units and
32,114,804 subordinated units representing an aggregate 60.7% limited
partner interest in us;

- Shell will own 31,000,000 common units and 10,000,000 special units
representing a 21.8% limited partner interest in us; and

- Our general partner will continue to own a combined 2.0% general partner
interest in us and all of our incentive distribution rights.

Our principal executive offices are located at 2727 North Loop West,
Houston, Texas 77008, and our phone number is (713) 880-6500.

S-4

OWNERSHIP OF ENTERPRISE PRODUCTS PARTNERS L.P. AND THE OPERATING PARTNERSHIP

PERCENTAGE INTEREST
UNITS (on a combined basis)
----------- ---------------------

Public common units.................................. 29,085,964 15.5%
EPCO common units.................................... 81,608,802 43.6%
EPCO subordinated units.............................. 32,114,804 17.1%
Shell common units................................... 31,000,000 16.5%
Shell special units.................................. 10,000,000 5.3%
General partner interest (70% EPCO; 30% Shell)(1).... 2.0%
------
Total........................................... 100.0%

[GRAPH]

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

(1) 2.0% general partner interest on a combined basis, including a 1.0% general
partner interest in Enterprise Products Partners L.P. and a 1.0101% general
partner interest in the operating partnership.

S-5

THE OFFERING

Common units offered...... 9,800,000 common units, including 1,809,200 common
units to be offered to members of our senior
management or their affiliates; and

11,270,000 common units if the underwriters exercise
their over-allotment option in full.

Units outstanding after
this offering............. 141,694,766 common units or 143,164,766 common units
if the underwriters exercise their over-allotment
option in full;

32,114,804 subordinated units; and

10,000,000 special units.

Use of proceeds........... We will use the net proceeds from this offering to
retire a portion of the indebtedness outstanding
under our $1.2 billion senior unsecured 364-day term
loan incurred to finance the Mid-America and Seminole
acquisitions. For a description of our term loan,
please read "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Our
Liquidity and Capital Resources -- Our Debt
Obligations."

Cash distributions........ Under our partnership agreement, we must distribute
all of our cash on hand as of the end of each
quarter, less reserves established by our general
partner. We refer to this cash as "available cash,"
and we define its meaning in our partnership
agreement.

On August 12, 2002, we paid a quarterly cash
distribution for the second quarter of 2002 of $0.335
per common unit, or $1.34 per common unit on an
annualized basis. On September 12, 2002, we announced
that the board of directors of our general partner
approved an increase in our quarterly distribution to
$0.345 per common unit, or $1.38 per common unit on
an annualized basis, commencing with the distribution
payable in the fourth quarter of this year.

When quarterly cash distributions exceed $0.253 per
unit in any quarter, our general partner receives a
higher percentage of the cash distributed in excess
of that amount, in increasing percentages up to 50%
if the quarterly cash distributions exceed $0.392.
Our special units do not accrue distributions and are
not entitled to cash distributions until their
conversion into an equal number of common units on
August 1, 2003. For a description of our cash
distribution policy, please read "Description of
Common Units -- Cash Distribution Policy" in the
accompanying prospectus.

Estimated ratio of taxable
income to
distributions........... We estimate that if you own the common units you
purchase in this offering through December 31, 2005,
you will be allocated, on a cumulative basis, an
amount of federal taxable income for that period that
will be less than 10% of the cash distributed with
respect to that period. Please read "Tax
Considerations" in this prospectus supplement for the
basis of this estimate.

New York Stock Exchange
symbol.................. EPD

S-6

SUMMARY HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA

The following table sets forth for the periods and at the dates indicated
selected historical and pro forma financial and operating data for us. The
selected historical income statement data for each of the three years in the
period ended December 31, 2001 and the selected balance sheet data for each of
the two years in the period ended December 31, 2001 are derived from and should
be read in conjunction with our audited financial statements for these periods
included elsewhere in this prospectus supplement. The selected historical data
for the six month periods ending June 30, 2001 and 2002 are derived from and
should be read in conjunction with our unaudited financial statements included
elsewhere in this prospectus supplement. The table should be read together with
"Management's Discussion and Analysis of Financial Condition and Results of
Operations."

The summary pro forma financial statements of Enterprise Products Partners
show the pro forma effect of:

- the Mid-America and Seminole acquisitions including the $1.2 billion
senior unsecured 364-day term loan;

- the propylene fractionation and storage business acquired from
Diamond-Koch in 2002 and the acquisition of Acadian Gas in 2001;

- the completion of this offering;

- the general partner's proportionate capital contribution; and

- the application of the net proceeds from this offering to repay a portion
of indebtedness outstanding under the term loan.

The summary pro forma financial and operating data for the year ended
December 31, 2001 and six months ended June 30, 2002 are derived from the
unaudited pro forma financial statements. The unaudited pro forma statements of
consolidated operations have been prepared as if the acquisitions had occurred
on January 1 of the respective periods presented, and the pro forma balance
sheet has been prepared as if the Mid-America and Seminole acquisitions occurred
on June 30, 2002.

EBITDA is defined as net income plus depreciation and amortization and
interest expense (net of amortization of loan costs and interest income) less
equity in income of unconsolidated affiliates. EBITDA should not be considered
an alternative to net income, operating income, cash flow from operations or any
other measure of financial performance presented in accordance with generally
accepted accounting principles. EBITDA is not intended to represent cash flow.
Our management uses EBITDA to assess the viability of projects and to determine
overall rates of return on alternative investment opportunities. Because EBITDA
excludes some, but not all, items that affect net income and these measures may
vary among other companies, the EBITDA data presented above may not be
comparable to similarly titled measures of other companies.

S-7

ENTERPRISE PRODUCTS PARTNERS L.P.

HISTORICAL PRO FORMA AS ADJUSTED
-------------------------------------------------------------- -------------------------
SIX MONTHS SIX MONTHS
FOR THE YEAR ENDED DECEMBER 31, ENDED JUNE 30, YEAR ENDED ENDED
------------------------------------ ----------------------- DECEMBER 31, JUNE 30,
1999 2000 2001 2001 2002 2001 2002
---------- ---------- ---------- ---------- ---------- ------------ ----------
(UNAUDITED) (UNAUDITED)

(Dollars in thousands)
INCOME STATEMENT DATA:
Revenues from consolidated
operations....................... $1,332,979 $3,049,020 $3,154,369 $1,795,712 $1,448,311 $3,952,943 $1,608,214
Equity in income of unconsolidated
affiliates....................... 13,477 24,119 25,358 11,061 16,295 23,479 16,295
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total.......................... $1,346,456 $3,073,139 $3,179,727 $1,806,773 $1,464,606 $3,976,422 $1,624,509
Costs and expenses:
Operating costs and expenses..... $1,201,605 $2,801,060 $2,861,743 $1,629,380 $1,410,044 $3,528,057 $1,487,900
Selling, general and
administrative expenses........ 12,500 28,345 30,296 13,905 15,702 64,672 31,888
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total.......................... $1,214,105 $2,829,405 $2,892,039 $1,643,285 $1,425,746 $3,592,729 $1,519,788
Operating income................... $ 132,351 $ 243,734 $ 287,688 $ 163,488 $ 38,860 $ 383,693 $ 104,721
Other income (expense):
Interest expense................. $ (16,439) $ (33,329) $ (52,456) $ (23,318) $ (37,545) $ (118,541) $ (64,301)
Interest income from
unconsolidated affiliates...... 1,667 1,787 31 31 92 35 92
Dividend income from
unconsolidated affiliates...... 3,435 7,091 3,462 1,632 2,196 3,462 2,196
Interest income -- other......... 886 3,748 7,029 5,477 1,575 7,029 1,575
Other income (expense), net...... (379) (272) (1,104) (531) (31) (1,492) (786)
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total.......................... $ (10,830) $ (20,975) $ (43,038) $ (16,709) $ (33,713) $ (109,507) $ (61,224)
Income before income taxes and
minority interest................ $ 121,521 $ 222,759 $ 244,650 $ 146,779 $ 5,147 $ 274,186 $ 43,497
Provision for income taxes......... -- -- -- -- -- (9,513) (5,369)
---------- ---------- ---------- ---------- ---------- ---------- ----------
Income before minority interest.... $ 121,521 $ 222,759 $ 244,650 $ 146,779 $ 5,147 $ 264,673 $ 38,128
Minority interest.................. (1,226) (2,253) (2,472) (1,478) (30) (7,276) (3,067)
---------- ---------- ---------- ---------- ---------- ---------- ----------
Net income......................... $ 120,295 $ 220,506 $ 242,178 $ 145,301 $ 5,117 $ 257,397 $ 35,061
========== ========== ========== ========== ========== ========== ==========
BASIC EARNINGS PER UNIT(1):
Net income per common and
subordinated unit................ $ 0.90 $ 1.63 $ 1.70 $ 1.06 $ 0.01 $ 1.69 $ 0.20
========== ========== ========== ========== ========== ========== ==========
DILUTED EARNINGS PER UNIT(1):
Net income per common, subordinated
and special unit................. $ 0.82 $ 1.32 $ 1.39 $ 0.85 $ 0.01 $ 1.39 $ 0.17
========== ========== ========== ========== ========== ========== ==========
BALANCE SHEET DATA (AT PERIOD END):
Total assets....................... $1,494,952 $1,951,368 $2,431,193 $2,441,993 $2,792,376 $4,165,659
Total debt......................... 295,000 403,847 855,278 855,608 1,223,552 2,311,278
Partners' equity................... 789,465 935,959 1,146,922 1,000,704 1,045,846 1,226,279
OTHER FINANCIAL DATA:
Cash flows from (used in) operating
activities....................... $ 177,953 $ 360,870 $ 283,328 $ 90,595 $ 45,183
Cash flows from (used in) investing
activities....................... (271,229) (268,798) (491,213) (397,474) (431,655)
Cash flows from (used in) financing
activities....................... 74,403 (36,893) 279,547 362,428 257,296
EBITDA............................. 147,050 267,058 320,392 180,349 60,580 $ 452,168 $ 141,491
Distributions received from
unconsolidated affiliates........ 6,008 37,267 45,054 13,212 29,133
OPERATING DATA (IN MBPD, EXCEPT AS
NOTED):
Pipelines:
Major NGL and petrochemical
pipelines...................... 264 367 454 430 518 1,271 1,339
Natural gas pipelines (BBtu/d)... n/a n/a 1,349 1,263 1,262 1,349 1,262
Fractionation:
NGL fractionation................ 184 213 204 184 226 204 226
Isomerization.................... 74 74 80 82 80 80 80
Propylene fractionation.......... 28 33 31 30 55 31 55
Processing -- equity NGL
production....................... 67 72 63 54 78 63 78
Octane enhancement................. 5 5 5 4 5 5 5

---------------
(1) Pro forma net income per unit is computed by dividing the limited partners'
interest in net income by the number of units expected to be outstanding at
the closing of this offering.

S-8

RISK FACTORS

An investment in our common units involves risks. You should carefully
consider the following risk factors, together with all of the other information
included in, or incorporated by reference into, this prospectus supplement, in
evaluating an investment in our common units. If any of the following risks were
to occur, our business, financial condition or results of operations could be
adversely affected. In that case, the trading price of our common units could
decline and you could lose all or part of your investment. For information
concerning the other risks related to our business, please read the risk factors
included under the caption "Risk Factors" beginning on page 3 of the
accompanying prospectus.

RISKS RELATED TO OUR BUSINESS

AFTER INCURRING ADDITIONAL INDEBTEDNESS TO FINANCE THE MID-AMERICA AND
SEMINOLE ACQUISITIONS, WE HAVE SUBSTANTIAL LEVERAGE THAT MAY RESTRICT OUR FUTURE
FINANCIAL AND OPERATING FLEXIBILITY.

Our leverage is significant in relation to our partners' capital. At June
30, 2002, on a pro forma basis prior to giving effect to this offering, our
total outstanding debt, which represented approximately 69% of our total
capitalization, was approximately $2.5 billion. This debt includes the term loan
we incurred in July 2002 to finance the Mid-America and Seminole acquisitions,
of which $150 million matures on December 31, 2002, an additional $450 million
matures on March 31, 2003, and the remaining $600 million matures on July 30,
2003. For a description of our other debt obligations, please see "Management's
Discussion and Analysis of Financial Condition and Results of Operations -- Our
Debt Obligations" in our Quarterly Report on Form 10-Q for the period ended June
30, 2002.

Debt service obligations, restrictive covenants and maturities resulting
from this leverage may adversely affect our ability to finance future
operations, pursue acquisitions, fund other capital needs and pay distributions
to unitholders, and may make our results of operations more susceptible to
adverse economic or operating conditions. Our ability to repay, extend or
refinance our existing debt obligations and to obtain future credit will depend
primarily on our operating performance, which will be affected by general
economic, financial, competitive, legislative, regulatory, business and other
factors, many of which are beyond our control. We are prohibited from making
cash distributions during an event of default under any of our indebtedness.

We currently expect to meet our anticipated future cash requirements,
including scheduled debt repayments, through operating cash flow, proceeds from
this offering and the proceeds of one or more future equity or debt offerings.
However, our ability to access the capital markets for future offerings may be
limited by adverse market conditions resulting from, among other things, general
economic conditions, contingencies and uncertainties which are difficult to
predict and beyond our control. If we were unable to access the capital markets
for future offerings, we might be forced to seek extensions for some of our
short-term maturities or to refinance some of our debt obligations through bank
credit, as opposed to long-term public debt securities or equity securities. The
price and terms upon which we might receive such extensions or additional bank
credit could be more onerous than those contained in our existing debt
agreements. Any such arrangements could, in turn, increase the risk that our
leverage may adversely affect our future financial and operating flexibility.

ACQUISITIONS AND EXPANSIONS MAY AFFECT OUR BUSINESS BY SUBSTANTIALLY
INCREASING THE LEVEL OF OUR INDEBTEDNESS AND CONTINGENT LIABILITIES AND
INCREASING OUR RISKS OF BEING UNABLE TO EFFECTIVELY INTEGRATE THESE NEW
OPERATIONS.

From time to time, we evaluate and acquire assets and businesses that we
believe complement our existing operations. The Mid-America and Seminole
acquisitions represent significant acquisitions for us and, as a result, we may
encounter difficulties integrating these acquisitions with our existing
businesses and our other recent acquisitions without a loss of employees or
customers, a loss of revenues, an increase in operating or other costs or other
difficulties. In addition, we may not be able to realize the operating
efficiencies, competitive advantages, cost savings or other benefits expected
from these acquisitions. Any

S-9

future acquisitions may require substantial capital or the incurrence of
substantial indebtedness. As a result, our capitalization and results of
operations may change significantly following an acquisition, and you will not
have the opportunity to evaluate the economic, financial and other relevant
information that we will consider in determining the application of these funds
and other resources.

WE ARE EXPOSED TO PRICING RISKS ASSOCIATED WITH OUR PROCESSING SEGMENT.

Our Processing segment is directly exposed to commodity price risks, as we
take title to NGLs and are obligated under certain of our gas processing
contracts to pay market value for the energy extracted from the natural gas
stream. We are exposed to various risks, primarily that of commodity price
fluctuations in response to changes in supply, market uncertainty and a variety
of additional factors that are beyond our control. These pricing risks cannot be
completely hedged or eliminated, and any attempt to hedge pricing risks may
expose us to financial losses.

THE USE OF MTBE HAS RECENTLY BEEN CHALLENGED ON BOTH THE STATE AND FEDERAL
LEVELS.

Our Octane Enhancement segment represents our minority investment in BEF,
which currently produces MTBE. The production of MTBE is driven by oxygenated
fuels programs enacted under the federal Clean Air Amendments of 1990 and other
legislation. On March 25, 1999, the Governor of California ordered the phase-out
of MTBE in California based on allegations by several public advocacy and
protest groups that MTBE contaminates water supplies, causes health problems and
has not been as beneficial in reducing air pollution as originally contemplated.
California's deadline for the complete phase-out of MTBE is December 31, 2003.
At least twelve other states are following California's lead and either have
banned or currently are considering legislation to ban MTBE. Congress also is
contemplating a federal ban on MTBE. On April 25, 2002, the Senate approved an
energy bill that in part would ban the use of MTBE within four years of
enactment and require the use of ethanol as a substitute for MTBE. Several oil
companies have taken an early initiative to phase out the production of MTBE in
response to this legislative pressure and the possibility of additional
groundwater contamination lawsuits. If MTBE is banned or if its use is
significantly limited, the revenues we derive from our Octane Enhancement
segment would be materially reduced or eliminated.

TERRORIST ATTACKS AIMED AT OUR FACILITIES COULD ADVERSELY AFFECT OUR
BUSINESS.

Since the September 11, 2001 terrorist attacks on the United States, the
United States government has issued warnings that energy assets, including our
nation's pipeline infrastructure, may be the future target of terrorist
organizations. Any terrorist attack on our facilities, those of our customers
and, in some cases, those of other pipelines, could have a material adverse
effect on our business.

OUR BUSINESS REQUIRES EXTENSIVE CREDIT RISK MANAGEMENT THAT MAY NOT BE
ADEQUATE TO PROTECT AGAINST CUSTOMER NONPAYMENT.

As a result of business failures, revelations of material
misrepresentations and related financial restatements by several large,
well-known companies in various industries over the last year, there have been
significant disruptions and extreme volatility in the financial markets and
credit markets. Because of the credit intensive nature of the energy industry
and troubling disclosures by some large, diversified energy companies, the
energy industry has been especially impacted by these developments, with the
rating agencies downgrading a number of large energy-related companies.
Accordingly, in this environment we are exposed to an increased level of credit
and performance risk with respect to our customers. We cannot assure you that we
have adequately assessed the creditworthiness of our existing or future
customers or that there will not be an unanticipated deterioration in their
creditworthiness, which could have an adverse impact on us.

S-10

RISKS RELATED TO OUR PARTNERSHIP STRUCTURE

CASH DISTRIBUTIONS ARE NOT GUARANTEED AND MAY FLUCTUATE WITH OUR
PERFORMANCE AND THE ESTABLISHMENT OF FINANCIAL RESERVES.

Because distributions on our common units are dependent on the amount of
cash we generate, distributions may fluctuate based on our performance. We
cannot guarantee that the minimum quarterly distributions will be paid each
quarter. The actual amount of cash that is available to be distributed each
quarter will depend upon numerous factors, some of which are beyond our control
and the control of our general partner. These factors include but are not
limited to the following:

- the level of our operating costs;

- the level of competition in our business segments;

- prevailing economic conditions;

- the level of capital expenditures we make;

- the restrictions contained in our debt agreements and our debt service
requirements;

- fluctuations in our working capital needs;

- the cost of acquisitions, if any; and

- the amount, if any, of cash reserves established by our general partner,
in its discretion.

In addition, cash distributions are dependent primarily on cash flow,
including cash flow from financial reserves and working capital borrowings, and
not solely on profitability, which is affected by non-cash items. Therefore,
cash distributions might be made during periods when we record losses and might
not be made during periods when we record profits.

COST REIMBURSEMENTS DUE OUR GENERAL PARTNER MAY BE SUBSTANTIAL AND WILL
REDUCE OUR CASH AVAILABLE FOR DISTRIBUTION TO YOU.

Prior to making any distribution on our common units, we will reimburse our
general partner and its affiliates, including officers and directors of our
general partner, for expenses they incur on our behalf. The reimbursement of
expenses could adversely affect our ability to pay cash distributions to you.
Our general partner has sole discretion to determine the amount of these
expenses, subject to an annual limit. In addition, our general partner and its
affiliates may provide us other services for which we will be charged fees as
determined by our general partner.

OUR GENERAL PARTNER AND ITS AFFILIATES MAY HAVE CONFLICTS WITH OUR
PARTNERSHIP.

The directors and officers of our general partner and its affiliates have
duties to manage the general partner in a manner that is beneficial to its
members. At the same time, our general partner has duties to manage our
partnership in a manner that is beneficial to us. Therefore, our general
partner's duties to us may conflict with the duties of its officers and
directors to its members.

Such conflicts may include, among others, the following:

- decisions of our general partner regarding the amount and timing of cash
expenditures, borrowings, issuances of additional units and reserves in
any quarter may affect the level of cash available to pay quarterly
distributions to unitholders and the general partner;

- under our partnership agreement we reimburse our general partner for the
costs of managing and operating our partnership;

- affiliates of our general partner may compete with us in certain
circumstances;

S-11

- we do not have any employees and we rely solely on employees of the
general partner and its affiliates; and

- our general partner generally attempts to avoid liability for partnership
obligations and is permitted to protect its assets by the partnership
agreement.

YOU MAY NOT BE ABLE TO REMOVE OUR GENERAL PARTNER EVEN IF YOU WISH TO DO
SO.

Our general partner manages and operates our partnership. Unlike the
holders of common stock in a corporation, you will have only limited voting
rights on matters affecting our business. You will have no right to elect the
general partner or the directors of the general partner on an annual or other
continuing basis. Because the owners of our general partner own more than
one-third of our outstanding units, these owners have the practical ability to
prevent the removal of our general partner.

In addition, the following provisions of our partnership agreement may
discourage a person or group from attempting to remove our general partner or
otherwise change our management:

- if holders, including the general partner and its affiliates, of at least
66 2/3% of the units vote to remove the general partner without cause,
all remaining subordinated units will automatically convert into common
units and will share distributions with the existing common units pro
rata, existing arrearages on the common units will be extinguished and
the common units will no longer be entitled to arrearages if we fail to
pay the minimum quarterly distribution in any quarter. "Cause" means that
a court of competent jurisdiction has entered a final, non-appealable
judgment finding our general partner liable for actual fraud, gross
negligence or willful or wanton misconduct in its capacity as our general
partner.

- any units held by a person that owns 20% or more of any class of units
then outstanding, other than our general partner and its affiliates,
cannot be voted on any matter.

- the partnership agreement contains provisions limiting the ability of
unitholders to call meetings or to acquire information about our
operations, as well as other provisions limiting the unitholders' ability
to influence the manner or direction of management.

As a result of these provisions, the price at which the common units will
trade may be lower because of the absence or reduction of a takeover premium in
the trading price.

WE MAY ISSUE ADDITIONAL COMMON UNITS WITHOUT YOUR APPROVAL, WHICH WOULD
DILUTE YOUR EXISTING OWNERSHIP INTERESTS.

During the subordination period, our general partner may cause us to issue
up to 54,550,000 additional common units without your approval. Our general
partner may also cause us to issue an unlimited number of additional common
units, without your approval, in a number of circumstances, such as:

- the issuance of common units in connection with acquisitions that
increase cash flow from operations per unit on a pro forma basis;

- the conversion of subordinated units into common units;

- the conversion of special units into common units;

- the conversion of the general partner interest and the incentive
distribution rights into common units as a result of the withdrawal of
our general partner; or

- issuances of common units under our long-term incentive plan.

S-12

The issuance of additional common units or other equity securities of equal
or senior rank will have the following effects:

- your proportionate ownership interest in us will decrease;

- the amount of cash available for distribution on each unit may decrease;

- since a lower percentage of total outstanding units will be subordinated
units, the risk that a shortfall in the payment of the minimum quarterly
distribution will be borne by the common unitholders will increase;

- the relative voting strength of each previously outstanding unit may be
diminished; and

- the market price of the common units may decline.

After the end of the subordination period, we may issue an unlimited number
of limited partner interests of any type without the approval of the
unitholders. Our partnership agreement does not give the unitholders the right
to approve our issuance of equity securities ranking junior to the common units.

OUR GENERAL PARTNER HAS A LIMITED CALL RIGHT THAT MAY REQUIRE YOU TO SELL
YOUR UNITS AT AN UNDESIRABLE TIME OR PRICE.

If at any time our general partner and its affiliates own 85% or more of
the common units, our general partner will have the right, but not the
obligation, which it may assign to any of its affiliates or to us, to acquire
all, but not less than all, of the remaining common units held by unaffiliated
persons at a price not less than their then current market price. As a result,
you may be required to sell your common units at an undesirable time or price
and may therefore not receive any return on your investment. You may also incur
a tax liability upon a sale of your units.

YOU MAY NOT HAVE LIMITED LIABILITY IF A COURT FINDS THAT LIMITED PARTNER
ACTIONS CONSTITUTE CONTROL OF OUR BUSINESS.

Under Delaware law, you could be held liable for our obligations to the
same extent as a general partner if a court determined that the right of limited
partners to remove our general partner or to take other action under the
partnership agreement constituted participation in the "control" of our
business.

Under Delaware law, the general partner generally has unlimited liability
for the obligations of the partnership, such as its debts and environmental
liabilities, except for those contractual obligations of the partnership that
are expressly made without recourse to the general partner.

In addition, Section 17-607 of the Delaware Revised Uniform Limited
Partnership Act provides that, under some circumstances, a limited partner may
be liable to us for the amount of a distribution for a period of three years
from the date of the distribution.

TAX RISKS TO COMMON UNITHOLDERS

You are urged to read "Tax Considerations" beginning on page 23 of the
accompanying prospectus for a more complete discussion of the following federal
income tax risks related to owning and disposing of common units.

THE IRS COULD TREAT US AS A CORPORATION FOR TAX PURPOSES, WHICH WOULD
SUBSTANTIALLY REDUCE THE CASH AVAILABLE FOR DISTRIBUTION TO YOU.

The anticipated after-tax economic benefit of an investment in the common
units depends largely on our being treated as a partnership for federal income
tax purposes. We have not requested, and do not plan to request, a ruling from
the IRS on this or any other matter affecting us.

S-13

If we were classified as a corporation for federal income tax purposes, we
would pay federal income tax on our income at the corporate tax rate, which is
currently a maximum of 35%, and we likely would pay state taxes as well.
Distributions to you would generally be taxed again to you as corporate
distributions, and no income, gains, losses or deductions would flow through to
you. Because a tax would be imposed upon us as a corporation, the cash available
for distribution to you would be substantially reduced. Treatment of us as a
corporation would result in a material reduction in the after-tax return to you,
likely causing a substantial reduction in the value of the common units.

A change in current law or a change in our business could cause us to be
taxed as a corporation for federal income tax purposes or otherwise subject us
to entity-level taxation. Our partnership agreement provides that, if a law is
enacted or existing law is modified or interpreted in a manner that subjects us
to taxation as a corporation or otherwise subjects us to entity-level taxation
for federal, state or local income tax purposes, then the minimum quarterly
distribution and the target distribution levels will be decreased to reflect
that impact on us.

A SUCCESSFUL IRS CONTEST OF THE FEDERAL INCOME TAX POSITIONS WE TAKE MAY
ADVERSELY IMPACT THE MARKET FOR COMMON UNITS, AND THE COSTS OF ANY CONTESTS WILL
BE BORNE BY OUR UNITHOLDERS AND OUR GENERAL PARTNER.

We have not requested a ruling from the IRS with respect to any matter
affecting us. The IRS may adopt positions that differ from the conclusions of
our counsel expressed in the accompanying prospectus or from the positions we
take. It may be necessary to resort to administrative or court proceedings to
sustain our counsel's conclusions or the positions we take. A court may not
concur with our counsel's conclusions or the positions we take. Any contest with
the IRS may materially and adversely impact the market for common units and the
price at which they trade. In addition, the costs of any contest with the IRS,
principally legal, accounting and related fees, will be borne indirectly by our
unitholders and our general partner.

YOU MAY BE REQUIRED TO PAY TAXES EVEN IF YOU DO NOT RECEIVE ANY CASH
DISTRIBUTIONS.

You will be required to pay federal income taxes and, in some cases, state,
local and foreign income taxes on your share of our taxable income even if you
do not receive any cash distributions from us. You may not receive cash
distributions from us equal to your share of our taxable income or even equal to
the actual tax liability that results from your share of our taxable income.

TAX GAIN OR LOSS ON DISPOSITION OF COMMON UNITS COULD BE DIFFERENT THAN
EXPECTED.

If you sell your common units, you will recognize gain or loss equal to the
difference between the amount realized and your tax basis in those common units.
Prior distributions in excess of the total net taxable income you were allocated
for a common unit, which decreased your tax basis in that common unit, will, in
effect, become taxable income to you if the common unit is sold at a price
greater than your tax basis in that common unit, even if the price you receive
is less than your original cost. A substantial portion of the amount realized,
whether or not representing gain, may be ordinary income to you. Should the IRS
successfully contest some positions we take, you could recognize more gain on
the sale of units than would be the case under those positions, without the
benefit of decreased income in prior years. Also, if you sell your units, you
may incur a tax liability in excess of the amount of cash you receive from the
sale.

TAX-EXEMPT ENTITIES, REGULATED INVESTMENT COMPANIES AND FOREIGN PERSONS
FACE UNIQUE TAX ISSUES FROM OWNING COMMON UNITS THAT MAY RESULT IN ADVERSE TAX
CONSEQUENCES TO THEM.

Investment in common units by tax-exempt entities, such as individual
retirement accounts (known as IRAs), regulated investment companies (known as
mutual funds) and foreign persons raises issues unique to them. For example,
virtually all of our income allocated to unitholders who are organizations
exempt from federal income tax, including individual retirement accounts and
other retirement plans, will be unrelated business taxable income and will be
taxable to them. Very little of our income will be qualifying income to a
regulated investment company or mutual fund. Distributions to foreign persons
will be reduced by withholding taxes at the highest effective U.S. federal
income tax rate for individuals, and foreign persons will be required to file
federal income tax returns and pay tax on their share of our taxable income.

S-14

WE ARE REGISTERED AS A TAX SHELTER. THIS MAY INCREASE THE RISK OF AN IRS
AUDIT OF US OR A UNITHOLDER.

We are registered with the IRS as a "tax shelter." Our tax shelter
registration number is 9906100007. The tax laws require that some types of
entities, including some partnerships, register as "tax shelters" in response to
the perception that they claim tax benefits that may be unwarranted. As a
result, we may be audited by the IRS and tax adjustments could be made. Any
unitholder owning less than a 1% profits interest in us has very limited rights
to participate in the income tax audit process. Further, any adjustments in our
tax returns will lead to adjustments in our unitholders' tax returns and may
lead to audits of unitholders' tax returns and adjustments of items unrelated to
us. You will bear the cost of any expense incurred in connection with an
examination of your personal tax return and indirectly bear a portion of the
cost of an audit of us.

WE WILL TREAT EACH PURCHASER OF COMMON UNITS AS HAVING THE SAME TAX
BENEFITS WITHOUT REGARD TO THE UNITS PURCHASED. THE IRS MAY CHALLENGE THIS
TREATMENT, WHICH COULD ADVERSELY AFFECT THE VALUE OF OUR COMMON UNITS.

Because we cannot match transferors and transferees of common units, we
adopt depreciation and amortization positions that may not conform with all
aspects of applicable Treasury regulations. A successful IRS challenge to those
positions could adversely affect the amount of tax benefits available to you. It
also could affect the timing of these tax benefits or the amount of gain from
your sale of common units and could have a negative impact on the value of the
common units or result in audit adjustments to your tax returns.

YOU WILL LIKELY BE SUBJECT TO STATE AND LOCAL TAXES IN STATES WHERE YOU DO
NOT LIVE AS A RESULT OF AN INVESTMENT IN OUR COMMON UNITS.

In addition to federal income taxes, you will likely be subject to other
taxes, including state and local income taxes, unincorporated business taxes and
estate, inheritance or intangible taxes that are imposed by the various
jurisdictions in which we do business or own property and in which you do not
reside. You may be required to file state and local income tax returns and pay
state and local income taxes in many or all of the jurisdictions in which we do
business or own property. Further, you may be subject to penalties for failure
to comply with those requirements. It is your responsibility to file all United
States federal, state and local tax returns. Our counsel has not rendered an
opinion on the state or local tax consequences of an investment in the common
units.

S-15

USE OF PROCEEDS

We will receive net proceeds of approximately $178.6 million from the sale
of the 9,800,000 common units after deducting underwriting discounts and
commissions and estimated offering expenses. In connection with the offering, we
also will receive a capital contribution of $3.8 million from our general
partner to maintain its combined 2% general partner interest. The underwriters
will receive no discount or commission on the sale of 1,809,200 common units to
our senior management or their affiliates. If the underwriters exercise their
over-allotment option in full, we will receive net proceeds of approximately
$209.7 million, including the $4.4 million general partner proportionate
contribution.

We will use the net proceeds of this offering to repay a portion of the
indebtedness outstanding under our $1.2 billion senior unsecured 364-day term
loan that we incurred to finance the Mid-America and Seminole acquisitions. We
will use the proceeds from the general partner's capital contribution for the
repayment of debt. At October 2, 2002, the interest rate on the term loan was
3.2%. The term loan matures as follows: $150 million on December 31, 2002, $450
million on March 31, 2003 and $600 million on July 30, 2003. For a description
of the term loan, please read "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Our Liquidity and Capital
Resources -- Our Debt Obligations." Affiliates of some of the underwriters for
this offering, including Lehman Brothers Inc., RBC Dain Rauscher Inc. and
Wachovia Securities, Inc., are lenders to us under our term loan and will be
partially repaid with the net proceeds from this offering. Please read
"Underwriting."

PRICE RANGE OF COMMON UNITS AND DISTRIBUTIONS

On August 31, 2002, we had 131,894,766 common units outstanding,
beneficially held by approximately 9,900 holders. The common units are traded on
the NYSE under the symbol "EPD."

The following table sets forth, for the periods indicated, the high and low
closing sales price ranges for the common units, as reported on the NYSE
Composite Transaction Tape, and the amount, record date and payment date of the
quarterly cash distributions paid per common unit. The last reported sales price
of our common units on the NYSE on October 2, 2002 was $18.99 per common unit.

PRICE RANGES(1) CASH DISTRIBUTION HISTORY
--------------- ------------------------------------------
PER RECORD PAYMENT
HIGH LOW UNIT(1)(2) DATE DATE
------ ------ ---------- ------------- -------------

2000
1st Quarter.............................. $10.44 $ 9.13 $0.2500 Apr. 28, 2000 May 10, 2000
2nd Quarter.............................. 11.38 9.75 0.2625 Jul. 31, 2000 Aug. 10, 2000
3rd Quarter.............................. 14.47 11.07 0.2625 Oct. 31, 2000 Nov. 10, 2000
4th Quarter.............................. 15.94 11.75 0.2750 Jan. 31, 2001 Feb. 9, 2001
2001
1st Quarter.............................. $18.40 $13.25 $0.2750 Apr. 30, 2001 May 10, 2001
2nd Quarter.............................. 21.88 16.60 0.2938 Jul. 31, 2001 Aug. 10, 2001
3rd Quarter.............................. 24.18 19.75 0.3125 Oct. 31, 2001 Nov. 9, 2001
4th Quarter.............................. 26.30 21.80 0.3125 Jan. 31, 2002 Feb. 11, 2002
2002
1st Quarter.............................. $25.57 $23.13 $0.3350 Apr. 30, 2002 May 10, 2002
2nd Quarter.............................. 24.43 16.25 0.3350 Jul. 31, 2002 Aug. 12, 2002
3rd Quarter.............................. 22.00 16.75
4th Quarter (through October 2, 2002).... 19.28 18.99

---------------
(1) On February 27, 2002, we announced that our general partner approved a
2-for-1 split for each class of our partnership units. The partnership unit
split was accomplished by distributing one additional partnership unit for
each partnership unit outstanding on May 15, 2002 to holders of record on
April 30, 2002.

(2) On September 12, 2002, we announced that the board of directors of our
general partner approved an increase in our quarterly distributions to
$0.345 per common unit, or $1.38 per common unit on an annualized basis.

S-16

CAPITALIZATION

The following table sets forth our capitalization as of June 30, 2002 on:

- a consolidated historical basis;

- a pro forma basis to give effect to adjustments related to the
Mid-America and Seminole acquisitions, including our $1.2 billion senior
unsecured 364-day term loan; and

- a pro forma as adjusted basis to give effect to the common units offered
by this prospectus supplement, our general partner's proportionate
capital contribution and the application of the net proceeds from this
offering to repay a portion of indebtedness outstanding under our $1.2
billion senior unsecured 364-day term loan.

You should read our financial statements and notes that are included
elsewhere in this prospectus supplement and that are incorporated by reference
for additional information about our capital structure.

AS OF JUNE 30, 2002
---------------------------------------
CONSOLIDATED PRO FORMA
HISTORICAL PRO FORMA AS ADJUSTED
------------ ---------- -----------
(UNAUDITED)

(Dollars in thousands)
Cash and cash equivalents................................ $ 7,929 $ 19,089 $ 19,089
========== ========== ==========
Short-term debt:
364-Day Term Loan, due July 2003....................... $ -- $1,200,000 $1,021,371
Seminole debt, current maturities (1).................. -- 15,000 15,000
Long-term debt:
364-Day Credit Facility, due November 2002 (2)......... 138,000 148,000 144,355
Multi-Year Credit Facility, due November 2005.......... 230,000 230,000 230,000
Senior Notes A, 8.25% fixed rate, due March 2005....... 350,000 350,000 350,000
MBFC Loan, 8.70% fixed rate, due March 2010............ 54,000 54,000 54,000
Senior Notes B, 7.50% fixed rate, due February 2011.... 450,000 450,000 450,000
Seminole debt, 6.67% fixed-rate (1).................... -- 45,000 45,000
---------- ---------- ----------
Total principal amount................................... $1,222,000 $2,492,000 $2,309,726
Unamortized balance of increase in fair value related to
hedging a portion of fixed-rate debt................... 1,895 1,895 1,895
Less unamortized discount:
Senior Notes A......................................... (99) (99) (99)
Senior Notes B......................................... (244) (244) (244)
---------- ---------- ----------
Total debt............................................... $1,223,552 $2,493,552 $2,311,278
Minority interest........................................ 10,818 65,146 66,987
Partners' equity:
Common units........................................... $ 589,504 $ 589,504 $ 768,133
Subordinated units..................................... 165,818 165,818 165,818
Special units.......................................... 296,634 296,634 296,634
Treasury units......................................... (16,736) (16,736) (16,736)
General partner interests.............................. 10,626 10,626 12,430
---------- ---------- ----------
Total partners' equity.............................. $1,045,846 $1,045,846 $1,226,279
---------- ---------- ----------
Total capitalization..................................... $2,280,216 $3,604,544 $3,604,544
========== ========== ==========

---------------
(1) In December 1993, Seminole Pipeline Company issued $75 million of its 6.67%
senior unsecured notes in a private placement. These notes are payable at
$15 million annually each December 1 commencing in 2001 through 2005. This
debt is being incorporated into our capitalization amounts as a result of
our acquisition of a 78% ownership interest in the Seminole pipeline system.

(2) Under the terms of this facility, the Operating Partnership has the option
to convert this facility into a term loan due November 15, 2003. Our
management intends to refinance this obligation with a similar obligation at
or before maturity.

S-17

SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA

The following tables set forth for the periods and at the dates indicated
selected historical financial and operating data for us, Mid-America and
Seminole and selected pro forma financial and operating data for us. The
selected historical income statement data for each of the three years in the
period ended December 31, 2001 and the selected balance sheet data for each of
the two years in the period ended December 31, 2001 are derived from and should
be read in conjunction with the audited financial statements for these periods
included elsewhere in this prospectus supplement. The selected historical data
for the six month periods ending June 30, 2001 and 2002 are derived from and
should be read in conjunction with the unaudited financial statements included
elsewhere in this prospectus supplement. The tables should be read together with
"Management's Discussion and Analysis of Financial Condition and Results of
Operations."

The summary pro forma financial statements of Enterprise Products Partners
show the pro forma effect of:

- the Mid-America and Seminole acquisitions including the $1.2 billion
senior unsecured 364-day term loan;

- the propylene fractionation and storage business acquired from
Diamond-Koch in 2002 and the acquisition of Acadian Gas in 2001;

- the completion of this offering;

- the general partner's proportionate capital contribution; and

- the application of the net proceeds from this offering to repay a portion
of indebtedness outstanding under the term loan.

S-18

ENTERPRISE PRODUCTS PARTNERS L.P.

S-19

MID-AMERICA PIPELINE SYSTEM

HISTORICAL
---------------------------------------------------------
SIX MONTHS
FOR THE YEAR ENDED DECEMBER 31, ENDED JUNE 30,
--------------------------------- --------------------
1999 2000 2001 2001 2002
--------- -------- -------- -------- --------
(UNAUDITED)

(Dollars in thousands)
INCOME STATEMENT DATA:
Revenues................................................... $ 190,686 $209,895 $214,518 $102,244 $109,865
Costs and expenses:
Operating costs and expenses............................... 87,623 105,591 125,349 67,870 45,111
Selling, general and administrative expenses............... 28,718 29,307 28,364 13,807 15,130
--------- -------- -------- -------- --------
Total.................................................... 116,341 134,898 153,713 81,677 60,241
--------- -------- -------- -------- --------
Operating income........................................... 74,345 74,997 60,805 20,567 49,624
Other income (expense):
Interest expense........................................... (7,673) (13,500) (12,700) (6,947) (4,432)
Other, net................................................. 822 880 (1,035) 89 (748)
--------- -------- -------- -------- --------
Total.................................................... (6,851) (12,620) (13,735) (6,858) (5,180)
--------- -------- -------- -------- --------
Income before income taxes................................. 67,494 62,377 47,070 13,709 44,444
Provision for income taxes................................. (23,651) (22,826) (17,445) (4,894) (16,604)
--------- -------- -------- -------- --------
Net income................................................. $ 43,843 $ 39,551 $ 29,625 $ 8,815 $ 27,840
========= ======== ======== ======== ========
BALANCE SHEET DATA (AT PERIOD END):
Total assets............................................... $736,783 $710,835 $681,603
Long-term debt............................................. 90,000 90,000 90,000
Owner equity............................................... 358,184 387,809 426,459
OTHER FINANCIAL DATA:
Cash flows from (used in) operating activities............. $ 124,367 $ 20,724 $ 17,893 $ 3,402 $ 2,090
Cash flows from (used in) investing activities............. (124,367) (20,724) (17,893) (3,402) (2,090)
EBITDA..................................................... 94,187 100,877 84,771 33,048 61,167

SEMINOLE PIPELINE COMPANY

HISTORICAL
-------------------------------------------------------
SIX MONTHS
FOR THE YEAR ENDED DECEMBER 31, ENDED JUNE 30,
-------------------------------- -------------------
1999 2000 2001 2001 2002
-------- -------- -------- ------- --------
(UNAUDITED)

(Dollars in thousands)
INCOME STATEMENT DATA:
Revenues................................................... $ 64,210 $ 66,609 $ 65,800 $30,880 $ 34,856
Costs and expenses:
Operating costs and expenses............................... 27,278 37,293 33,539 16,430 17,315
Selling, general and administrative expenses............... 1,035 1,700 1,535 750 796
-------- -------- -------- ------- --------
Total.................................................... 28,313 38,993 35,074 17,180 18,111
-------- -------- -------- ------- --------
Operating income........................................... 35,897 27,616 30,726 13,700 16,745
Other income (expense):
Interest expense........................................... (5,002) (5,003) (5,160) (2,450) (2,006)
Other, net................................................. 670 (1,542) 662 (9) (7)
-------- -------- -------- ------- --------
Total.................................................... (4,332) (6,545) (4,498) (2,459) (2,013)
-------- -------- -------- ------- --------
Income before income taxes................................. 31,565 21,071 26,228 11,241 14,732
Provision for income taxes................................. (11,611) (7,590) (9,470) (3,837) (5,347)
-------- -------- -------- ------- --------
Net income................................................. $ 19,954 $ 13,481 $ 16,758 $ 7,404 $ 9,385
======== ======== ======== ======= ========
BALANCE SHEET DATA (AT PERIOD END):
Total assets............................................... $280,940 $282,399 $279,739
Long-term debt, including current maturities............... 75,000 60,000 60,000
Owner equity............................................... 121,125 133,083 135,768
OTHER FINANCIAL DATA:
Cash flows from (used in) operating activities............. $ 19,248 $ 35,046 $ 25,343 $ 8,369 $ 4,096
Cash flows from (used in) investing activities............. (1,946) (795) (565) (286) (2,749)
Cash flows from (used in) financing activities............. (24,000) (31,590) (19,800) (2,000) (6,700)
EBITDA..................................................... 46,692 36,257 41,587 18,786 21,861

S-20

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

The following presentation of Management's Discussion and Analysis of
Financial Condition and Results of Operations is not complete and is qualified
in its entirety by reference to the information presented in (i) Item 7 of our
Annual Report on Form 10-K for the year ended December 31, 2001, (ii) Item 2 of
our Quarterly Reports on Form 10-Q for the periods ended March 31, 2002 and June
30, 2002 and (iii) Items 2 and 7 of our Current Report on Form 8-K/A (Amendment
No. 1) filed with the Commission on September 26, 2002, which are incorporated
by reference herein.

ENTERPRISE PRODUCTS PARTNERS L.P.

INTRODUCTION

We are a leading North American midstream energy company that provides a
wide range of services to producers and consumers of natural gas and NGLs. Our
asset platform in the Gulf Coast region, combined with our recently acquired
Mid-America and Seminole pipeline systems, creates the only integrated North
American natural gas and NGL transportation, fractionation, processing, storage
and import/export network. We provide integrated services to our customers and
generate fee-based cash flow from multiple sources along our natural gas and NGL
"value chain." Our business has five reportable segments:

Fractionation. Our Fractionation segment includes eight NGL fractionators,
the largest commercial isomerization complex in the United States and four
propylene fractionation facilities. NGL fractionators separate mixed NGL
streams, which are produced as by-products of natural gas production and crude
oil refining, into discrete NGL products: ethane, propane, isobutane, normal
butane and natural gasoline. Our isomerization complex converts normal butane
into mixed butane, which is subsequently fractionated into normal butane,
isobutane and high purity isobutane. Our propylene fractionators separate
refinery-sourced propane/propylene mix into propylene, propane and mixed butane.

RECENT ACQUISITIONS AND DEVELOPMENT PROJECTS

On July 31, 2002, we completed the acquisition of a 98% indirect ownership
interest in the Mid-America pipeline system and a 78% indirect ownership
interest in the Seminole pipeline system from Williams for approximately $1.2
billion in cash.

The acquisition of the Mid-America and Seminole pipeline systems was
financed with a $1.2 billion senior unsecured 364-day term loan. The net
proceeds of this offering will be used to reduce indebtedness outstanding under
this term loan. These acquisitions will be reflected in the operating results of
our pipeline segment from the date of the acquisitions. We have included in this
prospectus supplement financial data for the Mid-America and Seminole pipeline
systems. Additionally, we have included a discussion of the results of
operations for the Mid-America and Seminole pipeline systems.

S-21

Including Mid-America and Seminole, we have completed acquisitions and
investments having a combined value of over $3.1 billion during the last three
years. These include $1.8 billion in our Pipelines segment, $281 million in our
Fractionation segment and $529 million in our Processing segment. These
acquisitions and investments are reflected in our historical financial
statements commencing as of the date of acquisition. Our key investments and
acquisitions include:

- $239 million paid to purchase a controlling interest in a propylene
fractionation facility and related assets in Mont Belvieu (2002);

- $130 million paid to purchase storage assets in Mont Belvieu (2002);

- $112 million invested in four Gulf of Mexico natural gas pipeline systems
(2001);

- $244 million paid to acquire the Acadian Gas natural gas pipeline network
(2001);

- $100 million paid to acquire the Lou-Tex Propylene pipeline (2000);

- $42 million paid to acquire an additional interest in the Mont Belvieu
NGL fractionation facility (1999); and

- $529 million paid to acquire TNGL's natural gas processing and NGL
businesses (1999).

OUR RESULTS OF OPERATIONS

Our management evaluates segment performance based on gross operating
margin. Gross operating margin for each segment represents operating income
before depreciation and amortization, lease expense obligations retained by
EPCO, gains and losses on the sale of assets and selling, general and
administrative expenses. Segment gross operating margin is exclusive of interest
expense, interest income amounts, dividend income, minority interest,
extraordinary charges and other income and expense transactions.

We include equity earnings from unconsolidated affiliates in segment gross
operating margin and as a component of revenues. Our equity investments with
industry partners are a vital component of our business strategy and a means by
which we conduct our operations to align our interests with a supplier of raw
materials to a facility or a consumer of finished products from a facility. This
method of operation also enables us to achieve favorable economies of scale
relative to the level of investment and business risk assumed versus what we
could accomplish on a stand alone basis. Many of these businesses perform
supporting or complementary roles to our other business operations. For example,
we use the Promix NGL fractionator to process NGLs extracted by our gas plants.
The NGLs received from Promix then can be sold by our merchant businesses.

S-22

SIX MONTHS ENDED JUNE 30, 2002 COMPARED TO SIX MONTHS ENDED JUNE 30, 2001

Our gross operating margin amounts by segment along with a reconciliation
to consolidated operating income were as follows for the periods indicated:

SIX MONTHS ENDED
JUNE 30,
-------------------
2001 2002
-------- -------
(IN THOUSANDS)

Gross operating margin by segment:
Pipelines................................................. $ 42,819 $64,858
Fractionation............................................. 58,471 58,230
Processing................................................ 96,510 (34,558)
Octane enhancement........................................ 5,402 5,882
Other..................................................... 946 (1,061)
-------- -------
Total gross operating margin................................ $204,148 $93,351
Depreciation and amortization............................. 21,822 34,199
Retained lease expense, net............................... 5,320 4,578
Loss (gain) on sale of assets............................. (387) 12
Selling, general and administrative expenses.............. 13,905 15,702
-------- -------
Consolidated operating income............................... $163,488 $38,860
======== =======

Our significant plant production and other volumetric data were as follows
for the periods indicated (all data is expressed in MBPD, net, except for
natural gas pipelines, which is expressed in BBtu/d, net):

SIX MONTHS ENDED
JUNE 30,
----------------
2001 2002
------ ------

Pipelines
Major NGL and petrochemical pipelines..................... 430 518
Natural gas pipelines..................................... 1,263 1,262
Fractionation
NGL fractionation......................................... 184 226
Isomerization............................................. 82 80
Propylene fractionation................................... 30 55
Processing -- equity NGL production......................... 54 78
Octane enhancement.......................................... 4 5

PIPELINES

Our Pipelines segment recognized $64.9 million in gross operating margin
for the first six months of 2002 compared to $42.8 million during the same
period in 2001. These results do not include the results of operations related
to the Mid-America and Seminole pipeline systems. Net pipeline volumes (on an
energy equivalent basis) were 850 MBPD during the 2002 period versus 762 MBPD
during the 2001 period. The largest factor in the difference in margin between
the two periods is the margin contribution from the storage assets we acquired
from Diamond-Koch in January 2002. For the first six months of 2002, these
acquired assets added $8.2 million to the gross operating margin of this
segment. Other significant year-to-date differences are as follows:

- The 2002 period includes six months of Acadian Gas margins whereas the
2001 period includes only three months (we acquired Acadian Gas on April
1, 2001). The additional quarter's worth of margin in the 2002 period
accounts for $4.2 million of the overall increase in segment margin.

S-23

- Margin from the Louisiana Pipeline System for the 2002 period increased
$5.5 million over the 2001 period primarily due to higher NGL throughput
rates. NGL transport volumes increased to 182 MBPD during the first six
months of 2002 compared to 119 MBPD during the first six months of 2001.
The lower throughput rates during the 2001 period were primarily due to
decreased NGL extraction rates at gas processing plants during the first
half of 2001 caused by high natural gas prices.

- Equity earnings from EPIK's export terminal increased $2.7 million
period-to-period due to a strong export market during the first quarter
of 2002. Unusually high domestic prices for propane-related products in
the first half of 2001 decreased export opportunities. Product prices
during the first quarter of 2002 presented EPIK with a more favorable
export environment relative to the first quarter of 2001.

- Margin from our Lou-Tex NGL pipeline system increased $1.9 million
period-to-period primarily due to a 13 MBPD increase in transportation
volumes.

- Margin from the Lou-Tex Propylene pipeline decreased $2.6 million
period-to-period primarily due to lower pipeline throughput rates and
higher operating costs. The reduction in volumes is generally
attributable to a decline in petrochemical production by shippers.

- Margin from our Houston Ship Channel NGL import facility decreased $1.7
million period-to-period primarily due to a decline in mixed butane
imports.

- Margin from our Gulf of Mexico natural gas pipelines decreased $0.5
million period-to-period due to mechanical problems at certain Gulf of
Mexico production platforms. These platforms recommenced production in
May 2002.

FRACTIONATION

Fractionation gross operating margin was $58.2 million for the first six
months of 2002 versus $58.5 million for the first six months of 2001. NGL
fractionation margin decreased $2.8 million during the 2002 period when compared
to the 2001 period. NGL fractionation net volumes improved to 226 MBPD during
the first six months of 2002 versus 184 MBPD for the same period in 2001. NGL
fractionation volumes during the first quarter of 2001 were unusually low due to
reduced NGL extraction rates at gas processing plants caused by abnormally high
natural gas prices (which resulted in a decrease in mixed NGL volumes available
for fractionation). The decrease in NGL fractionation margin for the 2002 period
is primarily due to the following:

- non-routine maintenance charges at our Mont Belvieu facility in the first
quarter of 2002;

- a decrease in tolling fees per gallon at our Mont Belvieu facility due to
competition at this industry hub partially offset by a 12 MBPD increase
in fractionation volumes; and

- lower in-kind fee revenue at our Norco plant caused by lower NGL prices
in 2002 relative to 2001.

The negative factors were partially offset by increased margins at other
facilities due to higher processing volumes.

Our isomerization business posted a $9.9 million decrease in margin for the
first six months of 2002 when compared to the first six months of 2001.
Isomerization volumes decreased to 80 MBPD during the 2002 period versus 82 MBPD
during the 2001 period. The decrease in margin is primarily due to lower
isomerization fees per gallon. Certain of our isomerization tolling fees are
indexed to historical natural gas prices and were positively impacted when the
price of natural gas was at historically high levels during the first quarter of
2001 and negatively impacted by lower gas prices in 2002.

For the first six months of 2002, gross operating margin from propylene
fractionation was $11.6 million higher than the same period in 2001. The first
six months of 2002 includes $10.4 million in margin from the propylene
fractionation business we acquired from Diamond-Koch in February 2002. The
remainder of the increase in margin is primarily due to lower energy-related
costs at our other Mont Belvieu propylene fractionation facilities attributable
to lower natural gas prices between periods. Net volumes at our propylene
fractionation facilities increased to 55 MBPD for the first six months of 2002
compared to 30 MBPD for the

S-24

first six months of 2001. Of the 25 MBPD increase in 2002 volumes, 24 MBPD is
attributable to operations acquired from Diamond-Koch.

PROCESSING

Gross operating margin was a loss of $34.6 million for the first six months
of 2002 compared to $96.5 million for the first six months of 2001. Our
processing operating margin was significantly affected by hedging gains in 2001
and hedging losses in 2002. Eliminating the effects of our hedging program,
gross operating margin would have been $16.3 million for the first six months of
2002, compared to $26.2 million for the first six months of 2001.

Our equity NGL production averaged 78 MBPD during the 2002 period versus 54
MBPD during the 2001 period. Equity NGL production during the 2001 period
reflected reduced NGL extraction rates at our gas plants resulting from
abnormally high natural gas prices (which negatively affected operating costs),
particularly during the first quarter of 2001. In general, prices received for
our NGL production approximated a weighted-average of 36 CPG for the six months
ended June 30, 2002, compared to 56 CPG for the six months ended June 30, 2001.
The cost of natural gas averaged $2.86 per MMBtu during the 2002 period versus
$5.85 per MMBtu during the 2001 period. Of the $131.1 million decrease in margin
between periods, the significant differences are as follows:

- We recorded a loss of $50.9 million from our commodity hedging activities
during the first six months of 2002, of which $45.1 million of the loss
was recognized during the first quarter of 2002. This compares to $70.3
million of income from such activities during the first six months of
2001. This change in results accounts for $121.2 million of the decrease
in margin.

- Prior year margin benefited from unusually strong demand for propane for
heating in the first quarter of 2001 and isobutane for refining in the
second quarter of 2001. The higher prices caused by the extraordinary
demand for these products during the 2001 periods did not recur during
the 2002 period.

- Lastly, the decline in commodity hedging results and propane and
isobutane demand was offset by a favorable decrease in NGL inventory
valuation adjustments between the two quarters and improved processing
margins. Processing economics improved period to period as a result of
lower natural gas prices during the 2002 period relative to the 2001
period which in turn resulted in higher equity NGL production rates
during 2002.

Impact of Commodity Hedging Activities on Our Results of Operations. To
manage the risks associated with our Processing segment, from time to time we
enter into commodity financial instruments to hedge our exposure to price risks
associated with natural gas, NGL production and inventories, firm commitments
and certain anticipated transactions. We employ various hedging strategies to
mitigate the effects of fluctuating commodity prices (primarily NGL product and
natural gas prices) on margins.

One type of hedging strategy, employed in late 2000 and extending through
March 2002, was based on the historical relationship between natural gas prices
and NGL product prices. This type of hedging strategy utilized the forward sale
of natural gas at a fixed-price with the expected margin on the settlement of
the position offsetting or mitigating changes in the anticipated margins on NGL
merchant activities and the value of equity NGL production. Throughout 2001,
this strategy proved successful for us as the price of natural gas declined
relative to our fixed positions and was responsible for $101.3 million in income
we recorded from commodity hedging activities for that year. In late March 2002,
the effectiveness of this hedging strategy deteriorated due to a rapid increase
in natural gas prices resulting in losses on our fixed-price natural gas
financial instruments which were not offset by increased gas processing margins.
As a result, we recognized a loss on these hedging activities of $45.1 million
in the first quarter of 2002.

Due to the inherent uncertainty surrounding pricing in the markets, we
decided to discontinue the use of this hedging strategy. By late April 2002, we
had generally closed out our hedging positions, though not before the value of
the portfolio had declined by another $5.7 million. As a result, the total gain
from this strategy in fiscal 2001 was approximately $101.3 million and the total
loss from this strategy during fiscal 2002 was $50.8 million. Of the $50.8
million in losses from this strategy recorded during 2002, $7.6 million

S-25

was related to mark-to-market income from these instruments that we recognized
in the fourth quarter of 2001. The remaining $43.2 million represents our cash
exposure from these losses of which $31.9 million had been paid to
counterparties through June 30, 2002. We expect to pay the remaining $11.3
million to counterparties over the remainder of 2002.

Our current hedging strategies primarily cover the price risk associated
with certain NGL product inventories and fuel costs. We do not expect any
material impact on our liquidity or financial results from the settlement of
these commodity financial instruments, which settle primarily in the fourth
quarter of 2002 and the first quarter of 2003. The market value of these
instruments at June 30, 2002 was a net payable of $0.3 million. From a cash flow
sensitivity standpoint, if the commodity prices underlying these instruments
were to increase by 10% from the levels they were at on June 30, 2002, the
amount we would have to pay counterparties would increase to $0.8 million from
$0.3 million. Likewise, if the underlying prices decreased by 10%, we would
receive cash of $0.1 million from counterparties as opposed to paying $0.3
million.

OCTANE ENHANCEMENT

Equity earnings from our BEF investment improved to $5.9 million for the
first six months of 2002 from $5.4 million for the first six months of 2001. The
improvement is primarily due to a 24% increase in MTBE production during the
2002 period due to less maintenance downtime, offset by the impact of lower
overall MTBE prices period-to-period which affected margins.

ADDITIONAL MATTERS

Selling, general and administrative expenses. Selling, general and
administrative expenses for the first six months of 2002 increased $1.8 million
when compared to the first six months of 2001. This increase is primarily due to
the additional staff and resources acquired as a result of business
acquisitions.

Interest expense. Interest expense increased between the second quarters
of 2002 and 2001 and the year-to-date periods primarily due to additional
borrowings we made in conjunction with the Diamond-Koch acquisitions and
investments in inventories. Also, the first quarter of 2001 includes a $9.3
million benefit related to our interest rate swaps which did not reoccur in
2002.

YEAR ENDED DECEMBER 31, 2001 COMPARED TO YEAR ENDED DECEMBER 31, 2000

Our gross operating margin by segment along with a reconciliation to
consolidated operating income for the years presented were as follows:

FOR YEAR ENDED
DECEMBER 31,
-------------------
2000 2001
-------- --------
(IN THOUSANDS)

Gross operating margin by segment:
Pipelines................................................. $ 56,099 $ 96,569
Fractionation............................................. 129,376 118,610
Processing................................................ 122,240 154,989
Octane enhancement........................................ 10,407 5,671
Other..................................................... 2,493 944
-------- --------
Total gross operating margin................................ $320,615 $376,783
Depreciation and amortization............................. 35,621 48,775
Retained lease expense, net............................... 10,645 10,414
Loss (gain) on sale of assets............................. 2,270 (390)
Selling, general and administrative expenses.............. 28,345 30,296
-------- --------
Consolidated operating income............................... $243,734 $287,688
======== ========

S-26

Our significant plant production and other volumetric data for the years
presented were as follows (all data is expressed in MBPD, net, except for
natural gas pipelines, which is expressed in BBtu/d, net):

FOR YEAR ENDED
DECEMBER 31,
---------------
2000 2001
----- ------

Pipelines
Major NGL and petrochemical pipelines..................... 367 454
Natural gas pipelines..................................... n/a 1,349
Fractionation
NGL fractionation......................................... 213 204
Isomerization............................................. 74 80
Propylene fractionation................................... 33 31
Processing -- equity NGL production......................... 72 63
Octane enhancement.......................................... 5 5

PIPELINES

Our Pipelines segment posted a gross operating margin of $96.6 million in
2001, compared to $56.1 million in 2000. Of the $40.5 million increase in
margin, $20.0 million is attributable to natural gas pipelines acquired in 2001
(i.e., Acadian Gas and the Gulf of Mexico systems). Acadian Gas added $11.8
million in margin with the Gulf of Mexico systems contributing $8.2 million. On
a net basis, these pipeline systems transported an average of 1,349 BBtu/d of
natural gas.

Net NGL and petrochemical transportation volumes increased to 454 MBPD in
2001 from 367 MBPD in 2000. The majority of this increase is attributable to a
rise in commercial butane imports related to higher demand for isobutane
production. This activity contributed to a $5.2 million combined increase in
margin from our import terminal and HSC pipeline system. Additionally, margin
from the Louisiana Pipeline System increased $1.1 million in 2001 due to
increased demand for transportation services (with volumes increasing by 23 MBPD
in 2001, a 20% increase year-to-year). Also, the Lou-Tex NGL pipeline added
$12.2 million to margin during 2001 (construction of this system was completed
in the fourth quarter of 2000). This pipeline benefited from the movement of
mixed NGLs out of Louisiana to our Mont Belvieu processing facility during 2001.

FRACTIONATION

The gross operating margin from our Fractionation segment decreased to
$118.6 million in 2001 from $129.4 million in 2000. NGL fractionation margin for
2001 declined $21.0 million from 2000, primarily as the result of a $19.3
million decrease in "in-kind" fractionation fees at our Norco facility. An
in-kind arrangement allows us to receive NGL volumes in lieu of cash
fractionation fees. Norco is our only facility with this type of contract. The
decline in NGL fractionation margin is related to the NGL volumes received
during 2000 having a higher value than those received during 2001. Net volumes
at the NGL fractionation facilities decreased to 204 MBPD in 2001 compared to
213 MBPD in 2000. The decrease in throughput is due to lower NGL extraction
rates at gas processing facilities in early 2001 (due to the abnormally high
cost of natural gas) versus 2000 when the industry was maximizing NGL
production. The isomerization business posted an $8.4 million increase in margin
for 2001 over 2000 on volumes of 80 MBPD. Isomerization margins were bolstered
by increased demand during the second quarter of 2001 for services linked to
refinery activities, primarily gasoline blending. Gross operating margin from
propylene fractionation increased $0.3 million in 2001 over 2000 due to
additional margins from BRPC, which did not commence operations until July 2000.
Net volumes at our propylene fractionation facilities declined slightly to 31
MBPD in 2001 from 33 MBPD in 2000.

S-27

PROCESSING

Gross operating margin from our Processing segment was $155.0 million in
2001, up 27% from $122.2 million in 2000. The increase in margin is primarily
due to the positive impact of our commodity hedging activities.

2001 was a very challenging year for gas processors industry wide. The
volatility of natural gas prices and the depressed nature of NGL prices
throughout 2001 created an environment requiring processors to be proactive in
meeting the needs of the marketplace. The unusually poor processing economics of
the first quarter of 2001 (due to the abnormally high cost of energy relative to
the value of our NGL production during that time) yielded to improved market
conditions during the second half of 2001 as energy costs moderated. In general,
prices received for our NGL production approximated a weighted-average of 43 CPG
in 2001 compared to 57 CPG in 2000. In contrast, the cost of natural gas
averaged $4.20 per MMBtu in 2001 (peaking at near $10 per MMBtu during the first
quarter of 2001) versus $3.84 per MMBtu in 2000.

Equity NGL production averaged 63 MBPD in 2001 compared to 72 MBPD in 2000.
The decline in volume is related to the 2000 period reflecting near maximized
NGL recoveries supported by strong NGL economics. The 2001 equity NGL production
rate reflects less favorable extraction economics (as described above) but is
greatly improved relative to the first quarter of 2001's 46 MBPD when energy
costs peaked. With the improvement in processing margins in late 2001, we posted
equity NGL production of 80 MBPD during the fourth quarter of 2001.

In December 2001, Enron North America (the counterparty to some of our
commodity financial instruments) filed for protection under Chapter 11 of the
U.S. Bankruptcy Code. As a result, we recognized a charge to earnings of $10.6
million for all amounts owed to us by Enron. The Enron amounts were unsecured
and the amount that we may ultimately recover, if any, is not presently
determinable.

Our merchant activities benefited from strong demand for propane for
heating in the first quarter of 2001 and for isobutane for refining in the
second quarter of 2001. Overall, margin from merchant activities improved $9.9
million year-to-year. Processing margin also benefited from the reversal of $9.4
million in excess reserves associated with the gas processing plants.

OCTANE ENHANCEMENT

Equity earnings from our BEF investment declined $4.7 million year-to-year
on stable net volumes of 5 MBPD in both periods. The decrease in earnings is
primarily attributable to lower MTBE and byproduct prices.

ADDITIONAL MATTERS

Selling, general and administrative expenses. These expenses increased to
$30.3 million in 2001 from $28.3 million in 2000. The increase is primarily due
to expenses related to the additional staff and resources deemed necessary to
support our expansion activities resulting from acquisitions and other business
development.

Interest expense. Interest expense for 2001 increased by $19.1 million
over that for 2000. The increase is primarily due to the issuance of our $450
million of public debt in January 2001. The proceeds from this debt were used to
acquire our interest in the Stingray, Nautilus, Manta Ray and Nemo pipeline
systems from El Paso, to acquire Acadian Gas from Shell and to finance internal
growth and other general partnership purposes.

Interest expense for both 2001 and 2000 benefited from income attributable
to interest rate hedging activity. During the last two years, we used interest
rate swaps in order to effectively convert a portion of our fixed-rate debt into
variable-rate debt. With the decline in variable interest rates over the last
two years, our swaps provided income to offset fixed-rate-based interest
expense. For 2001, we recognized a $13.2 million benefit related to these swaps
compared with a $10.0 million benefit recorded in 2000.

S-28

During 2001, two of our three swaps that were outstanding at January 1,
2001 were terminated (closing instruments having a notional value of $100
million). One swap was terminated by a counterparty exercising its early
termination option while the other counterparty negotiated an early closeout of
its position. This left us with one swap outstanding at December 31, 2001 having
a notional amount of $54 million. This swap has an early termination option that
is exercisable in March 2003.

YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999

Our gross operating margin by segment along with a reconciliation to
consolidated operating income for the years presented were as follows:

FOR YEAR ENDED
DECEMBER 31,
--------------------
1999 2000
-------- --------
(IN THOUSANDS)

Gross operating margin by segment:
Pipelines................................................. $ 31,195 $ 56,099
Fractionation............................................. 110,424 129,376
Processing................................................ 28,485 122,240
Octane enhancement........................................ 8,183 10,407
Other..................................................... 908 2,493
-------- --------
Total gross operating margin................................ $179,195 $320,615
Depreciation and amortization............................. 23,664 35,621
Retained lease expense, net............................... 10,557 10,645
Loss (gain) on sale of assets............................. 123 2,270
Selling, general and administrative expenses.............. 12,500 28,345
-------- --------
Consolidated operating income............................... $132,351 $243,734
======== ========

FOR YEAR ENDED
DECEMBER 31,
---------------
1999 2000
----- -----

Pipelines
Major NGL and petrochemical pipelines..................... 264 367
Natural gas pipelines..................................... n/a n/a
Fractionation
NGL fractionation......................................... 184 213
Isomerization............................................. 74 74
Propylene fractionation................................... 28 33
Processing -- equity NGL production......................... 67 72
Octane enhancement.......................................... 5 5

PIPELINES

The gross operating margin from our Pipelines segment was $56.1 million in
2000 compared to $31.2 million in 1999. Overall NGL and petrochemical volumes
increased to 367 MBPD in 2000 from 264 MBPD in 1999. Generally, the $24.9
million increase in margin is attributable to the additional volumes and margins
contributed by the TNGL pipeline and storage assets, higher margins from the HSC
pipeline system and EPIK due to an increase in export volumes, the margins from
the Lou-Tex propylene pipeline that was purchased in March 2000 and margins from
the Lou-Tex NGL pipeline, which commenced operations in late November 2000. The
growth in export volumes is attributable to the installation of EPIK's new
chiller unit that began operations in the fourth quarter of 1999.

S-29

FRACTIONATION

The gross operating margin of our Fractionation segment increased to $129.4
million in 2000 from $110.4 million in 1999. The additional margin from the NGL
fractionators acquired from Shell in the TNGL acquisition was the primary reason
for a $29.7 million increase in NGL fractionation margin in 2000 over 1999.
Results for 1999 include five months of margin from the TNGL assets whereas the
2000 period includes twelve months. Net NGL fractionation volume increased to
213 MBPD in 2000 from 184 MBPD in 1999. The increase in net NGL fractionation
volume is attributable to higher production rates at our Mont Belvieu NGL
fractionator. Our ownership in this facility increased to 62.5% from 37.5% as a
result of the July 1999 MBA acquisition.

For 2000, gross operating margin from our isomerization business decreased
$7.8 million compared to 1999 primarily due to higher fuel and other operating
costs, plus the expenses related to the refurbishment of an isomerization unit.
Isomerization volumes were 74 MBPD in both 2000 and 1999. Gross operating margin
from propylene fractionation decreased $1.4 million in 2000 from 1999 levels
primarily due to higher energy costs. Net volumes at these facilities improved
to 33 MBPD in 2000 from 28 MBPD in 1999 due to the startup of the BRPC propylene
concentrator in July 2000.

PROCESSING

Our Processing segment generated $122.2 million in gross operating margin
during 2000 compared to $28.5 million in 1999. The $93.7 million increase is
primarily due to 2000 including twelve months of gas processing (and related
merchant activity) margins from the TNGL businesses, whereas 1999 includes only
five months. This segment benefited from a stronger NGL pricing environment in
2000 versus 1999 and a rise in equity NGL production from 67 MBPD in 1999 to 72
MBPD in 2000. In general, NGL prices approximated a weighted-average of 57 CPG
during 2000 compared to 35 CPG during 1999. The cost of natural gas averaged
$3.84 MMBtu during 2000 versus $2.23 per MMBtu during 1999.

OCTANE ENHANCEMENT

The gross operating margin from our Octane Enhancement segment increased to
$10.4 million in 2000 from $8.2 million in 1999. Equity earnings for 2000
improved over 1999 levels primarily due to higher than normal MTBE market prices
during the second and third quarters of 2000 and lower debt service costs (BEF
made its final note payment in May 2000 and, as a result, now owns the facility
debt-free). In addition, the 1999 period reflects a $1.5 million non-cash charge
related to the write-off of certain start-up expenses. MTBE production, on a net
basis, was 5 MBPD in both 2000 and 1999.

ADDITIONAL MATTERS

Selling, general and administrative expenses. These expenses increased to
$28.3 million in 2000 from $12.5 million in 1999. The increase is primarily due
to expenses related to the additional staff and resources deemed necessary to
support our expansion activities resulting from acquisitions and other business
development.

Interest expense. Interest expense increased to $33.3 million in 2000 from
$16.4 million in 1999. The increase is attributable to a rise in average debt
levels from $213 million in 1999 to $408 million in 2000. Debt levels have
increased over the previous year primarily due to capital expenditures for
assets such as the Lou-Tex propylene and Lou-Tex NGL pipelines and the issuance
of $404 million in debt instruments in March 2001. Interest expense for 2000
includes a $10.0 million benefit related to interest rate swaps.

S-30

OUR LIQUIDITY AND CAPITAL RESOURCES

Since our operating partnership owns substantially all of our consolidated
assets and conducts substantially all of our business and operations, the
following discussion of liquidity and capital resources constitutes combined (or
consolidated) information for our operating partnership and us. References to
partnership equity securities in this discussion pertain to units issued by us.
References to public debt pertain to those obligations issued by our operating
partnership and guaranteed by us.

GENERAL

Our primary cash requirements, in addition to normal operating expenses and
debt service, are for capital expenditures (both sustaining and
expansion-related), business acquisitions and distributions to partners. We
expect to fund our short-term needs for such items as operating expenses and
sustaining capital expenditures with operating cash flows. Capital expenditures
for long-term needs resulting from internal growth projects and business
acquisitions are expected to be funded by a variety of sources including (either
separately or in combination) cash flows from operating activities, borrowings
under bank credit facilities and the issuance of additional partnership equity
and public debt. Our quarterly cash distributions to partners are expected to be
funded primarily by current period operating cash flows, or to a lesser extent,
temporary borrowings under bank credit facilities or a combination thereof. Our
debt service requirements are expected to be funded by operating cash flows
and/or refinancing arrangements.

Our operating cash flows primarily reflect the effects of net income
adjusted for depreciation and amortization, equity income and cash distributions
from unconsolidated affiliates. The net effect of changes in operating accounts
is generally the result of timing of sales and purchases near the end of each
period. Our cash flows from operations are directly linked to earnings from our
business activities. Like our results of operations, these cash flows are
exposed to certain risks including fluctuations in NGL and energy prices,
competitive practices in the midstream energy industry and the impact of
operational and systems risks. The products that we process, sell or transport
are principally used as feedstocks in petrochemical manufacturing and motor
gasoline production and as fuel for residential and commercial heating. Reduced
demand for our products or services by industrial customers, whether because of
general economic conditions, reduced demand for the end products made with NGL
products, increased competition from petroleum-based products due to pricing
differences or other reasons, could have a negative impact on earnings and thus
the availability of cash from operating activities.

Certain of our liquidity and capital resource requirements are met using
borrowings under bank credit facilities and/or the issuance of additional
partnership equity or public debt (separately or in combination). As of June 30,
2002, total borrowing capacity under our revolving bank credit facilities was
$500 million of which $132 million was available. We have an effective $500
million universal shelf registration covering the issuance of an unspecified
amount of partnership equity or debt securities or a combination thereof. Our
plans for permanent financing of the approximately $1.2 billion Mid-America and
Seminole acquisitions include the issuance of equity and debt in amounts that
are consistent with our objective of maintaining our financial flexibility and
investment grade balance sheet.

We have the ability, under certain conditions during the subordination
period, to issue an unlimited number of common units to finance acquisitions and
capital improvements. The subordination period generally extends until the first
day of any quarter beginning after June 30, 2003 when certain financial tests
have been satisfied. We have the ability to issue an unlimited number of common
units for this type of expenditure if Adjusted Operating Surplus (as defined
within our partnership agreement) for the previous four fiscal quarter period
prior to the expenditure, on a pro forma basis, would have increased as a result
of such expenditure (i.e., would have been accretive on a pro forma basis for
each of the previous four fiscal quarters).

For those acquisitions and other transactions that do not qualify under the
aforementioned pro forma accretion test, we have 54,550,000 units available (and
unreserved) for general partnership purposes during the subordination period.
After the subordination period expires, we may issue an unlimited number of
units for any partnership purpose.

S-31

CREDIT RATINGS

On August 2, 2002, Moody's and S&P changed their ratings outlook regarding
our debt securities from "stable" to "negative." The ratings agencies did not
take any action to downgrade our ratings; they remain at Baa2 by Moody's and BBB
by S&P. Their negative outlook on our ratings reflects the execution risk they
see associated with our permanent financing plan for the Mid-America and
Seminole acquisitions, which includes the issuance of equity and long-term debt.
For a discussion of our debt associated with the Mid-America and Seminole
acquisitions, read "-- Our Liquidity and Capital Resources -- Our Debt
Obligations." The change in ratings outlook does not translate into any material
financial impact on our liquidity. Our management is committed to achieving its
goals of permanent financing for the Mid-America and Seminole acquisitions and
will actively pursue the appropriate mix and timing of offerings of equity and
debt that will maintain our investment grade balance sheet. We maintain regular
communications with these rating agencies which independently judge our
creditworthiness based on a variety of quantitative and qualitative factors.

CONSOLIDATED CASH FLOWS FOR SIX MONTHS ENDED JUNE 30, 2002 COMPARED TO SIX
MONTHS ENDED JUNE 30, 2001

Operating Cash Flows

Cash flow from operating activities was an inflow of $45.2 million for the
first six months of 2002 compared to $90.6 million during the same period in
2001. Excluding changes in operating accounts which are generally the result of
timing of sales and purchases near the end of each period, adjusted cash flow
from operating activities would be an inflow of $77.6 million for the first six
months of 2002 versus $121.2 million for the first six months of 2001. Cash flow
from operating activities before changes in operating accounts is an important
measure of our liquidity. It provides an indication of our success in generating
core cash flows from the assets and investments we own or have an interest in.
The $43.6 million decrease in adjusted cash flows between the two year-to-date
periods is primarily due to net hedging losses in 2002 versus net hedging income
in 2001 offset by:

- increased distributions from our unconsolidated affiliates; and

- an increase in operating earnings due to acquisitions.

We recorded $50.9 million in net commodity hedging losses during the first
six months of 2002 compared to $70.4 million of income during the first six
months of 2001. Of the recorded hedging loss for the 2002 period, we have
realized (i.e., paid out to counterparties) $31.9 million of this loss. The
difference of $19.0 million between the recorded loss and the realized loss
represents the non-cash change in market value of the overall portfolio between
December 31, 2001 and June 30, 2002. At June 30, 2002, the market value of the
commodity financial instruments that were outstanding was a payable of $11.1
million, which we expect to pay to counterparties over the remainder of the
2002.

We discontinued the hedging strategy underlying the $50.9 million in losses
in April 2002. This strategy had helped create essentially all of the $70.3
million in income from commodity hedging activities we recorded during the first
six months of 2001, of which $17.9 million had been received from counterparties
through June 30, 2001. Please read "-- Our Results of Operations -- Impact of
Commodity Hedging Activities on Our Results of Operations."

Investing Cash Flows

During the first six months of 2002, we used $431.7 million in cash to
finance investing activities compared to $397.5 million spent during the first
six months of 2001. The 2001 period includes $113 million paid to acquire equity
interests in several Gulf of Mexico natural gas pipelines from El Paso (our
Stingray, Manta Ray, Nautilus and Nemo equity investments) and $244 million paid
to acquire Shell's Acadian Gas natural gas pipeline system. The 2002 period
reflects $394.8 million in business acquisitions including $368.7 million paid
to acquire affiliates of Diamond-Koch's propylene fractionation and NGL and
petrochemical storage businesses and $18.0 million paid to Shell representing
the final purchase price adjustment relating to the Acadian Gas acquisition.

S-32

Financing Cash Flows

Our financing activities generated $257.3 million in cash inflows during
the first six months of 2002 compared to $362.4 million during the first six
months of 2001. The 2002 period includes $368.0 million in net borrowings under
our revolving credit facilities while the 2001 period reflects $449.7 million in
proceeds from the issuance of the Senior Notes B, in each case, partially offset
by cash distributions to our partners. Cash distributions paid to our partners
increased period-to-period primarily due to increases in both the declared
quarterly distribution rate and the number of units entitled to receive
distributions.

The conversion of 19,000,000 of Shell's non-distribution-bearing special
units to distribution-bearing common units on August 1, 2002 will increase
distributions paid to partners beginning with the third quarter of 2002
distribution expected to be paid in November 2002.

CONSOLIDATED CASH FLOWS FOR YEAR ENDED DECEMBER 31, 2001 COMPARED TO YEAR
ENDED DECEMBER 31, 2000

Operating Cash Flows

Cash flows from operating activities were $283.3 million in 2001 versus
$360.9 million in 2000. After adjusting for changes in operating accounts,
adjusted cash flow from operating activities would be $320.4 million in 2001 as
compared to $289.8 million in 2000. It provides an indication of our success in
generating core cash flows from the assets and investments that we own. The
$30.7 million increase for 2001 is attributable to our strong earnings as
discussed earlier under "Our Results of Operations -- Year Ended December 31,
2001 Compared to Year Ended December 31, 2000."

Investing Cash Flows

During 2001, we used $491.2 million of cash to finance investing activities
compared to $268.8 million in 2000. Capital expenditures were $149.9 million
during 2001 compared to $243.9 million during 2000. Over the last two years, we
have funded $384.3 million in internal growth projects. Of the cumulative $393.8
million spent during 2001 and 2000, $336.2 million is attributable to various
pipeline projects, including $99.5 million spent to purchase the Lou-Tex
Propylene pipeline (2000), $90.5 million to construct the Lou-Tex NGL pipeline
($83.7 million spent in 2000 with the remainder spent in 2001) and $64.1 million
in expansion activities related to our Louisiana Pipeline System (2001). We
spent $9.5 million on sustaining capital expenditures during the last two years
with $6.0 million in such charges recorded during 2001.

Our investing cash outflows for 2001 include $226 million paid to acquire
Acadian Gas from Shell. This amount was subject to certain post-closing
adjustments that were completed during the first half of 2002. In addition, our
investments in and advances to unconsolidated affiliates increased $84.7 million
in 2001 due to the $112.0 million paid to purchase equity interests in several
Gulf of Mexico natural gas pipeline systems from El Paso.

Financing Cash Flows

Our financing activities generated $279.5 million of cash receipts during
2001 compared to cash payments of $36.9 million in 2000. Cash flows from
financing activities are primarily affected by repayments of debt, borrowings
under debt agreements and distributions to partners. Cash flow from financing
activities in 2001 includes proceeds from the $450 million Senior Notes B issued
in January 2001 whereas the 2000 period includes proceeds from the $350 million
Senior Notes A and $54 million MBFC Loan and the associated repayments on
various bank credit facilities.

Cash distributions to partners and the minority interest increased to
$166.0 million in 2001 from $141.0 million in 2000 primarily due to (i)
increases in the quarterly distribution rate and (ii) the conversion of 5.0
million of Shell's special units into common units. Our cash distribution policy
has allowed us to retain a significant amount of cash flow for reinvestment in
the growth of the business. Over the last two years, we have retained
approximately $275.0 million to fund expansions and business acquisitions. We

S-33

believe that our cash distribution policy provides the partnership with
financial flexibility in executing its growth strategy.

At December 31, 2001, we had $5.8 million in restricted cash required by
the NYMEX commodity exchange to facilitate financial instrument and physical
purchase transactions. This amount can fluctuate over time depending on the
physical volumes underlying the contracts, market price of the commodity and
type of transactions executed. During 2001, our restricted cash balance required
by the exchange varied, reaching a peak of $13.4 million in July.

CONSOLIDATED CASH FLOWS FOR YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR
ENDED DECEMBER 31, 1999

Operating Cash Flows

Cash flows from operating activities were $360.9 million in 2000 compared
to $177.9 million in 1999. After adjusting for changes in operating accounts,
adjusted cash flow from operating activities increased $139.8 million to $289.8
million in 2000 compared to $150.0 million in 1999. The $139.8 million increase
in adjusted cash flow from operating activities between periods is primarily due
to the impact of the TNGL acquisition.

Investing Cash Flows

We invested $268.8 million during 2000 (primarily in internal growth
projects) compared to $271.2 million spent during 1999 (primarily for
acquisitions). Fiscal 1999 reflects $208.1 million in net cash payments
resulting from the TNGL and MBA acquisitions. Our capital expenditures increased
substantially in 2000 over 1999 primarily due to the purchase of the Lou-Tex
Propylene pipeline ($99.5 million) and construction costs related to the Lou-Tex
NGL pipeline ($83.7 million).

Investments in and advances to unconsolidated affiliates during 1999
include our share of costs ($38.2 million) to complete construction and commence
operations of the BRF facility and Wilprise and Tri-States pipelines. Our 2000
expenditures include $19.4 million paid to purchase an additional 8.4% interest
in the Dixie pipeline. The 1999 and 2000 amounts also include a combined $26.2
million in costs to construct the BRPC facility, which was completed in July
2000.

Financing Cash Flows

Our financing activities resulted in net cash payments of $36.9 million in
2000 versus net cash receipts of $74.4 million in 1999. Fiscal 2000 includes
proceeds from the issuance of Senior Notes A and the MBFC Loan and the
associated repayments on various bank credit facilities. Financing activities in
1999 include the borrowings under bank credit facilities to finance the TNGL and
MBA acquisitions. Distributions to partners and the minority interest increased
to $141.0 million in 2000 compared to $112.9 million in 1999 primarily due to
increases in the quarterly distribution rate. Lastly, we repurchased and retired
28,400 common units during 2000 under our buy-back program at a cost of $0.8
million.

CASH REQUIREMENTS FOR FUTURE GROWTH

Future Acquisitions

We are committed to the long-term growth and viability of our partnership.
Our strategy involves expansion through business acquisitions and internal
growth projects. In recent years, major oil and gas companies have sold
non-strategic assets in the midstream natural gas industry in which we operate.
We forecast that this trend will continue, and expect independent oil and
natural gas companies to consider similar disposal options. Our management
continues to analyze potential acquisitions, joint ventures or similar
transactions with businesses that operate in complementary markets and
geographic regions. We believe that our partnership is positioned to continue to
grow through acquisitions that will expand its platform of assets and through
internal growth projects.

S-34

So far in fiscal 2002, we have invested $1.6 billion in business
acquisitions and internal growth projects, including $1.2 billion for the
interests in Mid-America and Seminole we purchased from Williams in July 2002,
$239.0 million for the Mont Belvieu propylene fractionation assets we purchased
from Diamond-Koch in February 2002 and $129.6 million for the Mont Belvieu NGL
and petrochemical storage assets we purchased from Diamond-Koch in January 2002.
Of the $1.6 billion in business acquisitions and internal growth projects we
have completed thus far in 2002, we have borrowed approximately $1.5 billion of
the funds required. This will translate into additional debt service costs
during 2002.

The $1.2 billion we borrowed to effect the Mid-America and Seminole
acquisitions was in the form of a senior unsecured 364-day term loan. The loan
will mature as follows: $150 million due on December 31, 2002, $450 million on
March 31, 2003 and $600 million on July 30, 2003. Our plans for permanent
financing of these acquisitions include the issuance of equity and debt in
amounts that are consistent with our objective of maintaining our financial
flexibility and investment grade balance sheet. We will use the net proceeds
from this offering to retire a portion of the indebtedness outstanding under our
$1.2 billion senior unsecured 364-day term loan. Please read "Use of Proceeds."

Future Distributions

Our management's goal is to increase the distribution rate to our investors
by at least 10% annually. For the fourth quarter of 2001, the declared annual
rate was $1.25 per common unit (on a post-split basis). In the first quarter of
2002, the declared annual rate was raised to $1.34 per common unit. On September
12, 2002, we announced that the board of directors of our general partner
approved an increase in our quarterly distribution rate to our partners from
$0.335 per unit to $0.345 per unit, or $1.38 on an annualized basis. Based on
the number of distribution-bearing units projected to be outstanding at the end
of 2002 (not including the effect of any potential equity offerings), we project
that this increase would translate into cash distributions to partners
increasing by approximately $48 million over the amounts paid during 2001. The
number of distribution-bearing units projected to be outstanding at the end of
2002 includes the August 2002 conversion of 19.0 million
non-distribution-bearing special units owned by Shell into an equal amount of
distribution-bearing common units.

Our distribution rate is supported by prospective and historical cumulative
cash flow since our initial public offering in July 1998. From our initial
public offering through August 2002, we generated $849.6 million in cash that
was available for distribution to unitholders, of which $573.3 million was paid
to unitholders (including the second quarter of 2002 distribution paid on August
12, 2002). Our policy has been to retain and invest the difference of $276.3
million (the "excess cash flow") in capital projects that we anticipate will be
accretive in terms of cash flow to our unitholders over time. This policy has
helped us to maintain a strong financial presence in the markets we serve by
minimizing debt and using the excess cash flow to expand the partnership through
internal growth and acquisitions.

We believe that all cash distributions will be paid out of operating cash
flows over the long-term; however, from time to time, we may temporarily borrow
under our bank credit facilities for the purpose of paying distributions until
the full cash flow impact of our operations is realized.

Capital Spending

At June 30, 2002, we had $6.8 million in outstanding purchase commitments
attributable to capital projects. Of this amount, $5.1 million is related to the
construction of assets that will be recorded as property, plant and equipment
and $1.7 million is associated with capital projects of our unconsolidated
affiliates which will be recorded as additional investments.

During the first six months of 2002, our capital expenditures were $26.8
million, excluding acquisitions. For the remainder of 2002, we expect our
capital spending to approximate $8.1 million of which $5.7 million is forecasted
for our Pipelines segment. Our unconsolidated affiliates forecast a combined
$13.9 million in capital expenditures during the remainder of 2002 of which we
expect our share to be approximately $4.8 million, the majority of which relate
to expansion projects on our Gulf of Mexico natural gas pipeline systems. These
outlays will be recorded as additional investments in unconsolidated affiliates.

S-35

New environmental regulations in the state of Texas may necessitate
extensive redesign and modification of our Mont Belvieu facilities to achieve
the air emissions reductions needed for federal Clean Air Act compliance in the
Houston-Galveston, Texas area. The technical practicality and economic
reasonableness of these regulations have been challenged under state law in
litigation filed on January 19, 2001, against the Texas Commission on
Environmental Quality (formerly named the Texas Natural Resource Conservation
Commission) and its principal officials in the District Court of Travis County,
Texas, by a coalition of major Houston-Galveston area industries, including our
company. In June 2002, the TCEQ proposed a rule that would mitigate certain
aspects of these requirements. This rule is scheduled to be finalized in
December 2002. Until this rulemaking is finalized and the associated litigation
is resolved, the precise level of technology to be employed and the cost for
modifying the facilities to achieve the required amount of reductions cannot be
determined. Regardless of the outcome of the pending rulemaking and the
associated litigation, expenditures for air emissions reduction projects will be
spread over several years, and we believe that adequate liquidity and capital
resources will exist for us to undertake them. We have budgeted capital funds in
2002 to begin making modifications to certain Mont Belvieu facilities that will
result in air emission reductions. The methods employed to achieve these
reductions will be compatible with whatever regulatory requirements are
eventually put in place.

OUR DEBT OBLIGATIONS

For a detailed discussion of our debt obligations, please read Item 7
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Our Liquidity and Capital Resources" in our Annual Report on Form
10-K for the year ended December 31, 2001 and Item 2 "Management's Discussion
and Analysis of Financial Condition and Results of Operations -- Our Liquidity
and Capital Resources" in our Quarterly Report on Form 10-Q for the quarter
ended June 30, 2002.

Debt Associated With Mid-America and Seminole Acquisitions. We entered
into a $1.2 billion senior unsecured 364-day term loan to fund the acquisition
of the Mid-America and Seminole pipeline systems from Williams on July 31, 2002.
The lenders under this facility are Wachovia Bank, National Association, Lehman
Brothers Bank, FSB, Lehman Commercial Paper Inc. and Royal Bank of Canada. The
term loan currently bears interest at 3.2% and will generally bear interest at
either:

- the greater of (a) the Prime Rate or (b) the Federal Funds Effective Rate
plus one-half percent; or

- a Eurodollar rate, with any rate in effect being increased by an
appropriate applicable margin.

The $1.2 billion senior unsecured 364-day term loan contains various
affirmative and negative covenants applicable to our operating partnership
similar to those required under our Multi-Year and 364-Day Credit Facility
agreements. The term loan is guaranteed by us through an unsecured guarantee.
The term loan matures as follows: $150 million on December 31, 2002, $450
million on March 31, 2003 and $600 million on July 30, 2003.

On August 1, 2002, Seminole had $60 million in senior unsecured notes due
in December 2005. The principal amount of these notes amortize by $15 million
each December 1 through 2005. In accordance with generally accepted accounting
principles, this debt will be consolidated on our balance sheet because of our
78% indirect ownership interest in the Seminole pipeline system.

OUR ACCOUNTING POLICIES

For a discussion of our accounting policies, the impact of recent
accounting developments and uncertainties in our investment in BEF, see Item 2
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" in our Quarterly Report on Form 10-Q for the period ended June 30,
2002 and Item 7 "Management's Discussion and Analysis of Financial Condition and
Results of Operations" in our Annual Report on Form 10-K for the year ended
December 31, 2001.

S-36

RELATED PARTY TRANSACTIONS

For a more detailed discussion of our related party transactions, please
read Item 2 "Management's Discussion and Analysis of Financial Condition and
Results of Operations" in our Quarterly Report on Form 10-Q for the period ended
June 30, 2002 and Item 7 "Management's Discussion and Analysis of Financial
Condition and Results of Operations" in our Annual Report on Form 10-K for the
year ended December 31, 2001.

RELATIONSHIP WITH EPCO AND ITS AFFILIATES

We have an extensive and ongoing relationship with EPCO, which owns 65% of
our general partner. EPCO is majority-owned and controlled by Dan L. Duncan,
Chairman of the Board and a Director of our general partner. In addition, three
other members of the board of directors (O.S. Andras, Randa D. Williams and
Richard H. Bachmann) and the remaining executives and other officers of our
general partner are employees of EPCO. The principal business activity of our
general partner is to act as our managing partner. EPCO performs our management,
administrative and operating functions pursuant to the terms of the EPCO
agreement (in effect since July 1998). For additional information regarding the
EPCO agreement and other related party transactions with EPCO or its affiliates,
please refer to Item 13 of our Annual Report on Form 10-K for the fiscal year
ended December 31, 2001.

Mr. Duncan owns 50.4% of the voting stock of EPCO and, accordingly,
exercises sole voting and dispositive power with respect to the common and
subordinated units held by EPCO. The remaining shares of EPCO capital stock are
held primarily by trusts for the benefit of the members of Mr. Duncan's family,
including Randa D. Williams, a director of our general partner. In addition,
EPCO and Dan Duncan, LLC collectively own 70% of our general partner which in
turn owns a combined 2% interest in our company.

In addition, trust affiliates of EPCO (Enterprise Products 1998 Unit Option
Plan Trust and the Enterprise Products 2000 Rabbi Trust) purchase common units
for the purpose of granting options to certain directors of our general partner,
EPCO management and certain key employees. During 2001, these trusts purchased
423,036 common units on the open market or through privately negotiated
transactions. At December 31, 2001, these trusts owned a total of 2,923,036
common units. In November 2001, EPCO directly purchased 1,000,000 common units
at market prices for $22.6 million on behalf of a key executive and director of
our general partner.

Our agreements with EPCO are not the result of arm's-length transactions,
and there can be no assurance that any of the transactions provided for therein
are effected on terms at least as favorable to the parties to such agreement as
could have been obtained from unaffiliated third parties.

As a result of our company satisfying certain financial tests, 10,704,936
(or 25%) of EPCO's subordinated units converted to common units on May 1, 2002.
Should the financial criteria continue to be satisfied through the first quarter
of 2003, an additional 25% of the subordinated units would convert to common
units on May 1, 2003. The remaining 50% of subordinated units would convert on
August 1, 2003 should the balance of the conversion requirements be met.
Subordinated units have no voting rights until converted to common units. The
conversion(s) will have no impact upon our earnings per unit since the
subordinated units are already included in both the basic and diluted
calculations.

RELATIONSHIP WITH SHELL

We have an extensive relationship with Shell. Following this offering,
Shell will own approximately 21.8% of our limited partner units and 30.0% of our
general partner. Currently, three members of the board of directors of our
general partner (J.R. Eagan, J.A. Berget and Augustus Y. Noojin, III) are
employees of Shell.

Shell is a significant customer of our Processing segment. We have the
option to process Shell's current and future natural gas production from the
Gulf of Mexico under a 20-year contract. Apart from operating expenses arising
from the Shell Processing Agreement, we also sell NGL and petrochemical products
to Shell. During 2001, Shell generated $333.3 million, or 10.5%, of our
revenues.

S-37

Shell owns a 45.4% equity interest in one of our propylene fractionators at
our Mont Belvieu complex. We lease Shell's interest in this facility under a
long-term agreement. We have a long-term contract to provide Shell with
propylene from this facility. We have supplied Shell with propylene since our
first propylene fractionator was constructed in 1979.

In April 2000, we acquired the Lou-Tex propylene pipeline system and an
underground storage facility from Shell for $100 million in a negotiated
transaction that was approved by the Board of Directors of our general partner,
with the three Shell representatives abstaining. As part of the transaction, we
entered into a 20-year agreement to deliver propylene from Louisiana to Shell's
facilities on the Texas Gulf Coast.

In January 2001, we acquired ownership interests in the Nautilus, Manta
Ray, Nemo, Stingray and Triton natural gas pipeline systems in the Gulf of
Mexico from affiliates of El Paso. Shell owns equity interests of 50%, 50%, 66%,
50% and 50%, respectively, in these pipeline systems. Shell has responsibilities
for the commercial and physical management of these pipeline systems.

In April 2001, we acquired Acadian Gas from Shell for approximately $244
million in a negotiated transaction (through a bidding process) that was
approved by the board of directors of our general partner, with the three Shell
representatives abstaining.

In accordance with existing agreements with Shell, 19 million of Shell's
non-distribution bearing special units converted to distribution bearing common
units on a one-for-one basis on August 1, 2002. These special units were issued
to Shell over a period of time as assets acquired from Shell in the TNGL
acquisition in 1999 achieved performance targets established at the time of the
acquisition. The remaining 10 million special units will convert to common units
on a one-for-one basis in August 2003. These conversions have a dilutive impact
on basic earnings per unit.

MID-AMERICA AND SEMINOLE RESULTS OF OPERATIONS

The following discussion relates to the results of operations of the
Mid-America and Seminole pipeline systems, which we acquired from Williams in
July 2002. For additional information relating to the financial condition and
results of operations of Mid-America and Seminole, please read the Mid-America
Pipeline System Financial Statements and the related notes beginning on page
F-77 and the Seminole Pipeline Company Financial Statements and related notes
beginning on page F-87.

MID-AMERICA PIPELINE SYSTEM

Mid-America's primary business focus is to provide NGL transportation
services to customers (or shippers) on a fee (or tariff) basis. As such,
Mid-America's results of operations are generally dependent upon the volume of
NGLs transported and the level of fees charged to shippers. Mid-America is an
interstate common carrier pipeline subject to regulation by the FERC and some
state and local governmental agencies. As an interstate common carrier,
Mid-America provides service to any shipper who requests transportation
services, provided that products tendered for transportation satisfy the
conditions and specifications contained in the applicable tariff. Mid-America is
required to maintain tariffs on file with the FERC that set forth the rates it
can charge for providing transportation services as well as the rules and
regulations governing these services. Mid-America's intrastate transportation
services are generally under the regulation of the state in which the NGL
movement occurs.

The volume of NGLs available for transportation on the Mid-America pipeline
system is driven by natural gas and related NGL production from the natural gas
supply basins it serves. Mid-America has connections extending into several
natural gas supply basins throughout North America, including the Rocky Mountain
Overthrust, the San Juan and Permian basin, the Mid-Continent region and,
through third-party pipeline connections, north into Canada's Western
Sedimentary basin. The volume of NGLs available for transportation on the
Mid-America pipeline system can be affected by NGL extraction rates at natural
gas processing facilities, which in turn are affected by the relationship
between the market prices of natural gas and NGLs. During periods in which the
relative economic value of the mixed NGLs extracted by gas processing plants is
less than the costs associated with these activities, gas processors will reduce
the volume

S-38

of NGLs they produce, which will subsequently reduce the quantity of NGLs
available for transportation on Mid-America. Approximately 20 natural gas
processing plants in Wyoming, Utah and Colorado feed NGLs into Mid-America for
delivery to several destinations. In addition, Mid-America's volumes are
generally affected by seasonal changes in propane demand. Overall, NGL
transportation volumes tend to be higher in the October through March timeframe
due to the increased use of propane for heating. During 2001, approximately 63%
of Mid-America's revenues were derived from five major companies in the NGL
industry: BP, Burlington, Duke, Equistar and Williams.

The following table reflects Mid-America's revenues, costs and expenses,
operating income and gross operating margin for each of the three years ended
December 31, 2001 and the six month periods ended June 30, 2001 and 2002. The
table also includes average NGL transportation volumes for each of the periods
indicated.

SIX MONTHS
FOR THE YEAR ENDED DECEMBER 31, ENDED JUNE 30,
--------------------------------- -------------------
1999 2000 2001 2001 2002
--------- --------- --------- -------- --------
(DOLLARS IN THOUSANDS) (UNAUDITED)

Revenues................................ $190,686 $209,895 $214,518 $102,244 $109,865
Costs and expenses...................... 116,341 134,898 153,713 81,677 60,241
Operating income........................ 74,345 74,997 60,805 20,567 49,624
Gross operating margin.................. 122,083 129,304 114,170 46,766 77,045
NGL transportation volumes (MBPD)....... 634 637 641 617 631

Immediately prior to our acquisition, Mid-America extinguished all of its debt,
thereby eliminating interest expense associated with these amounts on a
going-forward basis.

SIX MONTHS ENDED JUNE 30, 2002 COMPARED TO SIX MONTHS ENDED JUNE 30, 2001

Revenues increased to $109.9 million in 2002 from $102.2 million in 2001
primarily due to an increase in transportation volumes from 617 MBPD in 2001 to
631 MBPD in 2002. Transportation volumes during the first six months of 2001
reflected decreased NGL extraction rates at gas processing facilities served by
Mid-America. The decrease in NGL extraction rates was primarily due to
abnormally high natural gas prices relative to the price of NGLs during the
period.

Mid-America's costs and expenses decreased by $21.4 million for the first
six months of 2002 as compared to the first six months of 2001, primarily due to
the following:

- The value of Mid-America's working inventory was written down by $12.9
million during the first six months of 2001 due to a decrease in NGL and
petrochemical prices during the period relative to its average historical
carrying values of these products.

- Mid-America's fuel and power costs for the first six months of 2002 were
$5.8 million lower than those recorded during the first six months of
2001. The lower expense is primarily due to a decrease in the price of
natural gas (which is a significant component of energy-related costs)
between the two periods.

Operating income increased $29.1 million for the first six months of 2002 as
compared to the first six months of 2001 primarily as a result of the items
discussed above. Gross operating margin increased $30.2 million to $77.0 million
in 2002 from $46.8 million in 2001 for similar reasons.

YEAR ENDED DECEMBER 31, 2001 COMPARED TO YEAR ENDED DECEMBER 31, 2000

Revenues increased to $214.5 million in 2001 from $209.9 million in 2000
primarily due to an increase in transportation volumes from 637 MBPD in 2000 to
641 MBPD in 2001. Transportation volumes in 2001 increased relative to 2000
despite the decrease in NGL extraction rates mentioned earlier. Costs and
expenses increased $18.8 million in 2001 primarily due to a decrease in the
value of Mid-America's working inventory relative to its average historical
carrying value.

S-39

Operating income decreased $14.2 million for the year ended December 31,
2001 as compared to the year ended December 31, 2000 primarily as the result of
the items discussed above. Gross operating margin decreased $15.1 million to
$114.2 million in 2001 from $129.3 million in 2000 for similar reasons.

YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999

Revenues increased to $209.9 million in 2000 from $190.7 million in 1999
primarily due to an increase in transportation volumes from 634 MBPD in 1999 to
637 MBPD in 2000. The increase in transportation volumes is primarily due to
Mid-America's Rocky Mountain pipeline, which was placed in service in late 1999.
Costs and expenses increased $18.6 million for the year ended December 31, 2000
as compared to the year ended December 31, 1999, primarily as the result of the
addition of operating expenses associated with the Rocky Mountain pipeline and
higher overall fuel and power costs.

Operating income increased $0.7 million year-to-year primarily as the
result of the items discussed above. Gross operating margin increased $7.2
million to $129.3 million in 2000 from $122.1 million in 1999 for similar
reasons. The $6.5 million difference between gross operating margin and
operating income is primarily due to the additional depreciation expense
recorded in 2000 associated with the Rocky Mountain pipeline.

LIQUIDITY AND CASH FLOW

Mid-America's primary cash requirements, in addition to normal operating
expenses, are for capital expenditures and cash dividends to its owner.
Historically, Mid-America's revenues have been sufficient to meet its cash
requirements for operating expenses and to fund debt service requirements.
Mid-America's capital expenditures during the three years ended December 31,
2001 were $176.8 million, of which $121.4 million was associated with the Rocky
Mountain pipeline completed in 1999.

SEMINOLE PIPELINE COMPANY

Seminole pipeline system's primary business is providing NGL transportation
services to customers (shippers) on a fee (or tariff) basis. As such, Seminole's
results of operations are generally dependent upon the volume of NGLs
transported and the level of fees charged to customers. Seminole's pipeline
system is an intrastate common carrier pipeline subject to regulation by the
FERC and some state and local governmental agencies. As a common carrier,
Seminole provides service to any shipper who requests transportation services,
provided that such products tendered for transportation satisfy the conditions
and specifications contained in the applicable tariff. Seminole is required to
maintain tariffs on file with the FERC that set forth the rates it can charge
for providing transportation services as well as the rules and regulations
governing these services.

The volume of NGLs available for transportation on Seminole is primarily
dependent on demand for mixed NGLs and NGL products from petrochemical plants in
the Houston, Texas vicinity that manufacture plastics and other petrochemical
products. Volumes transported on the Seminole system originate primarily as
injections from the Mid-America pipeline system (on a joint tarriff basis). As
such, a significant decline in the volumes transported by Mid-America to the
Hobbs hub will have a similar impact on Seminole's transportation volumes and
margins.

NGL transportation volumes on the Seminole pipeline do not exhibit a
significant degree of seasonality. Throughput rates are principally driven by
downstream demand from petrochemical plants which can be affected by general
economic conditions and other matters. From the standpoint of competition,
Seminole does not have any direct competitors for the volumes it transports
since these volumes are primarily dedications from Mid-America. During 2001,
approximately 77% of Seminole's revenues were derived from five major companies
in the NGL industry: BP, Burlington, ConocoPhillips, Duke and Williams.

The following table reflects Seminole's revenues, costs and expenses,
operating income and gross operating margin for each of the three years ended
December 31, 2001 and the six month periods ended

S-40

June 30, 2001 and 2002. The table also includes average NGL transportation
volumes (in MBPD) for each of the periods indicated.

SIX MONTHS
FOR THE YEAR ENDED DECEMBER 31, ENDED JUNE 30,
--------------------------------- -----------------
1999 2000 2001 2001 2002
--------- --------- --------- ------- -------
(DOLLARS IN THOUSANDS) (UNAUDITED)

Revenues..................................... $64,210 $66,609 $65,800 $30,880 $34,856
Costs and expenses........................... 28,313 38,993 35,074 17,180 18,111
Operating income............................. 35,897 27,616 30,726 13,700 16,745
Gross operating margin....................... 47,057 39,499 42,460 19,545 22,664
NGL transportation volumes (in MBPD)......... 245 245 241 230 259

SIX MONTHS ENDED JUNE 30, 2002 COMPARED TO SIX MONTHS ENDED JUNE 30, 2001

Revenues increased to $34.9 million in 2002 from $30.9 million in 2001
primarily due to an increase in transportation volumes from 230 MBPD in 2001 to
259 MBPD in 2002. NGL volumes available for transportation were lower in 2001
due to decreased NGL extraction rates at gas plants during the first quarter of
2001 resulting from abnormally high natural gas prices. Costs and expenses
increased $0.9 million for the year primarily as the result of increased
offloading charges. Operating income and gross operating margin increased $3.0
million and $3.1 million, respectively, in 2002 as compared to 2001, primarily
due to the increased throughput rates.

YEAR ENDED DECEMBER 31, 2001 COMPARED TO YEAR ENDED DECEMBER 31, 2000

Revenues decreased to $65.8 million in 2001 from $66.6 million in 2000
primarily due to a decrease in transportation volumes from 245 MBPD in 2000 to
241 MBPD in 2001. As noted above, 2001 volumes were affected by the decrease in
NGL extraction rates throughout the industry. Costs and expenses decreased to
$35.1 million in 2001 from $39.0 million in 2000 primarily due to decreases in
fuel and power costs of $1.8 million and property taxes of $1.9 million.
Operating income and gross operating margin increased $3.1 million and $3.0
million, respectively, primarily due to the lower operating expenses partially
offset by decreased transportation volumes.

YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999

Revenues increased to $66.6 million in 2000 from $64.2 million in 1999.
Transportation volumes were 245 MBPD for both years. Costs and expenses
increased $10.7 million to $39.0 million in 2000 from $28.3 million in 1999
primarily due to increases in fuel and power costs of $4.6 million and property
taxes of $2.5 million. Operating income and gross operating margin decreased by
$8.3 million and $7.6 million, respectively, primarily due to the higher
operating expenses.

LIQUIDITY AND CASH FLOW

Seminole's primary cash requirements, in addition to normal operating
expenses and debt service, are for capital expenditures and dividends to its
stockholders. Historically, Seminole's revenues have been sufficient to meet its
cash requirements.

In December 1993, Seminole issued $75 million of 6.67% senior unsecured
notes in a private placement. The principal amount of these notes amortizes at a
rate of $15 million annually commencing on December 1, 2001 through 2005.
Interest is paid semi-annually on June 1 and December 1. Seminole was in
compliance with its covenants with respect to the notes at December 31, 2001 and
June 30, 2002.

S-41

BUSINESS

OUR OPERATIONS

We are a leading North American midstream energy company that provides a
wide range of services to producers and consumers of natural gas and NGLs. Our
asset platform in the Gulf Coast region, combined with our recently acquired
Mid-America and Seminole pipeline systems, creates the only integrated North
American natural gas and NGL transportation, fractionation, processing, storage
and import/export network. We provide integrated services to our suppliers and
customers and generate fee-based cash flow from multiple sources along our
natural gas and NGL "value chain." Our services include the:

- gathering and transmission of raw natural gas from both onshore and
offshore Gulf of Mexico developments;

- processing of raw natural gas into a marketable product that meets
industry quality specifications by removing mixed NGLs and impurities;

- purchase of natural gas for delivery to our industrial, utility and
municipal customers;

- transportation of mixed NGLs to fractionation facilities by pipeline;

- fractionation of mixed NGLs produced as by-products of crude oil refining
and natural gas production into component NGL products: ethane, propane,
isobutane, normal butane and natural gasoline;

- transportation of NGL products to end-users by pipeline, railcar and
truck;

- import and export of NGL products and petrochemical products through our
dock facilities;

- fractionation of refinery-sourced propane/propylene mix into high purity
propylene, propane and mixed butane;

- transportation of high purity propylene to end-users by pipeline;

- storage of natural gas, mixed NGLs, NGL products and petrochemical
products;

- conversion of normal butane to isobutane through the process of
isomerization;

- production of high-octane additives for motor gasoline from isobutane;
and

- sale of NGL and petrochemical products we produce and/or purchase for
resale on a merchant basis.

We have five reportable business segments: Pipelines, Fractionation,
Processing, Octane Enhancement and Other. Pipelines consists of our natural gas,
NGL and petrochemical pipeline systems, storage and import/export terminaling
businesses. Fractionation includes our NGL fractionation, isomerization and
propylene fractionation facilities. Processing includes our natural gas
processing business and NGL merchant activities. Octane Enhancement represents
our minority interest in a facility that produces motor gasoline additives to
enhance octane. Other consists primarily of fee-based marketing services.

RECENT SIGNIFICANT ACQUISITIONS

Acquisitions of Mid-America and Seminole Pipeline Systems. On July 31,
2002, we completed the acquisition of the Mid-America and Seminole pipeline
systems from Williams for approximately $1.2 billion in cash. The acquisition
included:

- the purchase of a 98% ownership interest in Mapletree, LLC, which owns
100% of the Mid-America pipeline system and indirectly owns 16 propane
terminals and over 1.5 million barrels of storage capacity; and

- the purchase of a 98% ownership interest in E-Oaktree, LLC, which owns an
80% equity interest in the Seminole pipeline system.

S-42

Mid-America is a 7,226-mile NGL pipeline system connecting the Hobbs hub
located on the Texas-New Mexico border with supply regions in the Rocky
Mountains and with supply regions and markets in the Midwest. The Mid-America
pipeline system is comprised of three major segments: the Conway North pipeline,
the Conway South pipeline and the Rocky Mountain pipeline. In 2001, average
transportation volumes on the Mid-America pipeline system were approximately 641
MBPD. Seminole is a 1,281-mile pipeline system that interconnects with the
Mid-America pipeline system and transports mixed NGLs and NGL products from the
Hobbs hub and the Permian basin to Mont Belvieu, Texas. In 2001, average
transportation volumes on the Seminole pipeline system were approximately 241
MBPD, of which approximately 32% of Seminole's volumes in 2001 were transported
to our Mont Belvieu facilities for fractionation, storage and distribution.
Major customers utilizing the Mid-America and Seminole pipeline systems include
BP, Burlington, ConocoPhillips, Duke, Equistar and Williams.

The acquisition of the Mid-America and Seminole pipeline systems
significantly enhances our existing asset base by:

- accessing NGL-rich natural gas production in major North American natural
gas producing regions;

- expanding our integrated natural gas and NGL network;

- providing access to new end markets for NGL products; and

- increasing our gross margins from fee-based businesses.

In addition to our current strategic position in the Gulf of Mexico, we now have
access to major supply basins throughout North America, including the Rocky
Mountain Overthrust, the San Juan and Permian basins, the Mid-Continent region
and, through third-party pipeline connections, north into Canada's Western
Sedimentary basin. In addition to access to supply, the combination of these
assets with our existing assets creates a significant link between Mont Belvieu,
Texas and Conway, Kansas, the two largest NGL hubs in the United States, and
provides additional access to new end markets for NGL products. The Conway South
segment of the Mid-America pipeline system connects the Conway hub with
refineries in Kansas and transports mixed NGLs from Conway to Hobbs and from
Hobbs to Mont Belvieu. The 2,740-mile Conway North pipeline links the market hub
in Conway with petrochemical and refining customers and propane markets in the
upper Midwest.

Acquisition of Propylene Fractionation Business. In February 2002, we
completed the purchase of various propylene fractionation assets and certain
inventories of propylene and propane from Diamond-Koch for approximately $239
million in cash. The acquisition includes a 66.7% interest in a polymer grade
propylene fractionation facility located in Mont Belvieu, Texas, a 50% interest
in a polymer grade propylene export terminal located in the Houston Ship Channel
and varying interests in several supporting distribution pipelines and related
equipment. This Mont Belvieu facility has the capacity to produce approximately
41 MBPD of polymer grade propylene.

Acquisition of Storage Business. In January 2002, we completed the
purchase of various NGL and petrochemical storage assets from Diamond-Koch for
approximately $130 million in cash. These storage facilities consist of 30 salt
dome storage caverns located in Mont Belvieu, Texas with a useable capacity of
68 million barrels, local distribution pipelines and related equipment. The
facilities provide storage services for mixed NGL products and olefins, such as
ethylene and propylene. The facilities, together with our existing storage
facilities, serve the largest concentration of petrochemical and refinery
facilities in the United States, and represent the largest NGL and petrochemical
underground storage operation in the world.

S-43

OUR BUSINESS STRATEGY

Our business strategy is to:

- develop and invest in joint venture projects with strategic partners that
provide the raw materials for these projects or purchase the projects'
end products;

- continue to expand our asset base through accretive acquisitions of
complementary midstream energy assets; and

- increase our fee-based cash flows by investing in pipelines and other
fee-based businesses.

COMPETITIVE STRENGTHS

- The acquisition of the Mid-America and Seminole pipeline systems
significantly expands our access to NGL supply regions and markets. Our
pipeline systems serve the two fastest growing natural gas and NGL
production areas in the United States, the deepwater Gulf of Mexico and
the Rocky Mountain Overthrust, as well as the San Juan and Permian
basins, the Mid-Continent region and, through third-party pipeline
connections, north into Canada's Western Sedimentary basin.

- We have significant operations on the Gulf Coast of the United States,
which accounts for approximately 55% of domestic NGL production and 79%
of domestic NGL demand. Our asset position at Mont Belvieu on the Texas
Gulf Coast is the most significant NGL marketplace in the world because
of the large salt dome storage capacity at Mont Belvieu, its access to
supplies of raw materials and end-product markets through domestic
pipeline systems and import/export facilities on the Houston Ship
Channel.

- Our system is connected to 97% of the domestic petrochemical steam
cracking market, which is the largest consumer of NGL products.

Integrated platform of assets. Our assets are physically linked to create
the only integrated natural gas and NGL transportation, fractionation,
processing, storage and import/export network in North America, which connects
the largest supply basins to the largest consumer markets, both domestic and
international.

- Our asset platform allows us to be a single-source provider of a
comprehensive package of essential midstream energy services to producers
and consumers of natural gas, NGLs and petrochemicals.

- Our asset platform provides customers with valuable alternatives, such as
connections to multiple sources of supply and markets.

- Our asset platform has multiple entry points. Hydrocarbons can enter our
integrated system through offshore natural gas pipelines, natural gas
processing plants, mixed NGL gathering or transportation pipelines, NGL
fractionators, NGL storage facilities, NGL product transportation or
distribution pipelines or onshore natural gas pipelines. At each link
along this value chain, we either earn a fee based on volume or receive
mixed NGLs or NGL products.

S-44

Relationships with major oil, natural gas and petrochemical companies. We
have long-term relationships with many of our suppliers and customers. We
jointly own facilities with many of our customers who either provide raw
materials to or consume the end products produced from our facilities.

- In connection with our acquisition of Shell Oil Company's midstream
energy business in September 1999, we entered into a 20-year agreement
with Shell that gives us the option to process all of Shell's current and
future natural gas production from the Gulf of Mexico under a life of
lease dedication.

- Our partners in our NGL fractionator in Baton Rouge, Louisiana are Exxon
Mobil, BP and Williams, who collectively supplied 100% of the NGLs
fractionated at this facility in 2001.

- Our partner in our propylene fractionator in Baton Rouge, Louisiana is
Exxon Mobil, who provides 100% of the raw material and takes 100% of the
fractionated propylene at this facility.

- Our partners in our Promix NGL fractionator in Napoleonville, Louisiana
are Dow Chemical and Koch Industries, who collectively purchased 50% of
the NGL and petrochemical products produced at this facility during 2001.

- Our partners in our NGL fractionator in Mont Belvieu, Texas are
Burlington Resources and Duke Energy, who collectively supplied 49% of
the NGLs volumes fractionated at this facility in 2001.

- Our partners in our offshore natural gas gathering pipelines are Shell
and Marathon, who have dedicated over 110 blocks, or 1,000 square miles,
to the Manta Ray, Nautilus and Nemo pipeline systems.

- Our other major joint venture partners are ChevronTexaco, Sunoco, El Paso
and Devon Energy.

- We also have long-term relationships with major consumers of NGL products
such as Lyondell and Huntsman.

Large-scale, low-cost integrated operations. We believe the operating
costs of our large-scale facilities are either competitive with or significantly
lower than those of our competitors.

- Our facilities benefit from economies of scale, which provide cost per
unit advantages over competitors with smaller facilities.

- Our largest facilities in Mont Belvieu, Texas and Baton Rouge, Louisiana
have been engineered to incorporate efficient gas turbines, a proprietary
heat pump design and cogeneration technology to reduce energy costs,
which are the largest component of operating costs in fractionating NGLs.

- Our infrastructure provides us with a platform for cost-effective
expansion through development projects or acquisitions.

Experienced operator. We have historically operated our largest natural
gas processing and fractionation facilities and most of our pipelines.

- As the leading provider of NGL-related services, we have established a
reputation in the industry as a reliable and cost-effective operator.

- By virtue of our successful and award-winning operating and safety
record, we believe we are well positioned to continue to operate as a
large-scale processor of natural gas, NGLs and other products for our
customers.

S-45

PIPELINES

Our Pipelines segment owns or has interests in approximately 14,000 miles
of NGL, petrochemical and natural gas transportation and distribution pipelines.
This segment also includes our storage and import/export terminalling
businesses.

NATURAL GAS PIPELINES

We entered the natural gas pipeline business in 2001, when we invested $338
million in this business, including $226 million paid to Shell for the purchase
of Acadian Gas (an onshore Louisiana system) and a combined $112 million paid to
El Paso for equity interests in four Gulf of Mexico natural gas pipelines
(primarily Gulf of Mexico offshore Louisiana systems). We believe that these
assets have attractive growth attributes given the expected long-term increase
in natural gas demand for industrial and power generation uses. In addition,
these assets expanded our midstream energy service relationship with long-term
NGL customers (producers, petrochemical suppliers and refineries) and provide us
with opportunities to generate additional fee-based cash flows.

Our natural gas pipeline systems provide for the gathering, transmission
and storage of natural gas from both onshore and offshore Louisiana
developments. Typically, these systems receive natural gas from producers, other
pipelines or shippers through system interconnects and redeliver the natural gas
at other points throughout the system. Generally, natural gas pipeline
transportation agreements generate revenue for these systems based on a
transportation fee per unit of volume (generally in MMBtus) transported. Natural
gas pipelines (such as our Acadian Gas system) may also gather and purchase
natural gas from producers and suppliers and resell such natural gas to
customers such as electric utility companies, local natural gas distribution
companies and industrial customers. Our Acadian Gas operation is exposed to
commodity price risk to the extent it takes title to natural gas volumes through
certain of its contracts. Our Gulf of Mexico systems generally do not take title
to the natural gas that they transport; rather the shipper retains title and the
associated commodity price risk.

Within their market area, our onshore systems compete with other natural
gas pipeline companies on the basis of price (in terms of transportation rates
and/or natural gas selling prices), service and flexibility. Our competitive
position within the onshore market is positively affected by our longstanding
relationships with customers and the limited number of delivery pipelines
connected (or capable of being connected) to the customers we serve. We are
exposed to concentrations of customers in certain market segments (such as the
chemical and refining industry in south Louisiana) in which the business cycle
could affect their creditworthiness and ability to continue business with us.
Our Gulf of Mexico offshore pipeline systems compete primarily on the basis of
transportation rates and service. These pipelines are strategically situated to
gather a substantial volume of the natural gas production in the offshore
Louisiana area from both continental shelf and deepwater developments.

Our onshore and offshore systems are affected by natural gas exploration
and production activities. If these exploration and production activities
decline as a result of a weakened domestic economy or due to natural depletion
of the oil and gas fields they are connected to, then throughput volumes on
these pipelines will decline, thereby affecting our earnings from these
investments. We actively seek to offset the loss of volumes due to natural
depletion by adding connections to new customers and fields.

In light of the complex, interconnected nature of the pipeline networks and
the varying diameter of pipe used and pressure employed, the utilization of
these assets is measured in MMBtu/d of natural gas transported.

S-46

The following table summarizes our natural gas pipeline assets and
ownership interests:

LENGTH OUR
IN OWNERSHIP
NATURAL GAS PIPELINES MILES INTEREST
--------------------- ------ ---------

Cypress..................................................... 577 100.0%
Acadian Gas................................................. 438 100.0%
Stingray.................................................... 379 50.0%
VESCO(1).................................................... 260 13.1%
Manta Ray................................................... 235 25.7%
Nautilus.................................................... 101 25.7%
Evangeline.................................................. 27 49.5%
Nemo........................................................ 24 33.9%
-----
Total.................................................. 2,041
=====

---------------
(1) The VESCO gas gathering pipelines are an integral part of the natural gas
processing activities of VESCO, the assets of which are accounted for as
part of our Processing segment.

Acadian Gas, Cypress and Evangeline. In April 2001, we acquired Acadian
Gas from Shell for $244 million. Acadian Gas is involved in the purchase, sale,
transportation and storage of natural gas in Louisiana. Its assets are comprised
of the 438-mile Acadian and 577-mile Cypress natural gas pipelines and a leased
natural gas storage facility. Acadian Gas owns a 49.5% equity interest in
Evangeline, which owns a 27-mile natural gas pipeline. We operate the Acadian
Gas and Evangeline systems. Overall, the Acadian Gas, Cypress and Evangeline
systems are comprised of 1,042 miles of pipeline. During 2001, these systems had
an average throughput of 783,485 MMBtu/d of natural gas during the period in
which we owned or had an interest in these assets, on a net basis.

Stingray. In January 2001, we purchased a 50.0% interest in the Stingray
natural gas pipeline system and a related natural gas dehydration facility from
El Paso. We own our interest in these assets through our 50.0% equity investment
in Starfish, a joint venture with Shell. The Stingray system is a 379-mile,
FERC-regulated natural gas pipeline system that transports natural gas and
condensate from certain production areas located in the Gulf of Mexico offshore
Louisiana to onshore transmission systems located in south Louisiana. The
natural gas dehydration facility is connected to the onshore terminus of the
Stingray system in south Louisiana. During 2001, this system transported 300,000
MMBtu/d of natural gas, on a net basis. Shell is the operator of these systems
and owns the remaining equity interest in Starfish.

Manta Ray, Nautilus and Nemo. In conjunction with our purchase of the
Stingray interest, we also acquired from El Paso a 25.7% interest in the Manta
Ray and Nautilus natural gas pipeline systems located in the Gulf of Mexico
offshore Louisiana. The Manta Ray system comprises approximately 235 miles of
unregulated pipelines and related equipment and the Nautilus system comprises
approximately 101 miles of FERC-regulated pipelines. Our ownership of the Manta
Ray and Nautilus systems is through our unconsolidated affiliate, Neptune. We
also purchased from El Paso a 33.9% interest in the 24-mile Nemo natural gas
pipeline, which became operational in August 2001. Like Stingray, Shell is the
operator of the Manta Ray and Nemo systems. Shell is the administrative agent
for Nautilus. Shell and Marathon are our co-owners in Neptune and Shell owns the
remaining interest in Nemo. These systems transported a combined 265,914 MMBtu/d
of natural gas during 2001, on a net basis.

S-47

NGL AND PETROCHEMICAL PIPELINES

Our NGL and petrochemical pipelines transport mixed NGLs and hydrocarbons
to our fractionation plants, distribute NGL products and propylene to
petrochemical plants and refineries and deliver propane to customers along the
Dixie pipeline. Our pipelines provide transportation services to customers on a
fee basis. Therefore, the results of operation for this business are generally
dependent upon the volume of product transported and the level of fees charged
to customers (which include our merchant businesses). Taken as a whole, this
business area does not exhibit a significant degree of seasonality. However,
volumes on the Dixie pipeline are higher in the November through March timeframe
due to increased use of propane for heating in the southeastern United States.
In addition, volumes on the Lou-Tex NGL pipeline are generally higher during the
April through September period due to gasoline blending considerations at
refineries.

The maximum number of barrels that these systems can transport per day
depends upon the operating balance achieved at a given time between various
segments of the system. Because the balance is dependent upon the mix of
products to be shipped and the demand levels at the various delivery points, the
exact capacity of the systems cannot be stated. As shown in the following table,
utilization is measured in terms of throughput (in MBPD, on a net basis).

FOR YEAR ENDED DECEMBER 31,
-----------------------------
NGL AND PETROCHEMICAL PIPELINES 1999 2000 2001
------------------------------- ------- ------- -------

Dixie....................................................... 14 14 26
Louisiana Pipeline System................................... 74 115 138
Lou-Tex Propylene........................................... n/a 23 27
Lou-Tex NGL................................................. n/a 30 29
HSC......................................................... 99 106 133
Tri-States, Wilprise and Belle Rose......................... 41 42 36
Lake Charles/Bayport........................................ 5 5 6
Chunchula................................................... 7 6 5
Promix (1).................................................. 29 33 28
----- ----- -----
Total.................................................. 269 374 428
Pipelines acquired in 2002
Mid-America Pipeline System (2)........................... 634 637 641
Seminole Pipeline (2)..................................... 245 245 241
----- ----- -----
Total NGL and petrochemical pipelines.................. 1,148 1,256 1,310
===== ===== =====

---------------
(1) The Promix NGL pipelines are an integral component of the NGL fractionation
activities of Promix, the assets and equity earnings of which are accounted
for as part of our Fractionation segment.

(2) These assets were owned by Williams in 1999, 2000 and 2001, and we have
estimated our net utilization based on our current ownership percentages.

In the markets we serve, we compete with a number of intrastate and
interstate liquids pipeline companies (including those affiliated with major oil
and gas companies) and barge and truck fleet operators. In general, our NGL and
petrochemical pipelines compete with these entities in terms of transportation
rates and service. We believe that our pipeline systems are cost effective and
allow for significant flexibility in rendering transportation services for our
customers.

S-48

The following table summarizes our principal NGL and petrochemical pipeline
transportation and distribution networks:

LENGTH OUR
IN OWNERSHIP
NGL AND PETROCHEMICAL PIPELINES MILES INTEREST
------------------------------- ------ ---------

Mid-America Pipeline System................................. 7,226 98.0%
Dixie....................................................... 1,301 19.9%
Seminole Pipeline System.................................... 1,281 78.4%
Louisiana Pipeline System................................... 536 100.0%
Promix (1).................................................. 410 33.3%
Lou-Tex Propylene........................................... 291 100.0%
Lou-Tex NGL................................................. 206 100.0%
HSC......................................................... 175 100.0%
Tri-States.................................................. 169 33.3%
Lake Charles/Bayport........................................ 164 50.0%
Chunchula................................................... 117 100.0%
Belle Rose.................................................. 48 41.7%
Wilprise.................................................... 30 37.4%
------
Total NGL and petrochemical pipelines.................. 11,954
======

Mid-America Pipeline System. The Mid-America pipeline system is a major
NGL pipeline system with 7,226 miles of pipe that transports NGLs from the Rocky
Mountains, the Midwest and a portion of the Southwest to Mont Belvieu, the
largest NGL hub in the United States. Approximately 20 natural gas processing
plants in Wyoming, Utah and Colorado feed NGLs into the pipeline system for
delivery in the Midwest. The average transportation volumes on the Mid-America
pipeline system over the last three years were approximately 640 MBPD. Williams
currently operates this pipeline under a transition services agreement.

Dixie. The Dixie pipeline is a 1,301-mile propane pipeline which
transports propane supplies from Mont Belvieu, Texas and Louisiana to markets in
the southeastern United States. We own a 19.9% interest in Dixie. An affiliate
of Phillips operates the system.

Seminole Pipeline System. The Seminole pipeline system is a 1,281-mile
pipeline system that transports mixed NGLs and NGL products from Hobbs, Texas
and the Permian Basin to Mont Belvieu, Texas. The average volume transported on
the Seminole Pipeline System over the last three years was approximately 245
MBPD. Williams currently operates this pipeline under a transition services
agreement.

Louisiana Pipeline System. The Louisiana pipeline system is a 536-mile
network of nine NGL pipelines located in Louisiana. This system is used to
transport NGL products and serves a variety of customers including major
refineries and petrochemical companies along the Mississippi River corridor in
southern Louisiana. This system also provides transportation services for our
gas processing plants and other facilities located in Louisiana. In general, we
own and operate these pipelines.

Lou-Tex Propylene Pipeline System. The Lou-Tex propylene pipeline system
consists of a 291-mile pipeline used to transport propylene from Sorrento,
Louisiana to Mont Belvieu, Texas. Currently, this system is used to transport
chemical grade propylene for third parties from production facilities in
Louisiana to customers in Texas. This system also includes storage facilities
and a 28-mile NGL pipeline. We own and operate this system.

Lou-Tex NGL Pipeline System. The Lou-Tex NGL pipeline system consists of a
206-mile NGL pipeline used to provide transportation services for NGL products
and refinery grade propylene between the Louisiana and Texas markets. We also
use this pipeline to transport mixed NGLs from our Louisiana gas processing
plants to our Mont Belvieu NGL fractionation facility. We own and operate this
pipeline system.

S-49

HSC Pipeline System. The HSC pipeline system is a collection of NGL and
petrochemical pipelines aggregating 175 miles in length extending from our
Houston Ship Channel import/export terminal facility to Mont Belvieu, Texas.
This pipeline is used to deliver products to third-party petrochemical plants
and refineries as well as to deliver feedstocks to our Mont Belvieu facilities.
This system is also used to transport MTBE produced by BEF to delivery locations
along the Houston Ship Channel. We own and operate this pipeline system.

Tri-States, Belle Rose and Wilprise. We participate in three pipeline
joint ventures that supply mixed NGLs to the BRF and Promix NGL fractionators.
We own a 33.3% interest in Tri-States, which owns a l69-mile NGL pipeline that
extends from Mobile Bay, Alabama to near Kenner, Louisiana. In addition, we own
a 41.7% interest in and operate Belle Rose, which owns a 48-mile NGL pipeline
that extends from near Kenner, Louisiana to Promix. We own a 37.4% interest in
Wilprise, which owns a 30-mile NGL pipeline that extends from near Kenner,
Louisiana to Sorrento, Louisiana. Williams operates the Tri-States and Wilprise
systems.

Lake Charles/Bayport. Our Lake Charles/Bayport system is a 164-mile
propylene pipeline used to distribute polymer grade propylene from Mont Belvieu
to an affiliate of Shell's polypropylene plants in Lake Charles, Louisiana and
Bayport, Texas and to Aristech's facility in La Porte, Texas. A segment of the
pipeline is jointly owned by us and a Shell affiliate, and another segment is
leased from Exxon Mobil.

Chunchula. The Chunchula pipeline system is a 117-mile NGL pipeline
extending from the Alabama-Florida border to our storage and NGL fractionation
facilities in Petal, Mississippi for further distribution. We own and operate
this system.

Promix NGL Pipeline System. The Promix pipeline system is a 410-mile NGL
gathering pipeline that gathers mixed NGLs from 12 processing plants in
Louisiana, including the Neptune plant, for delivery to the Promix fractionator.

NGL AND PETROCHEMICAL STORAGE AND IMPORT/EXPORT TERMINAL

Storage. Our NGL and petrochemical storage facilities and import/export
terminal are integral parts of our pipeline operations. In general, our storage
wells are used to store mixed NGLs, NGL products and petrochemical products for
customers and ourselves. The profitability of storage operations is primarily
dependent upon the volume of material stored and the level of fees charged.

We also own storage facilities located at Breaux Bridge, Napoleonville,
Sorrento and Venice, Louisiana having a gross capacity of 33 MMBbls and a net
capacity of 14.8 MMBbls. Our Mississippi storage assets are comprised of
facilities located at or near Petal and Hattiesburg having a gross capacity of
12 MMBbls and a net capacity of 9.5 MMBbls. Of the facilities located in
Louisiana and Mississippi, we operate those located in Breaux Bridge, Louisiana
and Petal, Mississippi. Affiliates of Koch, Dynegy and Shell operate the
remaining facilities. In January 2002, we completed the purchase of
Diamond-Koch's Mont Belvieu storage assets for $129 million. These facilities
include 30 storage wells with a useable capacity of 68 MMBbls and allow for the
storage of mixed NGLs, NGL products and petrochemicals. With the addition of
these facilities, we own and operate 95 MMBbls of storage capacity at Mont
Belvieu. In connection with our purchase of the Mid-America and Seminole
pipeline systems in July 2002, we acquired 20 underground NGL and petrochemical
storage wells located in five states. The Mid-America and Seminole storage
facilities have a

S-50

gross capacity of 4.6 MMBbls and a net capacity of 4.5 MMBbls. The following
table summarizes our storage assets:

GROSS NET
CAPACITY, CAPACITY,
STORAGE ASSETS MMBBLS MMBBLS
-------------- --------- ---------

Texas....................................................... 95.9 95.7
Louisiana................................................... 33.0 14.8
Mississippi................................................. 12.0 9.5
New Mexico.................................................. 2.7 2.6
Iowa........................................................ 0.5 0.5
Nebraska.................................................... 0.3 0.3
Oklahoma.................................................... 0.1 0.1
----- -----
Total.................................................. 144.5 123.5
===== =====

When used in conjunction with our processing operations, these wells allow
us to mix various batches of feedstock and maintain a sufficient supply and
stable composition of feedstock to our processing facilities. At times, we
provide some of our processing customers with short-term storage services
(typically 30 days or less) at nominal fees when they cannot take immediate
delivery of products. Our intersegment revenues for the Pipelines segment
include those fees charged to our various merchant businesses for use of the
storage facilities.

We are also in the merchant storage business, with our focus being to
attract customers to store products in our wells for a fee. Our competitors in
this area are other merchant storage and pipeline companies such as TEPPCO,
Dynegy and Equistar. Major oil and gas companies such as Exxon Mobil and
ConocoPhillips occasionally use their proprietary storage assets in a merchant
role thereby entering into competition with us and other merchant providers. Our
Mont Belvieu facilities (including those recently acquired from Diamond-Koch)
represent the largest merchant storage facilities in the world for NGLs and
olefins. We compete with other service providers primarily in terms of the fees
charged, pipeline connections and dependability. We believe that due to the
integrated nature of our operations, our storage customers have access to a
competitively priced, flexible and dependable network of assets.

Import/Export Terminal. We lease and operate an NGL import facility
located on the Houston Ship Channel that enables NGL tankers to be offloaded at
their maximum unloading rate of 10,000 barrels per hour, thus minimizing laytime
and increasing the number of vessels that can be offloaded. This facility is
primarily used to offload volumes bound for our facilities in Mont Belvieu.
Typically, our import activity exhibits little seasonality; however, throughput
can be positively affected when domestic demand for NGL products exceeds supply
making it profitable to transport mixed NGLs and NGL products by barge or ship
from overseas locations or other domestic ports. For example, imports of normal
butane destined for our isomerization plants increased significantly during the
second quarter of 2001 due to demand for isobutane. In addition, we own a 50.0%
interest in EPIK, which owns NGL export facilities at the same terminal
including an NGL products chiller and related equipment used for loading
refrigerated marine tankers. The export terminal can load vessels of
refrigerated propane and butane at rates up to 5,000 barrels per hour.
Traditionally, EPIK's export volumes are higher during the winter months due to
increased propane exports. The profitability of import and export activities
primarily depends upon the quantities loaded and offloaded and the throughput
fees associated with each activity.

S-51

The following table shows volumes loaded and offloaded through our
import/export terminal over the last three years (in MBPD, on a net basis):

FOR YEAR ENDED
DECEMBER 31,
------------------
FACILITY 1999 2000 2001
-------- ---- ---- ----

NGL import facility......................................... 14 9 45
EPIK........................................................ 10 17 8
-- -- --
Total Imports and Exports.............................. 24 26 53
== == ==

When compared to 2000, export activity declined as strong domestic pricing
for products reduced the economic need to export. Normal butane imports were
higher in 2001 due to increased isobutane production.

Our NGL import and EPIK's NGL export facility have a small number of
competitors, primarily Dynegy and Dow. These operations compete primarily in
terms of service, such as the ability to quickly load or offload vessels. Our
competitive position is enhanced because our extensive storage and pipeline
assets at Mont Belvieu allow us to load and offload ships very efficiently.

In February 2002, we acquired a 50.0% interest in OTC, which owns a dock
facility located in Seabrook, Texas for the receipt, storage, handling and
redelivery of polymer grade propylene. We acquired our interest in OTC in
connection with our purchase of the Mont Belvieu III propylene fractionation
facility from Diamond-Koch. At maximum rates, this facility can load 144 MBPD of
polymer grade propylene onto ships and barges. The OTC facility is an integral
part of our Mont Belvieu III propylene fractionation business, of which the
assets and earnings (including those of OTC) are accounted for as part of our
Fractionation segment.

FRACTIONATION

NGL FRACTIONATION

NGL fractionation facilities separate mixed NGL streams into discrete NGL
products: ethane, propane, isobutane, normal butane and natural gasoline. Ethane
is primarily used in the petrochemical industry as feedstock for ethylene, one
of the basic building blocks for a wide range of plastics and other chemical
products. Propane is used both as a petrochemical feedstock in the production of
ethylene and propylene and as a heating, engine and industrial fuel. Isobutane
is fractionated from mixed butane (a mixed stream of normal butane and
isobutane) or refined from normal butane through the process of isomerization,
principally for use in refinery alkylation to enhance the octane content of
motor gasoline, in the production of MTBE, and in the production of propylene
oxide. Normal butane is used as a petrochemical feedstock in the production of
ethylene and butadiene (a key ingredient of synthetic rubber), as a blendstock
for motor gasoline and to derive isobutane through isomerization. Natural
gasoline, a mixture of pentanes and heavier hydrocarbons, is primarily used as a
blendstock for motor gasoline or as a petrochemical feedstock.

The three principal sources of mixed NGLs fractionated in the United States
are (1) domestic gas processing plants, (2) domestic crude oil refineries and
(3) imports of butane and propane mixtures. When produced at the wellhead,
natural gas consists of a mixture of hydrocarbons that must be processed to
remove impurities and render the gas suitable for pipeline transportation. Gas
processing plants are located near the production areas and separate pipeline
quality natural gas (principally methane) from mixed NGLs and other components.
After being extracted from natural gas, mixed NGLs are typically transported to
a centralized facility for fractionation. Recoveries of mixed NGLs by gas
processing plants represent the most important source of throughput for our NGL
fractionators and are generally governed by the degree to which NGL prices
exceed the cost (principally that of natural gas as a feedstock and as a fuel)
of separating the mixed NGLs from the natural gas stream. When operating and
extraction costs of gas processing plants are higher than the incremental value
of the NGL products that would be received by NGL extraction, the mixed NGL
recovery levels of gas processing plants may be reduced, leading to a reduction
in volumes available for NGL fractionation.

S-52

Crude oil and condensate production also contain varying amounts of NGLs,
which are removed during the refining process and are either fractionated by the
refiners themselves or delivered to third-party NGL fractionation facilities
like those owned by us. The mixed NGLs delivered from domestic gas processing
plants and crude oil refineries to our NGL fractionation facilities are
typically transported by NGL pipelines and, to a lesser extent, by railcar and
truck. We also take delivery of mixed NGL imports through our Houston Ship
Channel import terminal, which is connected to our Mont Belvieu complex via
pipeline.

The majority of our NGL fractionation facilities process mixed NGL streams
for third-party customers and our NGL merchant business by charging them a toll
fractionation fee. Toll fee arrangements typically include a base cents per
gallon fee for mixed NGLs processed subject to adjustment for changes in certain
fractionation expenses. At our Norco facility, we are paid for fractionation
services by receiving a percentage of NGLs fractionated for third-party
customers, or in-kind fees. The results of operation of our NGL fractionation
business are dependent upon the volume of mixed NGLs processed and either the
level of toll processing fees charged (in toll fee-based operations) or the
value of NGLs received (applicable to in-kind fee arrangements only). The NGL
fractionation business exhibits little to no seasonal variation. Lastly, we are
exposed to the pricing risks of NGLs only to the extent that we receive in-kind
fees for our services, since our customers generally retain title to the mixed
NGL streams that we process and the NGL products that are ultimately produced.

Our management believes that sufficient volumes of mixed NGLs, especially
those originating from Gulf Coast gas processing plants, will be available for
fractionation in the foreseeable future. These gas processing plants are
expected to benefit from anticipated increases in natural gas production from
emerging deepwater developments in the Gulf of Mexico offshore Louisiana.
Deepwater natural gas production has historically had a higher concentration of
NGLs than continental shelf or domestic land-based production along the Gulf
Coast. In addition, significant volumes of mixed NGLs are contractually
committed to our facilities by joint owners and third-party customers.

Although competition for NGL fractionation services is primarily based on
the fractionation fee, the ability of an NGL fractionator to obtain mixed NGLs
and distribute NGL products is also an important competitive factor and is a
function of the existence of the necessary pipeline and storage infrastructure.
NGL fractionators connected to extensive transportation and distribution systems
such as ours have direct access to larger markets than those with less extensive
connections. We compete with a number of NGL fractionators in Texas, Louisiana
and Kansas. Our Mont Belvieu NGL fractionator competes directly with three local
facilities having an estimated combined processing capacity of 475 MBPD and
indirectly with two other Texas facilities having a combined processing capacity
of 210 MBPD. In addition, our facilities compete on a more limited basis with
two facilities in Kansas and several facilities in Louisiana. Finally, we also
compete with a number of producers who operate small NGL fractionators at
individual field processing facilities.

Our NGL fractionation operations include eight NGL fractionators with a
combined gross processing capacity of 572 MBPD and a net processing capacity to
us of 303 MBPD. The following table summarizes our NGL fractionation facilities:

GROSS OUR OUR NET
CAPACITY, OWNERSHIP CAPACITY,
NGL FRACTIONATION FACILITY LOCATION MBPD INTEREST MBPD
-------------------------- ----------- --------- --------- ---------

Mont Belvieu............................ Texas 210 75.0% 131
Norco................................... Louisiana 70 100.0% 70
Promix.................................. Louisiana 145 33.3% 48
BRF..................................... Louisiana 60 32.2% 19
Toca-Western............................ Louisiana 14 100% 14
Tebone.................................. Louisiana 30 28.9% 9
Petal................................... Mississippi 7 100.0% 7
Venice.................................. Louisiana 36 13.1% 5
---- ----
Total.............................. 572 303
==== ====

S-53

During 2001, our NGL fractionation facilities processed mixed NGLs at an
average rate of 204 MBPD or 70% of capacity, both amounts on a net basis. The
following table shows net processing volumes and capacity (in MBPD) and the
corresponding overall utilization rates of our NGL fractionation facilities for
the last three years:

FOR YEAR ENDED
DECEMBER 31,
--------------------
NGL FRACTIONATION FACILITY 1999 2000 2001
-------------------------- ---- ---- ----

Mont Belvieu................................................ 78 106 110
Norco....................................................... 48 47 41
BRF......................................................... 13 15 14
Promix...................................................... 30 34 30
Other....................................................... 15 11 9
--- --- ---
Total net volume....................................... 184 213 204
=== === ===
Net capacity................................................ 264 290 290
=== === ===
Utilization rate............................................ 70% 73% 70%
=== === ===

Mont Belvieu. We operate one of the largest NGL fractionation facilities
in the United States with a gross processing capacity of 210 MBPD at Mont
Belvieu, Texas. Mont Belvieu is the hub of the domestic NGL industry because of
its proximity to the largest concentration of refineries and petrochemical
plants in the United States and its location on a large naturally-occurring salt
dome that provides for the underground storage of significant quantities of
NGLs. Our Mont Belvieu NGL fractionation facility is supported by long-term
fractionation agreements with Burlington Resources and Duke (accounting for 63
MBPD of net processing volume in 2001), each of which is a significant producer
of NGLs and a co-owner of the facility. We own an effective 75% interest in this
facility.

Norco. We own and operate an NGL fractionation facility at Norco,
Louisiana. The Norco facility receives mixed NGLs via pipeline from the
Yscloskey, Toca and Crawfish gas processing plants in Louisiana and has a gross
processing capacity of 70 MBPD. During 2001, long-term in-kind fee arrangements
exclusive to this facility accounted for approximately 41 MBPD of processing
volume.

BRF. We operate and own a 32.2% interest in BRF, which owns a 60 MBPD NGL
fractionation facility and related pipeline transportation assets located near
Baton Rouge, Louisiana. The BRF facility processes mixed NGLs provided by the
co-owners of the facility (Williams, BP and Exxon Mobil) from production areas
in Alabama, Mississippi and southern Louisiana including offshore Gulf of Mexico
areas.

Promix. We operate and own a 33.3% interest in Promix, which owns a 145
MBPD NGL fractionation facility located near Napoleonville, Louisiana. Promix
includes a 315-mile mixed NGL gathering system connected to nine gas processing
plants, five NGL salt dome storage wells and a barge loading facility. Promix
receives mixed NGLs from numerous gas processing plants located in southern
Louisiana.

Toca-Western. We own and operate an integrated NGL fractionation and
natural gas processing facility located in St. Bernard Parish, Louisiana that we
acquired in 2002. The NGL fractionator contained within this complex has a gross
and net processing capacity of 14 MBPD.

Tebone. We own a 28.9% interest in a 30 MBPD NGL fractionation facility
located in Asceasion Parish, Louisiana. The Tebone NGL fractionation facility
was built in the 1960s and receives NGLs from the North Terreborne gas
processing plant.

Petal. We own and operate an NGL fractionation facility at Petal,
Mississippi that has an average production capacity of 7 MBPD. The Petal
facility is connected to our Chunchula pipeline system and serves NGL producers
in Mississippi, Alabama and Florida.

Venice. As a result of our VESCO investment, we own a 13.1% interest in a
36 MBPD NGL fractionator located in Plaquemines Parish, Louisiana. This facility
is part of the integrated natural gas processing complex owned by VESCO.

S-54

ISOMERIZATION

Our commercial isomerization units convert normal butane into mixed butane,
which is subsequently fractionated into normal butane, isobutane and high purity
isobutane. The demand for commercial isomerization services depends upon the
industry's requirements for high purity isobutane and isobutane in excess of
naturally occurring isobutane produced from NGL fractionation and refinery
operations. Isobutane demand is marginally higher in the spring and summer
months due to the demand for isobutane-based clean fuel additives such as MTBE
in the production of motor gasoline. The results of operation of this business
are generally dependent upon the volume of normal and mixed butanes processed
and the level of toll processing fees charged to customers. The principal uses
of isobutane are for alkylation, propylene oxide and in the production of MTBE.

We use the isomerization facilities to convert normal butane into
isobutane, including high purity grade, for our toll processing customers,
including our isobutane merchant business that is part of our Processing
segment. Our larger third-party toll processing customers, such as Lyondell and
Huntsman, operate under long-term contracts in which they supply normal butane
feedstock and pay us toll processing fees based on the volume of isobutane
produced. We, as well as our partners in BEF, use the high purity isobutane
produced by these facilities to meet our feedstock obligations of the MTBE plant
under tolling arrangements. Our isobutane merchant business uses the
isomerization facilities to meet the requirements of its isobutane sales
contracts when the processing of company-owned inventories of normal and/or
mixed butanes is necessary. During 2001, 18 MBPD of isobutane production was
attributable to our merchant activities, 14 MBPD to BEF-related contracts, with
the balance related to various toll processing arrangements.

Our isomerization business includes three butamer reactor units and eight
associated DIBs located in Mont Belvieu, Texas, which comprise the largest
commercial isomerization complex in the United States. These facilities have an
average combined production capacity of 116 MBPD of isobutane. We own the
isomerization facilities with the exception of one of the butamer reactor units,
which we control through a long-term lease. We operate the facilities. The
following table shows isobutane production and capacity (both in MBPD) and
overall utilization for the last three years:

FOR YEAR ENDED
DECEMBER 31,
--------------------
ISOMERIZATION FACILITIES 1999 2000 2001
------------------------ ---- ---- ----

Production.................................................. 74 74 80
Capacity.................................................... 116 116 116
Utilization rate............................................ 64% 64% 69%

In the isomerization market, we compete with facilities located in Kansas,
Louisiana and New Mexico. Competitive factors affecting this business include
the level of toll processing fees charged, the quality of isobutane that can be
produced and access to pipeline and storage infrastructure. We believe that our
isomerization facilities benefit from the integrated nature of the Mont Belvieu
complex with its extensive connections to pipeline and storage assets.

PROPYLENE FRACTIONATION

In general, propylene fractionation plants separate refinery grade
propylene (a mixture of propane and propylene) into either polymer grade
propylene or chemical grade propylene along with by-products of propane and
mixed butane. Polymer grade propylene can also be produced from chemical grade
propylene feedstock. Likewise, chemical grade propylene is also a by-product of
olefin (ethylene) production. Approximately 50% of the demand for polymer grade
propylene is attributable to polypropylene, which has a variety of end uses,
including packaging film, fiber for carpets and upholstery and molded plastic
parts for appliance, automotive, houseware and medical products. Chemical grade
propylene is a basic petrochemical used in plastics, synthetic fibers and foams.
Overall, the propylene fractionation business exhibits little seasonality.

Results of operations for our polymer grade propylene plants are generally
dependent upon toll processing arrangements and propylene merchant activities.
Under toll processing arrangements, we are paid

S-55

fees based on throughput of refinery grade propylene used to produce polymer
grade propylene. Our largest toll processing customers in 2001 were Huntsman and
Equistar. In our propylene merchant business, we have several long-term polymer
grade propylene sales agreements, the largest of which is with an affiliate of
Shell. To meet our merchant obligations, we have entered into several long-term
agreements to purchase refinery grade propylene. To limit the exposure to price
risk in the merchant side of this business, we attempt to match the timing and
price of our feedstock purchases with those of the sales of end products. During
2001, 10 MBPD of our net polymer grade propylene production was associated with
toll processing operations with the balance attributable to merchant activities.

We can unload barges carrying refinery grade propylene using our import
terminal located on the Houston Ship Channel. In addition, we can receive
supplies of refinery grade propylene through our Mont Belvieu truck and rail
unloading facility and from refineries and other producers connected to our HSC
pipeline system. In turn, polymer grade propylene is transported to customers by
truck or pipeline. We also can load and unload volumes of polymer grade
propylene as a result of our 50% investment in Olefins Terminal Corporation
located in Seabrook, Texas.

We compete with numerous producers of polymer grade propylene, which
include many of the major refiners on the Gulf Coast. Generally, the propylene
fractionation business competes in terms of the level of toll processing fees
charged and access to pipeline and storage infrastructure. Our propylene
fractionation units have been designed to be cost efficient which allows us to
be very competitive in terms of processing fees. In addition, our facilities are
connected to extensive pipeline transportation and storage facilities, which
provide our customers with operational flexibility.

Our propylene fractionation business consists of three polymer grade
propylene facilities and one chemical grade propylene plant. These assets
include a controlling interest in our Mont Belvieu III unit, which we purchased
from Diamond-Koch in February 2002. The following table summarizes our propylene
fractionation business assets and ownership:

GROSS EFFECTIVE NET
CAPACITY, OWNERSHIP CAPACITY,
PROPYLENE FRACTIONATION FACILITY LOCATION MBPD INTEREST MBPD
-------------------------------- --------- --------- --------- ---------

Mont Belvieu I................................... Texas 17 100.0% 17
Mont Belvieu II.................................. Texas 14 100.0% 14
Mont Belvieu III................................. Texas 41 66.7% 27
BRPC............................................. Louisiana 23 30.0% 7
--------- ---------
Total........................................ 95 65
========= =========

During 2001, our propylene fractionation facilities produced at an average
rate of 31 MBPD or 82% of capacity, both amounts on a net basis. The table below
shows our net production volumes and capacity (both in MBPD) based on our
current ownership interest and the corresponding overall utilization rates of
our facilities for the last three years:

FOR YEAR ENDED
DECEMBER 31,
--------------------
PROPYLENE FRACTIONATION FACILITY 1999 2000 2001
-------------------------------- ---- ---- ----

Mont Belvieu I and II (1)................................... 28 29 27
BRPC........................................................ n/a 4 4
--- -- --
Total net volume........................................ 28 33 31
=== == ==
Net capacity................................................ 31 35 38
=== == ==
Utilization rate............................................ 90% 94% 82%
=== == ==

---------------
(1) Does not include information for Mont Belvieu III, which we did not own
during the periods indicated.

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Mont Belvieu I, II and III. We operate three polymer grade propylene
fractionation facilities (Mont Belvieu I, II and III) in Mont Belvieu, Texas
having a combined capacity of 58.3 MBPD. We own a 54.6% interest in Mont Belvieu
I, all of Mont Belvieu II and a 66.7% interest in Mont Belvieu III. We lease the
remaining 45.4% interest in Mont Belvieu I from an affiliate of Shell.

BRPC. We operate and own a 30.0% interest in BRPC, which owns a 23 MBPD
chemical grade propylene production facility located near Baton Rouge,
Louisiana. This unit, located across the Mississippi River from Exxon Mobil's
refinery and chemical plant, fractionates refinery grade propylene produced by
Exxon Mobil into chemical grade propylene for a toll processing fee. The results
of operation of BRPC depend upon the volume of refinery grade propylene
processed and the level of fees we charge Exxon Mobil.

PROCESSING

The Processing segment consists of our natural gas processing business and
related merchant activities. At the core of our natural gas processing business
are thirteen processing plants located on the Louisiana and Mississippi Gulf
Coast with a gross natural gas processing capacity of 11.77 Bcf/d (3.38 Bcf/d on
a net basis). Our net share of the NGL production from these plants, in addition
to NGLs we purchase on a merchant basis and a portion of the production from our
Mont Belvieu isomerization facilities, support the merchant activities included
in this operating segment.

The majority of the operating margin earned by our natural gas processing
plants is based on the relative economic value of the mixed NGLs extracted by
the gas plants as compared to the costs of extracting the mixed NGLs
(principally that of natural gas as a feedstock and as a fuel, plus plant
operating expenses). Natural gas processing arrangements where the processor
takes title to the NGLs extracted from the natural gas stream are defined as
"keepwhole contracts." The processor reimburses producers for the market value
of the energy extracted based upon the Btus consumed from the natural gas stream
in the form of fuel and mixed NGLs, multiplied by the market value of natural
gas. The processor derives a profit margin to the extent the market value of the
NGLs extracted exceeds the costs of extraction.

The most significant contract affecting our natural gas processing business
is the 20-year Shell processing agreement, which grants us the right to process
Shell's current and future production from the Gulf of Mexico within the state
and federal waters off Texas, Louisiana, Mississippi, Alabama and Florida on a
keepwhole basis. This includes natural gas production from deepwater
developments. This is a life of lease dedication, which may extend the agreement
well beyond 20 years. Shell is the largest oil and gas producer and holds one of
the largest lease positions in the deepwater Gulf of Mexico. Generally, this
contract has the following rights and obligations:

- the exclusive right to process substantially all of Shell's Gulf of
Mexico natural gas production; plus

- the exclusive right to process all natural gas production from leases
dedicated by Shell; plus

- the right to all title, interest and ownership in the mixed NGL stream
extracted by our gas plants from Shell's natural gas production from such
leases; with

- the obligation to re-deliver to Shell the natural gas stream after the
mixed NGL stream is extracted.

We believe that natural gas and its associated NGL production from the Gulf
of Mexico will significantly increase in the coming years as a result of
advances in seismic and deepwater development technologies and continued capital
spending for exploration and production by major oil companies.

Several deepwater Gulf of Mexico developments began production during 2001.
These include Shell's Ursa, Brutus, Oregano, Crosby, Einset and Serrano
developments. As a result of these new streams of rich natural gas, in the
fourth quarter of 2001, we had record equity NGL production of 80 MBPD.

Our natural gas processing facilities are primarily straddle plants that
are situated on mainline natural gas pipelines that bring unprocessed Gulf of
Mexico natural gas production onshore. Straddle plants allow us to extract NGLs
from a raw natural gas stream when the market value of the NGLs exceeds the cost
(principally that of natural gas as a feedstock and as a fuel) of extracting the
mixed NGLs. After extraction, we transport

S-57

the mixed NGLs to a centralized facility for fractionation into purity NGL
products such as ethane, propane, normal butane, isobutane and natural gasoline.
The purity NGL products can then be used by our merchant business to meet
contractual requirements or sold on spot and forward markets.

The natural gas throughput capacities of the plants are based on practical
limitations. Our utilization of these gas plants depends upon general economic
and operating conditions and is generally measured in terms of equity NGL
production. Equity NGL production is defined as the volume of NGLs extracted by
the gas plants to which we take title under the terms of processing agreements
or as a result of our plant ownership interests. Equity NGL production can be
adversely affected by high natural gas costs and/or low purity NGL product
prices. Our equity NGL production averaged 63 MBPD during 2001, 72 MBPD during
2000 and 67 MBPD during 1999.

As noted previously, we take title to a portion of the mixed NGLs that are
extracted by the gas plants. Once this mixed NGL volume is fractionated into
purity NGL products (ethane, propane, normal butane, isobutane and natural
gasoline), we use them to meet contractual requirements or sell them on spot and
forward markets as part of our overall merchant business activities. In our
isomerization merchant activities, we are party to a number of isobutane sales
contracts. To fulfill our obligations under these sales contracts, we can
purchase isobutane on the spot market for resale, sell our isobutane in
inventory or pay our isomerization business (which is part of the Fractionation
segment) a toll processing fee to process our inventories of imported or
domestically-sourced normal and mixed butanes into isobutane.

Since we take title to NGLs and are obligated under certain of our gas
processing contracts to pay market value for the energy extracted from the
natural gas stream, we are exposed to various risks, primarily that of commodity
price fluctuations. The prices of natural gas and NGLs are subject to
fluctuations in response to changes in supply, market uncertainty and a variety
of additional factors that are beyond our control. We attempt to mitigate these
risks through the use of commodity financial instruments.

The following table lists our gas processing plants, processing capacities
and corresponding ownership interest:

GROSS GAS NET GAS
PROCESSING OUR PROCESSING
CAPACITY OWNERSHIP CAPACITY
NATURAL GAS PROCESSING FACILITY LOCATION (BCF/D) INTEREST (BCF/D)
------------------------------- ----------- ---------- --------- ----------

Yscloskey.............................. Louisiana 1.85 28.2% 0.52
Calumet................................ Louisiana 1.60 35.4% 0.57
North Terrebonne....................... Louisiana 1.30 28.9% 0.38
Venice................................. Louisiana 1.30 13.1% 0.17
Toca................................... Louisiana 1.10 60.2% 0.66
Pascagoula............................. Mississippi 1.00 40.0% 0.40
Sea Robin.............................. Louisiana 0.95 15.5% 0.15
Blue Water............................. Louisiana 0.95 7.4% 0.07
Patterson II........................... Louisiana 0.60 2.0% 0.01
Iowa................................... Louisiana 0.50 2.0% 0.01
Neptune................................ Louisiana 0.30 66.0% 0.20
Toca-Western........................... Louisiana 0.16 100.0% 0.16
Burns Point............................ Louisiana 0.16 50.0% 0.08
---------- ----------
Total............................. 11.77 3.38
========== ==========

Some of our exposure to commodity price risk is mitigated because natural
gas with a high content of NGLs must be processed in order to meet pipeline
quality specifications and to be suitable for ultimate consumption. To the
extent that natural gas is not processed and does not meet pipeline quality
specifications, this unprocessed natural gas and its associated crude oil
production may be subject to being shut-in (i.e., to not being processed and
made marketable). Therefore, producers are motivated to reach contractual

S-58

arrangements that are acceptable to gas processors in order for gas processing
services to be available on a continuous basis (e.g., through natural gas cost
reductions and other economic incentives to gas processors).

Our gas processing business and related merchant activities encounter
competition from fully integrated oil companies, intrastate pipeline companies,
major interstate pipeline companies and their non-regulated affiliates, and
independent processors. Each of our competitors has varying levels of financial
and personnel resources and competition generally revolves around price, service
and location issues. Our integrated system affords us flexibility in meeting our
customers' needs. While many companies participate in the gas processing
business, few have a presence in significant downstream activities such as NGL
fractionation and transportation, import/export services and merchant activities
as we do. Our competitive or leading strategic position and sizeable presence in
these downstream businesses allows us to extract incremental value while
offering our customers enhanced services, including comprehensive service
packages.

Our merchant activities utilize a fleet of approximately 625 railcars, the
majority of which are under short and long term leases. The railcars are used to
deliver feedstocks to our facilities and to transport NGL products throughout
the United States. We have rail loading/unloading facilities at Mont Belvieu,
Texas, Breaux Bridge, Louisiana and Petal, Mississippi. These facilities service
our and our customers' rail shipments. This segment also includes our 13.1%
investment in VESCO. VESCO owns an integrated complex comprised of the Venice
gas processing plant, a fractionation facility, storage assets and gas gathering
pipelines in Louisiana.

OCTANE ENHANCEMENT

The Octane Enhancement segment consists of our 33.3% interest in BEF, which
owns a facility that produces motor gasoline additives to enhance octane. Our
partners in BEF are affiliates of Sunoco and Devon Energy. The BEF facility
currently produces MTBE and is located within our Mont Belvieu complex. The
gross capacity of the MTBE facility is approximately 15 MBPD with a net capacity
of 5 MBPD. For the years 2001, 2000 and 1999, net production averaged 5 MBPD.
EPCO operates the facility.

The production of MTBE is driven by oxygenated fuel programs enacted under
the federal Clean Air Act Amendments of 1990 and other legislation and as an
additive to increase octane in motor gasoline. Any changes to the oxygenated
fuel programs that enable localities to elect to not participate in these
programs, lessen the requirements for oxygenates or favor the use of
non-isobutane based oxygenated fuels would reduce the demand for MTBE and could
have a negative impact on our operations. Although oxygenated fuel requirements
can be satisfied by using other products such as ethanol, MTBE is the most
widely used due to its ready availability and history of acceptance by refiners.
Additionally, motor gasoline containing MTBE can be transported through
pipelines, which is a significant competitive advantage over alcohol blends such
as ethanol.

MTBE demand is linked to motor gasoline requirements in certain urban areas
of the United States designated as carbon monoxide and ozone non-attainment
areas by the Clean Air Act Amendments of 1990 and the California oxygenated
motor gasoline program. Motor gasoline demand in turn is affected by many
factors, including the price of motor gasoline (which is generally dependent
upon crude oil prices) and overall economic conditions. BEF has a ten-year
off-take agreement with Sunoco under which Sunoco is obligated to purchase all
of BEF's MTBE production through September 2004. Beginning in June 2000 and for
the remaining term of this agreement, Sunoco is required to purchase all of the
plant's MTBE production at spot-market related prices. Sunoco uses this MTBE
primarily to satisfy the gasoline blending requirements of its markets located
in the eastern United States.

Historically, the spot price for MTBE has been at a modest premium to
gasoline blend values. BEF is exposed to commodity price risk due to the
market-related pricing provisions of the Sunoco off-take agreement. In general,
MTBE prices are stronger during the April to September period of each year,
which corresponds with the summer driving season. Future MTBE demand is highly
dependent upon environmental regulation, federal legislation and the actions of
individual states (see "-- Recent Regulatory Developments" below).

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Each owner of BEF is responsible for supplying one-third of the facility's
isobutane feedstock requirements through June 2004. We, along with the other two
co-owners, use high purity isobutane produced at our Mont Belvieu facilities to
meet this obligation. The methanol feedstock used by BEF is purchased from third
parties under long-term contracts and transported to Mont Belvieu using our HSC
pipeline system. Lastly, BEF's MTBE production is transported to a location on
the Houston Ship Channel for delivery to Sunoco using our HSC pipeline system.

The MTBE market has a number of producers, including a number of refiners
who produce MTBE for internal consumption in the manufacture of reformulated
motor gasoline. In general, MTBE producers compete in terms of price and
production (in terms of economies of scale and quality of product). While the
Sunoco contract is in effect, BEF is not directly exposed to its competition,
although it is affected by market pricing through the Sunoco off-take agreement.
The world-class scale of the BEF facility, combined with the technological
advances incorporated into its construction and maintenance, make it one of the
most efficient domestic MTBE plants in operation.

Recent Regulatory Developments. In recent years, MTBE has been detected in
water supplies. The major source of ground water contamination appears to be
leaks from underground storage tanks. Although these detections have been
limited and the great majority have been well below levels of public health
concern, there have been calls for the phase-out of MTBE in motor gasoline in
various federal and state governmental agencies and advisory bodies. For
example, the Governor of California ordered the phase-out of MTBE in California
on March 25, 1999. California's deadline for the complete phase-out of MTBE is
December 31, 2003. At least twelve other states are following California's lead
and either have banned or currently are considering legislation to ban MTBE. In
addition, Congress is contemplating a federal ban on MTBE. On April 25, 2002,
the Senate approved an energy bill that in part would ban the use of MTBE within
four years of enactment and require the use of ethanol as a substitute for MTBE.
For additional information regarding the impact of environmental regulation on
BEF, see "Impact of the Clean Air Act's oxygenated fuels programs on our BEF
Investment" in our Annual Report on Form 10-K for the year ended December 31,
2001.

Alternative uses of the BEF facility. In light of these regulatory
developments, the owners of BEF have been formulating a contingency plan for use
of the BEF facility if MTBE were banned or significantly curtailed. Our
management is exploring possible conversion of the BEF facility from MTBE
production to alkylate production. We believe that if MTBE usage is banned or
significantly curtailed, the motor gasoline industry would need a substitute
additive to maintain octane levels in motor gasoline and that alkylate would be
an attractive substitute. We are currently undergoing an engineering study that
is expected to be completed by the end of the first quarter of 2003, at which
time a conversion cost estimate will be available. The cost to convert the
facility will depend on the type of alkylate process chosen and level of
alkylate production desired by the partnership.

OTHER

This operating segment is primarily comprised of fee-based marketing
services. For a small number of clients, we perform NGL marketing services for
which we charge a commission. The clients we serve are primarily located in the
states of Washington, California and Illinois. We utilize the resources of our
merchant businesses to perform these services. Commissions are generally based
on either a percentage of the final sales price negotiated on behalf of the
client or on a fixed fee per gallon basis. Our fee-based marketing services
handle approximately 23 MBPD of various NGL products with the period of highest
activity occurring during the summer months. The principal elements of
competition in this business are price and quality of service. This segment also
includes other engineering services, construction equipment rentals and computer
network services that support other operations and business activities.

EMPLOYEES

We do not have any employees. EPCO employs all the persons necessary for
the operation of our business. At June 30, 2002, EPCO had approximately 1,000
employees involved in the management and

S-60

operations of our business, none of whom were members of a union. We reimburse
EPCO for the services of certain of its employees under a long-term services
agreement.

MAJOR CUSTOMERS

Our revenues are derived from a wide customer base. Our largest customer,
Shell, accounted for 9.5% and 10.5% of consolidated revenues in 2000 and 2001,
respectively. Approximately 80% of our revenues from Shell during these periods
were attributable to sales of NGL products, which are recorded in our Processing
segment.

REGULATION AND ENVIRONMENTAL MATTERS

Our operations are subject to extensive regulations. Many federal, state
and local departments and agencies are authorized by statute to issue and have
issued laws and regulations binding on the energy industry and its individual
participants. The failure to comply with such rules and regulations can result
in substantial penalties. The regulatory burden on the energy industry increases
our cost of doing business and, consequently, affects our profitability.
However, we do not believe that we are affected in a significantly different
manner by these laws and regulations than are our competitors. For a more
detailed description of regulatory issues affecting our business, please refer
to Items 1 and 2 "Business and Properties -- Regulation and Environmental
Matters" in our Annual Report on Form 10-K for the year ended December 31, 2001.

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MANAGEMENT

The following table sets forth certain information with respect to the
executive officers and members of the board of directors of our general partner.
Executive officers and directors are elected for one-year terms.

NAME AGE POSITION WITH GENERAL PARTNER
---- --- -----------------------------

Dan L. Duncan........................ 69 Director and Chairman of the Board
O.S. Andras.......................... 67 Director, President and Chief Executive Officer
Richard H. Bachmann.................. 49 Director, Executive Vice President, Chief Legal
Officer and Secretary
Michael A. Creel..................... 48 Executive Vice President and Chief Financial Officer
A.J. Teague.......................... 57 Executive Vice President
William D. Ray....................... 67 Executive Vice President
Charles E. Crain..................... 70 Senior Vice President
A. Monty Wells....................... 56 Senior Vice President
W. Ordemann.......................... 43 Senior Vice President
Gil H. Radtke........................ 41 Senior Vice President
Michael J. Knesek.................... 48 Vice President, Controller and Principal Accounting
Officer
W. Randall Fowler.................... 46 Vice President and Treasurer
Randa D. Williams.................... 41 Director
J.R. Eagan........................... 48 Director
J.A. Berget.......................... 49 Director
Dr. Ralph S. Cunningham.............. 61 Director
Augustus Y. Noojin, III.............. 55 Director
Lee W. Marshall, Sr.................. 70 Director
Richard S. Snell..................... 60 Director

Dan L. Duncan was elected Chairman of the Board and a Director of our
general partner in April 1998. Mr. Duncan has served as Chairman of the Board of
our predecessor, EPCO, since 1979.

O.S. Andras was elected President, Chief Executive Officer and a Director
of our general partner in April 1998. Mr. Andras served as President and Chief
Executive Officer of EPCO from 1996 to February 2001.

Richard H. Bachmann was elected a Director of our general partner in June
2000. He has served as Executive Vice President and Chief Legal Officer of our
general partner and EPCO since January 1999. Previously, he was a partner with
the legal firms of Snell & Smith P.C. and Butler & Binion.

Michael A. Creel was elected an Executive Vice President of our general
partner in February 2001, having served as a Senior Vice President of our
general partner since November 1999. In June 2000, Mr. Creel, a certified public
accountant, assumed the role of Chief Financial Officer of our company along
with his other responsibilities. From 1997 to 1999 he held a series of positions
with a Shell affiliate, including Senior Vice President, Chief Financial Officer
and Treasurer. From 1995 to 1997, Mr. Creel was Vice President and Treasurer of
NorAm Energy Corp.

A.J. ("Jim") Teague was elected an Executive Vice President of our general
partner in November 1999. From 1998 to 1999 he served as President of a Shell
affiliate and from 1997 to 1998 was President of Marketing and Trading for
Mapco, Inc.

William D. Ray was elected an Executive Vice President of our general
partner in April 1998. Mr. Ray has served as EPCO's Executive Vice President of
Supply and Marketing since 1985.

Charles E. Crain was elected a Senior Vice President of our general partner
in April 1998. Mr. Crain has served as Senior Vice President of Operations for
EPCO since 1991.

A. Monty Wells was elected a Senior Vice President of our general partner
in June 2000. Mr. Wells has served in a number of managerial positions with EPCO
since 1980 including Vice President of Marketing and Supply.

S-62

W. ("Bill") Ordemann was elected a Senior Vice President of our general
partner in September 2001. Mr. Ordemann has served in executive level positions
in our NGL businesses since 1999. From 1996 to 1999, he served as a Vice
President of two Shell affiliates, including TNGL.

Gil H. Radtke was elected a Senior Vice President of our general partner in
February 2002. Mr. Radtke joined our company in connection with our purchase of
Diamond-Koch's storage and propylene fractionation assets in January and
February 2002. Before joining our company, Mr. Radtke served as President of the
Diamond-Koch joint venture where he was responsible for its storage, propylene
fractionation, pipeline and NGL fractionation businesses. Mr. Radtke was
employed by Valero Energy Corporation (a partner in the Diamond-Koch joint
venture) for the last eighteen years in various commercial and analysis roles.

Michael J. Knesek was elected Principal Accounting Officer and a Vice
President of our general partner in August 2000. Since 1990, Mr. Knesek, a
certified public accountant, has been the Controller and a Vice President of
EPCO.

W. Randall Fowler was elected Treasurer and a Vice President of our general
partner in August 2000. Mr. Fowler joined our company as director of investor
relations in 1999. From 1995 to 1999, Mr. Fowler served in a number of corporate
finance and accounting-related capacities at NorAm Energy Corp., including
Director of Finance Wholesale Energy Marketing and Assistant Treasurer.

Randa D. Williams was elected a Director of our general partner in April
1998. In February 2001, she was promoted to President and Chief Executive
Officer of EPCO from her previous position of Group Executive Vice President of
EPCO, a position she had held since 1994. Ms. Williams is the daughter of Dan L.
Duncan.

J.R. (Jeri) Eagan was elected a Director of our general partner in October
2000. Since 1999, Ms. Eagan has served in various executive-level positions with
Shell and currently holds the office of Chief Financial Officer of Shell Oil
Company in addition to that of Vice President Finance & Commercial Operations of
a Shell subsidiary. From 1994 to 1999, she worked on several assignments for the
Royal Dutch/Shell Group of companies in London.

J.A. (Jorn) Berget was elected a Director of our general partner in
November 2000. Since 1995, Mr. Berget has served in various managerial positions
for the Royal Dutch/Shell Group of companies and Shell, including Vice President
and General Manager for one of its subsidiaries since 2000. Mr. Berget also
serves as a director of Enventure Global Technologies (a joint venture between
Shell and Halliburton Company).

Dr. Ralph S. Cunningham was elected a Director of our general partner in
April 1998. Dr. Cunningham retired in 1997 from Citgo Petroleum Corporation,
where he had served as President and Chief Executive Officer since 1995. Dr.
Cunningham serves as a director of Tetra Technologies, Inc. (a publicly traded
energy services and chemicals company) and Agrium, Inc. (a Canadian publicly
traded agricultural chemicals company) and was a former director of EPCO from
1987 to 1997. Dr. Cunningham serves as Chairman of our Audit and Conflicts
Committee.

Augustus Y. ("Gus") Noojin, III was elected a Director of our general
partner in May 2002. Mr. Noojin was elected President and Chief Executive
Officer of Shell U.S. Gas & Power LLC, an affiliate of Shell, in May 2002, and
has held various other executive-level positions with affiliates of Shell.

Lee W. Marshall, Sr. was elected a Director of our general partner in April
1998. Mr. Marshall has been the Managing Partner and principal owner of Bison
Resources, LLC since 1993. He has also served in senior management positions
with Union Pacific Resource and Tenneco Oil. Mr. Marshall is a member of our
Audit and Conflicts Committee.

Richard S. Snell was elected a Director of our general partner in June
2000. Mr. Snell was an attorney with Snell & Smith, P.C. for seven years after
founding the firm in 1993. He is currently a partner with the law firm of
Thompson & Knight LLP in Houston, Texas and is a certified public accountant.
Mr. Snell is a member of our Audit and Conflicts Committee.

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TAX CONSIDERATIONS

The tax consequences to you of an investment in common units will depend in
part on your own tax circumstances. For a discussion of the principal federal
income tax considerations associated with our operations and the ownership and
disposition of common units, please read "Tax Considerations" in the
accompanying prospectus. You are urged to consult your own tax advisor about the
federal, state, local and foreign tax consequences peculiar to your
circumstances.

We estimate that if you purchase common units in this offering and own them
through December 31, 2005, then you will be allocated, on a cumulative basis, an
amount of federal taxable income for that period that will be less than 10% of
the cash distributed with respect to that period. If you own common units
purchased in this offering for a shorter period, the percentage of federal
taxable income allocated to you may be higher. These estimates are based upon
the assumption that our available cash for distribution will approximate the
amount required to distribute cash to the holders of the common units in an
amount equal to the announced quarterly distribution of $0.345 per unit and
other assumptions with respect to capital expenditures, cash flow and
anticipated cash distributions. These estimates and assumptions are subject to,
among other things, numerous business, economic, regulatory, competitive and
political uncertainties beyond our control. Further, the estimates are based on
current tax law and certain tax reporting positions that we have adopted with
which the IRS could disagree. In addition, subsequent issuances of equity
securities by us could also affect the percentage of distributions that will
constitute taxable income. 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
and could materially affect the value of the common units.

S-64

UNDERWRITING

Under the underwriting agreement, which is filed as an exhibit to the
registration statement of which this prospectus supplement and the accompanying
prospectus form a part, each of the underwriters named below has severally
agreed to purchase from us the respective number of common units opposite its
name below:

NUMBER OF
UNDERWRITERS COMMON UNITS
------------ ------------

Lehman Brothers Inc......................................... 2,940,000
Goldman, Sachs & Co. ....................................... 1,715,000
UBS Warburg LLC............................................. 1,715,000
RBC Dain Rauscher Inc....................................... 980,000
Wachovia Securities, Inc.................................... 980,000
McDonald Investments Inc. .................................. 490,000
Raymond James & Associates Inc. ............................ 490,000
Sanders Morris Harris Inc. ................................. 490,000
---------
Total.................................................. 9,800,000
=========

Dan L. Duncan, the Chairman of our general partner, through EPC Partners
II, Inc., an entity controlled by him, and O.S. Andras, the President and Chief
Executive Officer of our general partner, will purchase 1,800,000 common units
in this offering directly from the underwriters at a price equal to the public
offering price.

At the request of Enterprise Products Partners, the underwriters will sell
9,200 common units under a directed unit program to senior management. These
shares will be sold at the public offering price, but the underwriters will
receive no underwriting discount or commission on the sale of common units under
the directed unit program.

The underwriting agreement provides that the underwriters are obligated to
purchase, subject to certain conditions, all of the common units in the offering
if any are purchased, other than those covered by the over-allotment option
described below. The conditions contained in the underwriting agreement include
the requirements that:

- all the representations and warranties made by us to the underwriters are
true;

- there has been no material adverse change in our condition or in the
financial markets; and

- we deliver to the underwriters customary closing documents.

We have granted to the underwriters a 30-day option after the date of the
underwriting agreement to purchase, in whole or in part, up to an aggregate of
1,470,000 additional common units at the public offering price less underwriting
discounts and commissions. Such option may be exercised to cover
over-allotments, if any, made in connection with the offering. To the extent
that the option is exercised, each underwriter will be obligated, subject to
certain conditions, to purchase its pro rata portion of these additional common
units based on the underwriter's percentage underwriting commitment in the
offering as indicated on the preceding table.

We have been advised by the underwriters that the underwriters propose to
offer the common units directly to the public at the price to the public set
forth on the cover page of this prospectus supplement and to selected dealers
(who may include the underwriters) at the offering price less a selling
concession not in excess of $0.48 per unit. The underwriters may allow, and the
selected dealers may reallow, a discount from the concession not in excess of
$0.10 per unit to other dealers. After the offering, the underwriters may change
the offering price and other selling terms.

S-65

The following table shows the underwriting discounts and commissions we
will pay to the underwriters. These amounts are shown assuming both no exercise
and full exercise of the underwriters' option to purchase additional common
units. The underwriting fee is the difference between the initial offering price
and the amount the underwriters pay to us to purchase the common units from us.

NO EXERCISE FULL EXERCISE
----------- -------------

Per unit.................................................... $ 0.81 $ 0.81
Total.................................................. $6,472,548 $7,663,248

We estimate that the total expenses of the offering, excluding underwriting
discounts and commissions, will be approximately $1.0 million.

In connection with this offering, the underwriters may engage in
stabilizing transactions, over-allotment transactions, syndicate covering
transactions and penalty bids for the purpose of pegging, fixing or maintaining
the price of the common units in accordance with Regulation M under the Exchange
Act.

- Stabilizing transactions permit bids to purchase the underlying security
so long as the stabilizing bids do not exceed a specified maximum.

- Over-allotment transactions involve sales by the underwriters of the
common units in excess of the number of common units the underwriters are
obligated to purchase, which creates a syndicate short position. The
short position may be either a covered short position or a naked short
position. In a covered short position, the number of common units
over-allotted by the underwriters is not greater than the number of
common units they may purchase in the over-allotment option. In a naked
short position, the number of common units involved is greater than the
number of common units in the over-allotment option. The underwriters may
close out any short position by either exercising their over-allotment
option and/or purchasing common units in the open market.

- Syndicate covering transactions involve purchases of the common units in
the open market after the distribution has been completed in order to
cover syndicate short positions. In determining the source of the common
units to close out the short position, the underwriters will consider,
among other things, the price of common units available for purchase in
the open market as compared to the price at which they may purchase
common units through the over-allotment option. If the underwriters sell
more common units than could be covered by the over-allotment option, a
naked short position, the position can only be closed out by buying
common units in the open market. A naked short position is more likely to
be created if the underwriters are concerned that there could be downward
pressure on the price of the common units in the open market after
pricing that could adversely affect investors who purchase in the
offering.

- Penalty bids permit the underwriters to reclaim a selling concession from
a syndicate member when the common units originally sold by the syndicate
member are purchased in a stabilizing or syndicate covering transaction
to cover syndicate short positions.

These stabilizing transactions, syndicate covering transactions and penalty
bids may have the effect of raising or maintaining the market price of our
common units or preventing or retarding a decline in the market price of the
common units. As a result, the price of the common units may be higher than the
price that might otherwise exist in the open market. These transactions may be
effected on the NYSE or otherwise and, if commenced, may be discontinued at any
time. On the date of this prospectus, Lehman Brothers Inc. purchased 29,900
common units on behalf of the underwriters at a price of $18.99 per common unit.

Neither we nor any of 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 any of the underwriters make any representation that the underwriters
will engage in these stabilizing transactions or that any transaction, once
commenced, will not be discontinued without notice.

S-66

We, our affiliates that own common units and the directors and executive
officers of our general partner have agreed that we and they will not, subject
to limited exceptions, directly or indirectly, sell, offer, pledge or otherwise
dispose of any common units or any securities convertible into or exchangeable
or exercisable for common units or enter into any derivative transaction with
similar effect as a sale of common units for a period of 90 days after the date
of this prospectus supplement without the prior written consent of Lehman
Brothers Inc. The restrictions described in this paragraph do not apply to the
sale of common units to the underwriters.

Lehman Brothers Inc., in its discretion, may release the common units
subject to lock-up agreements in whole or in part at any time with or without
notice. When determining whether or not to release common units from lock-up
agreements, Lehman Brothers Inc. will consider, among other factors, the
unitholders' reasons for requesting the release, the number of common units for
which the release is being requested and market conditions at the time.

The common units are listed on the NYSE under the symbol "EPD."

We, our general partner and our operating partnership have agreed to
indemnify the underwriters against certain liabilities, including liabilities
under the Securities Act of 1933, or to contribute to payments that may be
required to be made in respect of these liabilities.

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

Affiliates of Lehman Brothers Inc., RBC Dain Rauscher Inc. and Wachovia
Securities, Inc. are lenders to us under our $1.2 billion senior unsecured
364-day term loan. Each of these lenders was granted a right of first refusal to
provide, arrange, place or underwrite the financings required to repay this term
loan. Each of these lenders will receive a share of the partial repayment by us
of amounts outstanding under this term loan from the net proceeds of this
offering.

The compensation received by the underwriters in connection with this
offering, including the right of first refusal granted to the lenders under the
term loan, which is assigned a value of 1% of the gross proceeds of this
offering, does not exceed 8% of the gross proceeds of this offering.

Because the NASD views the common units offered hereby as interests in a
direct participation program, the offering is being made in compliance with Rule
2810 of the NASD Conduct Rules. Investor suitability with respect to the common
units should be judged similarly to the suitability with respect to other
securities that are listed for trading on a national securities exchange.

No sales to accounts over which the underwriters have discretionary
authority may be made without the prior written approval of the customer.

A prospectus in electronic format may be made available on the Internet
sites or through other online services maintained by one or more of the
underwriters and/or selling group members participating in this offering, or by
their affiliates, in those cases, prospective investors may view offering terms
online and, depending upon the particular underwriter or selling group member
prospective investors may be allowed to place orders online. The underwriters
may agree with us to allocate a specific number of shares for sale to online
brokerage account holders. Any such allocation for online distributions will be
made by the representatives on the same basis as other allocations.

Other than the prospectus in electronic format, the information on any
underwriter's or selling group member's web site and any information contained
in any other web site maintained by an underwriter or selling group member is
not part of the prospectus or the registration statement of which this
prospectus supplement forms a part, has not been approved and/or endorsed by us
or any underwriter or selling group member in its capacity as underwriter or
selling group member and should not be relied upon by investors.

S-67

INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE

The Commission allows us to "incorporate by reference" into this prospectus
supplement and the accompanying prospectus the information we file with it,
which means that we can disclose important information to you by referring you
to those documents. The information incorporated by reference is considered to
be part of this prospectus supplement and the accompanying prospectus, and later
information that we file with the Commission will automatically update and
supersede this information. We incorporate by reference the documents listed
below filed by us and any future filings made by us with the Commission under
section 13(a), 13(c), 14 or 15(d) of the Securities Exchange Act of 1934 until
our offering is completed:

- Our Annual Report on Form 10-K for the fiscal year ended December 31,
2001;

- Our Quarterly Reports on Form 10-Q for the fiscal quarters ended March
31, 2002 and June 30, 2002;

- Our Current Report on Form 8-K filed with the Commission on August 12,
2002, as amended by our Current Report on Form 8-K/A (Amendment No. 1)
filed with the Commission on September 26, 2002 (excluding Item 9
information);

- Our Current Reports on Form 8-K filed with the Commission on September
27, 2002 and October 2, 2002; and

- The descriptions of our common units contained in the Registration
Statement on Form 8-A, initially filed with the Commission on July 21,
1998, and any subsequent amendment thereto filed for the purposes of
updating such description.

LEGAL MATTERS

Certain legal matters with respect to the common units will be passed upon
for us by Vinson & Elkins L.L.P., Houston, Texas. Certain legal matters with
respect to the common units are being passed upon for the underwriters by Baker
Botts L.L.P., Houston, Texas. Baker Botts L.L.P. performs legal services for us
and our affiliates from time to time.

EXPERTS

The (i) consolidated financial statements and the related consolidated
financial statement schedule of Enterprise Products Partners L.P. and
subsidiaries as of December 31, 2001 and 2000 and for each of the three years in
the period ended December 31, 2001 included and incorporated by reference in
this prospectus supplement, (ii) and the balance sheet of Enterprise Products
GP, LLC as of December 31, 2001, incorporated by reference in this prospectus
supplement, have been audited by Deloitte & Touche LLP, independent auditors, as
stated in their reports, which are included and incorporated by reference herein
(which reports express unqualified opinions and the report for Enterprise
Products Partners L.P. includes an explanatory paragraph referring to a change
in method of accounting for derivative instruments in 2001 as discussed in Note
13 to Enterprise Products Partners L.P.'s consolidated financial statements),
and have been so included and incorporated in reliance upon the reports of such
firm given upon their authority as experts in accounting and auditing.

The financial statements of Mid-America Pipeline System and Seminole
Pipeline Company as of December 31, 2000 and 2001 and for each of the three
years in the period ended December 31, 2001 appearing in Enterprise Products
Partners L.P. and Enterprise Products Operating L.P.'s Current Report on Form
8-K/A (Amendment No. 1) filed September 26, 2002, have been audited by Ernst &
Young LLP, independent auditors, as set forth in their reports thereon included
therein and incorporated by reference in the Registration Statement and related
Prospectus and also included elsewhere in this Prospectus Supplement. These
financial statements have been included in this Prospectus Supplement and
incorporated by reference in the Registration Statement and related Prospectus
in reliance upon such reports given on the authority of such firm as experts in
accounting and auditing.

S-68

GLOSSARY

The following abbreviations, acronyms or terms used in this prospectus
supplement are defined below:

Acadian Gas Acadian Gas, LLC and subsidiaries, acquired from Shell in
April 2001
BBtu Billion British thermal units, a measure of heating value
Bcf Billion cubic feet
Bcf/d Billion cubic feet per day
BEF Belvieu Environmental Fuels, an equity investment of EPOLP
Belle Rose Belle Rose NGL Pipeline LLC, an equity investment of EPOLP
BP BP PLC and affiliates
BPD Barrels per day
BRF Baton Rouge Fractionators LLC, an equity investment of EPOLP
BRPC Baton Rouge Propylene Concentrator, LLC, an equity
investment of EPOLP
Btu British thermal units, a measure of heating value
Burlington Resources Burlington Resources Inc. and its affiliates
ChevronTexaco ChevronTexaco and its affiliates
CPG Cents per gallon
ConocoPhillips ConocoPhillips Petroleum Company and affiliates
Devon Energy Devon Energy Corporation, its subsidiaries and affiliates
Diamond-Koch Refers to affiliates of Valero Energy Corporation and Koch
Industries, Inc.
DIB Deisobutanizer
Dixie Dixie Pipeline Company, an equity investment of EPOLP
Dow Dow Chemical Company and its affiliates
Duke Duke Energy Corporation and its affiliates
Dynegy Dynegy Inc. and its affiliates
El Paso El Paso Corporation, its subsidiaries and affiliates
Energy Policy Act Energy Policy Act of 1992
E-Oaktree E-Oaktree, LLC
EPCO Enterprise Products Company, an affiliate of our partnership
EPIK EPIK Terminalling L.P. and EPIK Gas Liquids, LLC,
collectively, an equity investment of EPOLP
EPOLP Enterprise Products Operating L.P., our operating
partnership
Equistar A joint venture of Lyondell Chemical Company, Millennium
Chemicals, Inc. and Occidental Petroleum Corporation
Exxon Mobil Exxon Mobil Corporation and its affiliates
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
GAAP United States Generally Accepted Accounting Principles
HSC Denotes our Houston Ship Channel pipeline system
Huntsman Huntsman Corporation and its affiliates
Koch Koch Industries and its affiliates
LIBOR London interbank offered rate
Lyondell Lyondell Chemical Company and its affiliates
Manta Ray A Gulf of Mexico Offshore Louisiana natural gas pipeline
system owned by Manta Ray offshore Gathering Company, LLC
Mapletree Mapletree, LLC
Marathon Marathon Oil Corporation and its affiliates
MBA acquisition Refers to the acquisition of Mont Belvieu Associates'
remaining interest in the Mont Belvieu NGL fractionation
facility in 1999
MBFC Mississippi Business Finance Corporation

S-69

MBPD Thousand barrels per day
MLP Denotes our partnership
MBbls Thousands of barrels
MMBbls Millions of barrels
MMBtu/d Million British thermal units per day, a measure of heating
value
MMBtus Million British thermal units, a measure of heating value
MMcf Million cubic feet
MMcf/d Million cubic feet per day
Mont Belvieu Mont Belvieu, Texas
Mont Belvieu I Our 54.6% interest in a polymer-grade propylene
fractionation facility located in Mont Belvieu, the
remaining 45.4% interest in which we lease from an affiliate
of Shell
Mont Belvieu II Our 100% interest in a polymer-grade propylene fractionation
facility located in Mont Belvieu
Mont Belvieu III 66.7% interest in a polymergrade propylene fractionation
facility located in Mont Belvieu
MTBE Methyl tertiary butyl ether
Nautilus A Gulf of Mexico offshore Louisiana natural gas pipeline
system owned by Nautilus Pipeline Company, LLC
Nemo Nemo Gathering Company, LLC, an equity investment of EPOLP
Neptune Neptune Pipeline Company LLC
NGL or NGLs Natural gas liquid(s)
Norco An NGL fractionation facility located at Norco, Louisiana
NYSE New York Stock Exchange
Operating Partnership EPOLP and its subsidiaries
OTC Olefins Terminal Corporation
Promix K/D/S/ Promix LLC, an equity investment of EPOLP
SEC U.S. Securities and Exchange Commission
SFAS Statement of Financial Accounting Standards issued by the
FASB
Senior Notes A Our 8.25% fixed-rate Senior Notes due March 15, 2005
Senior Notes B Our 7.50% fixed-rate Senior Notes due February 1, 2011
Shell Shell Oil Company, its subsidiaries and affiliates
Starfish Starfish Pipeline Company, LLC, an equity investment of
EPOLP
Sunoco Sunoco Inc. and its affiliates
TCEQ Texas Commission on Environmental Quality
TEPPCO Texas Eastern Pipeline Partners Company
TNGL acquisition Refers to the 1999 acquisition of Tejas Natural Gas Liquids,
LLC, formerly an affiliate of Shell
Tri-States Tri-States NGL Pipeline LLC, an equity investment of EPOLP
Trust EPOLP 1999 Revocable Grantor Trust, a subsidiary of EPOLP
Trust Units Common units owned by the Trust
VESCO Venice Energy Services Company, LLC, a cost method
investment of EPOLP
Williams The Williams Companies, Inc.
Wilprise Wilprise Pipeline Company, LLC, an equity investment of
EPOLP

S-70

INDEX TO FINANCIAL STATEMENTS

Enterprise Products Partners L.P. Unaudited Pro Forma
Consolidated Financial Statements:
Introduction.............................................. F-2
Pro Forma Statement of Consolidated Operations for the six
months ended June 30, 2002............................. F-3
Pro Forma Statement of Consolidated Operations for the
year ended December 31, 2001........................... F-4
Pro Forma Consolidated Balance Sheet at June 30, 2002..... F-5
Notes to Unaudited Pro Forma Consolidated Financial
Statements............................................. F-6
Enterprise Products Partners L.P. Audited Annual Financial
Statements:
Independent Auditors' Report.............................. F-9
Statements of Consolidated Operations for the years ended
December 31, 2001, 2000 and 1999....................... F-10
Consolidated Balance Sheets as of December 31, 2001 and
2000................................................... F-11
Statements of Consolidated Cash Flows for the years ended
December 31, 2001, 2000 and 1999....................... F-12
Statements of Consolidated Partners' Equity for the years
ended December 31, 1999, 2000 and 2001................. F-13
Notes to Consolidated Financial Statements................ F-14
Enterprise Products Partners L.P. Unaudited Quarterly
Financial Statements
Consolidated Balance Sheets as of June 30, 2002 and
December 31, 2001...................................... F-49
Statements of Consolidated Operations for the three months
ended June 30, 2002 and 2001 and the six months ended
June 30, 2002 and 2001................................. F-50
Statements of Consolidated Cash Flows for the six months
ended June 30, 2002 and 2001........................... F-51
Notes to Unaudited Consolidated Financial Statements...... F-52
Mid-America Pipeline System Financial Statements:
Report of Independent Auditors............................ F-76
Combined Statements of Operations and Owner Equity for the
years ended December 31, 1999, 2000 and 2001 and the
six months ended June 30, 2001 and 2002................ F-77
Combined Balance Sheets as of December 31, 2000 and 2001
and the six months ended June 30, 2002................. F-78
Combined Statements of Cash Flows for the years ended
December 31, 1999, 2000 and 2001 and the six months
ended June 30, 2001 and 2002........................... F-79
Notes to Combined Financial Statements.................... F-80
Seminole Pipeline Company Financial Statements:
Report of Independent Auditors............................ F-86
Statements of Operations for the years ended December 31,
1999, 2000 and 2001 and the six months ended June 30,
2001 and 2002.......................................... F-87
Balance Sheets as of December 31, 2000 and 2001 and the
six months ended June 30, 2002......................... F-88
Statement of Stockholders' Equity for the years ended
December 31, 1999, 2000 and 2001 and for the six months
ended June 30, 2002.................................... F-89
Statements of Cash Flows for the years ended December 31,
1999, 2000 and 2001 and the six months ended June 30,
2001 and 2002.......................................... F-90
Notes to Financial Statements............................. F-91

F-1

ENTERPRISE PRODUCTS PARTNERS L.P.
UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

INTRODUCTION

On July 31, 2002, we acquired 98% of the ownership interests in two
affiliates of The Williams Companies Inc. ("Williams"): Mapletree, LLC and
E-Oaktree, LLC. Mapletree, LLC owns 100% of Mid-America Pipeline Company, LLC
("Mid-America") and certain propane terminals and storage facilities. E-Oaktree,
LLC owns 80% of Seminole Pipeline Company ("Seminole"). The pro forma financial
statements are primarily based upon the combined historical financial position
and results of operations of Enterprise Products Partners L.P., Mid-America and
Seminole. Unless the context requires otherwise, references to "we", "us", "our"
or the "Company" are intended to mean the consolidated business and operations
of Enterprise Products Partners L.P., which includes Enterprise Products
Operating L.P. and its subsidiaries.

The unaudited pro forma Statements of Consolidated Operations have been
prepared as if the acquisitions had occurred on January 1 of the respective
periods presented, and the pro forma consolidated balance sheet has been
prepared as if the acquisitions occurred on June 30, 2002. The combined purchase
price of these acquisitions was approximately $1.2 billion and was primarily
funded by an unsecured 364-day term loan of the same amount (the "Term Loan").

The unaudited pro forma financial statements should be read in conjunction
with and are qualified in their entirety by reference to the notes accompanying
such pro forma consolidated financial statements and with the historical
financial statements and related notes of our Company, Mid-America, and Seminole
included elsewhere or incorporated by reference in this prospectus.

The unaudited pro forma information is not necessarily indicative of the
financial results that would have occurred if the acquisitions described herein
had taken place on the dates indicated or we had issued equity and borrowed
funds on the dates indicated, nor is it indicative of our future consolidated
financial results.

F-2

ENTERPRISE PRODUCTS PARTNERS L.P.

PRO FORMA STATEMENT OF CONSOLIDATED OPERATIONS
FOR THE SIX MONTHS ENDED JUNE 30, 2002
(DOLLARS IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)
(UNAUDITED)

ENTERPRISE MID-AMERICA SEMINOLE ENTERPRISE
HISTORICAL HISTORICAL HISTORICAL OTHER ADJUSTMENTS PRO FORMA
---------- ----------- ---------- ------- ----------- ----------

REVENUES
Revenues from consolidated operations..... $1,448,311 $109,865 $ 34,856 $17,434 $ (2,252)(f) $1,608,214
Equity income in unconsolidated
affiliates.............................. 16,295 -- -- -- 16,295
---------- -------- -------- ------- -------- ----------
Total............................. 1,464,606 109,865 34,856 17,434 (2,252) 1,624,509
---------- -------- -------- ------- -------- ----------
COST AND EXPENSES
Operating costs and expenses.............. 1,410,044 45,111 17,315 16,231 1,325(b) 1,487,900
126(c)
(2,252)(f)
Selling, general and administrative....... 15,702 15,130 796 260 31,888
---------- -------- -------- ------- -------- ----------
Total............................. 1,425,746 60,241 18,111 16,491 (801) 1,519,788
---------- -------- -------- ------- -------- ----------
OPERATING INCOME.......................... 38,860 49,624 16,745 943 (1,451) 104,721
OTHER INCOME (EXPENSE)
Interest expense.......................... (37,545) (4,432) (2,006) -- 4,148(b) (67,195)
(26,709)(a)
(651)(c)
Interest income from unconsolidated
affiliates.............................. 92 -- -- -- 92
Dividend income from unconsolidated
affiliates.............................. 2,196 -- -- -- 2,196
Interest income -- other.................. 1,575 -- -- -- 1,575
Other, net................................ (31) (748) (7) -- (786)
---------- -------- -------- ------- -------- ----------
Other income (expense)............ (33,713) (5,180) (2,013) -- (23,212) (64,118)
---------- -------- -------- ------- -------- ----------
INCOME BEFORE MINORITY INTEREST AND
PROVISION FOR INCOME TAXES.............. 5,147 44,444 14,732 943 (24,663) 40,603
PROVISION FOR INCOME TAXES................ -- (16,604) (5,347) -- 16,582 (b) (5,369)
---------- -------- -------- ------- -------- ----------
INCOME BEFORE MINORITY INTEREST........... 5,147 27,840 9,385 943 (8,081) 35,234
MINORITY INTEREST......................... (30) -- -- -- (3,008)(d) (3,038)
---------- -------- -------- ------- -------- ----------
NET INCOME................................ $ 5,117 $ 27,840 $ 9,385 $ 943 $(11,089) $ 32,196
========== ======== ======== ======= ======== ==========
ALLOCATION OF NET INCOME TO:
Limited partners.................. $ 1,223 $ 26,811(e) $ 28,034
========== ======== ==========
General partner................... $ 3,894 $ 268(e) $ 4,162
========== ======== ==========
BASIC EARNINGS PER LIMITED PARTNER UNIT:
Number of Units used in computing Basic
Earnings per Unit..................... 145,404 145,404
========== ==========
Income before minority interest......... $ 0.01 $ 0.21
========== ==========
Net income per Unit..................... $ 0.01 $ 0.19
========== ==========
DILUTED EARNINGS PER LIMITED PARTNER UNIT:
Number of Units used in computing
Diluted Earnings per Unit............. 174,404 174,404
========== ==========
Income before minority interest......... $ 0.01 $ 0.18
========== ==========
Net income per Unit..................... $ 0.01 $ 0.16
========== ==========

ADJUSTMENTS ADJUSTED
DUE TO EQUITY ENTERPRISE
OFFERING PRO FORMA
------------- ----------

REVENUES
Revenues from consolidated operations..... $1,608,214
Equity income in unconsolidated
affiliates.............................. 16,295
----------
Total............................. 1,624,509
----------
COST AND EXPENSES
Operating costs and expenses.............. 1,487,900
Selling, general and administrative....... 31,888
----------
Total............................. 1,519,788
----------
OPERATING INCOME.......................... 104,721
OTHER INCOME (EXPENSE)
Interest expense.......................... (64,301)
2,894(a)
Interest income from unconsolidated
affiliates.............................. 92
Dividend income from unconsolidated
affiliates.............................. 2,196
Interest income -- other.................. 1,575
Other, net................................ (786)
------- ----------
Other income (expense)............ 2,894 (61,224)
------- ----------
INCOME BEFORE MINORITY INTEREST AND
PROVISION FOR INCOME TAXES.............. 2,894 43,497
PROVISION FOR INCOME TAXES................ (5,369)
------- ----------
INCOME BEFORE MINORITY INTEREST........... 2,894 38,128
MINORITY INTEREST......................... (29)(d) (3,067)
------- ----------
NET INCOME................................ $ 2,865 $ 35,061
======= ==========
ALLOCATION OF NET INCOME TO:
Limited partners.................. $ 2,836 (e) $ 30,870
======= ==========
General partner................... $ 29 (e) $ 4,191
======= ==========
BASIC EARNINGS PER LIMITED PARTNER UNIT:
Number of Units used in computing Basic
Earnings per Unit..................... 9,800(a) 155,204
======= ==========
Income before minority interest......... $ 0.22
==========
Net income per Unit..................... $ 0.20
==========
DILUTED EARNINGS PER LIMITED PARTNER UNIT:
Number of Units used in computing
Diluted Earnings per Unit............. 9,800(a) 184,204
======= ==========
Income before minority interest......... $ 0.18
==========
Net income per Unit..................... $ 0.17
==========

The accompanying notes are an integral part of these unaudited pro forma
condensed financial statements.
F-3

ENTERPRISE PRODUCTS PARTNERS L.P.

PRO FORMA STATEMENT OF CONSOLIDATED OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 2001
(DOLLARS IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)
(UNAUDITED)

ENTERPRISE MID-AMERICA SEMINOLE ENTERPRISE
HISTORICAL HISTORICAL HISTORICAL OTHER ADJUSTMENTS PRO FORMA
---------- ----------- ---------- -------- ----------- ----------

REVENUES
Revenues from consolidated operations.... $3,154,369 $214,518 $ 65,800 $522,669 $ (4,413)(f) $3,952,943
Equity income in unconsolidated
affiliates............................. 25,358 -- -- (1,879) 23,479
---------- -------- -------- -------- -------- ----------
Total............................ 3,179,727 214,518 65,800 520,790 (4,413) 3,976,422
---------- -------- -------- -------- -------- ----------
COST AND EXPENSES
Operating costs and expenses............. 2,861,743 125,349 33,539 507,869 2,230(b) 3,528,057
1,740(c)
(4,413)(f)
Selling, general and administrative...... 30,296 28,364 1,535 4,477 64,672
---------- -------- -------- -------- -------- ----------
Total............................ 2,892,039 153,713 35,074 512,346 (443) 3,592,729
---------- -------- -------- -------- -------- ----------
OPERATING INCOME......................... 287,688 60,805 30,726 8,444 (3,970) 383,693
OTHER INCOME (EXPENSE)
Interest expense......................... (52,456) (12,700) (5,160) -- 8,400(b) (124,328)
(53,418)(a)
(8,994)(c)
Interest income from unconsolidated
affiliates............................. 31 -- -- 4 35
Dividend income from unconsolidated
affiliates............................. 3,462 -- -- -- 3,462
Interest income -- other................. 7,029 -- -- -- 7,029
Other, net............................... (1,104) (1,035) 662 (15) (1,492)
---------- -------- -------- -------- -------- ----------
Other income (expense)........... (43,038) (13,735) (4,498) (11) (54,012) (115,294)
---------- -------- -------- -------- -------- ----------
INCOME BEFORE MINORITY INTEREST AND
PROVISION FOR INCOME TAXES............. 244,650 47,070 26,228 8,433 (57,982) 268,399
PROVISION FOR INCOME TAXES............... -- (17,445) (9,470) -- 17,402(b) (9,513)
---------- -------- -------- -------- -------- ----------
INCOME BEFORE MINORITY INTEREST.......... 244,650 29,625 16,758 8,433 (40,580) 258,886
MINORITY INTEREST........................ (2,472) -- -- -- (4,746)(d) (7,218)
---------- -------- -------- -------- -------- ----------
NET INCOME............................... $ 242,178 $ 29,625 $ 16,758 $ 8,433 $(45,326) $ 251,668
========== ======== ======== ======== ======== ==========
ALLOCATION OF NET INCOME TO:
Limited partners................. $ 236,570 $ 9,403(e) $ 245,973
========== ======== ==========
General partner.................. $ 5,608 $ 87(e) $ 5,695
========== ======== ==========
BASIC EARNINGS PER LIMITED PARTNER UNIT:
Number of Units used in computing Basic
Earnings per Unit.................... 139,452 139,452
========== ==========
Income before minority interest........ $ 1.72 $ 1.82
========== ==========
Net income per Unit.................... $ 1.70 $ 1.76
========== ==========
DILUTED EARNINGS PER LIMITED PARTNER
UNIT:
Number of Units used in computing
Diluted Earnings per Unit............ 170,786 170,786
========== ==========
Income before minority interest........ $ 1.40 $ 1.48
========== ==========
Net income per Unit.................... $ 1.39 $ 1.44
========== ==========

ADJUSTMENTS ADJUSTED
DUE TO EQUITY ENTERPRISE
OFFERING PRO FORMA
------------- ----------

REVENUES
Revenues from consolidated operations.... $3,952,943
Equity income in unconsolidated
affiliates............................. 23,479
----------
Total............................ 3,976,422
----------
COST AND EXPENSES
Operating costs and expenses............. 3,528,057
Selling, general and administrative...... 64,672
----------
Total............................ 3,592,729
----------
OPERATING INCOME......................... 383,693
OTHER INCOME (EXPENSE)
Interest expense......................... (118,541)
5,787(a)
Interest income from unconsolidated
affiliates............................. 35
Dividend income from unconsolidated
affiliates............................. 3,462
Interest income -- other................. 7,029
Other, net............................... (1,492)
------- ----------
Other income (expense)........... 5,787 (109,507)
------- ----------
INCOME BEFORE MINORITY INTEREST AND
PROVISION FOR INCOME TAXES............. 5,787 274,186
PROVISION FOR INCOME TAXES............... (9,513)
------- ----------
INCOME BEFORE MINORITY INTEREST.......... 5,787 264,673
MINORITY INTEREST........................ (58)(d) (7,276)
------- ----------
NET INCOME............................... $ 5,729 $ 257,397
======= ==========
ALLOCATION OF NET INCOME TO:
Limited partners................. $ 5,672(e) $ 251,645
======= ==========
General partner.................. $ 57(e) $ 5,752
======= ==========
BASIC EARNINGS PER LIMITED PARTNER UNIT:
Number of Units used in computing Basic
Earnings per Unit.................... 9,800(a) 149,252
======= ==========
Income before minority interest........ $ 1.73
==========
Net income per Unit.................... $ 1.69
==========
DILUTED EARNINGS PER LIMITED PARTNER
UNIT:
Number of Units used in computing
Diluted Earnings per Unit............ 9,800(a) 180,586
======= ==========
Income before minority interest........ $ 1.43
==========
Net income per Unit.................... $ 1.39
==========

The accompanying notes are an integral part of these unaudited pro forma
condensed financial statements.

F-4

ENTERPRISE PRODUCTS PARTNERS L.P.

PRO FORMA CONSOLIDATED BALANCE SHEET AT JUNE 30, 2002
(DOLLARS IN THOUSANDS, UNAUDITED)

ADJUSTMENTS
ENTERPRISE MID-AMERICA SEMINOLE DUE TO EQUITY ADJUSTED
HISTORICAL HISTORICAL HISTORICAL ADJUSTMENTS PRO FORMA OFFERING PRO FORMA
---------- ----------- ---------- ----------- ---------- ------------- ----------

ASSETS
CURRENT ASSETS
Cash and cash equivalents...... $ 7,929 $ -- $ 11,160 $ 1,195,000(a) $ 19,089 $ 178,629(a) $ 19,089
(1,195,000)(a) 3,645(a)
(182,274)(a)
Accounts receivable, net....... 284,021 1,383 9,199 294,603 294,603
Accounts
receivable -- affiliates..... 1,740 20,506 7,791 (16,333)(f) 13,704 13,704
Income taxes -- affiliates..... 11,855 1,637 (13,492)(b) -- --
Inventories.................... 153,280 10,210 -- 163,490 163,490
Prepaid and other current
assets....................... 34,089 868 122 15,000(a) 50,079 50,079
---------- -------- -------- ----------- ---------- --------- ----------
Total current assets..... 481,059 44,822 29,909 (14,825) 540,965 -- 540,965
---------- -------- -------- ----------- ---------- --------- ----------
PROPERTY, PLANT AND EQUIPMENT,
NET............................ 1,570,571 633,937 249,390 426,766(b) 2,880,664 2,880,664
INVESTMENTS IN AND ADVANCES TO
UNCONSOLIDATED AFFILIATES...... 403,070 -- -- 403,070 403,070
INTANGIBLE ASSETS................ 249,222 -- -- 249,222 249,222
GOODWILL......................... 81,543 -- -- 81,543 81,543
OTHER ASSETS..................... 6,911 2,844 440 10,195 10,195
---------- -------- -------- ----------- ---------- --------- ----------
TOTAL.................... $2,792,376 $681,603 $279,739 $ 411,941 $4,165,659 $ -- $4,165,659
========== ======== ======== =========== ========== ========= ==========
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Current maturities of debt..... $ -- $ -- $ 15,000 $ 1,200,000(a) $1,215,000 $(178,629)(a) $1,036,371
Accounts payable -- trade...... 70,716 5,178 2,389 78,283 78,283
Accounts
payable -- affiliates........ 21,233 26,726 17,948 (16,333)(f) 49,574 49,574
Accrued gas payables........... 303,983 -- -- 303,983 303,983
Accrued expenses............... 12,961 7,777 2,665 23,403 23,403
Accrued interest............... 24,676 2,100 668 (2,100)(b) 25,344 25,344
Other current liabilities...... 70,672 368 1,185 72,225 72,225
---------- -------- -------- ----------- ---------- --------- ----------
Total current
liabilities............ 504,241 42,149 39,855 1,181,567 1,767,812 (178,629) 1,589,183
---------- -------- -------- ----------- ---------- --------- ----------
LONG-TERM DEBT................... 1,223,552 90,000 45,000 10,000(a) 1,278,552 (3,645) 1,274,907
(90,000)(b)
DEFERRED INCOME TAXES............ -- 122,611 59,116 (181,727)(b) -- --
OTHER LONG-TERM LIABILITIES...... 7,919 384 -- 8,303 8,303
MINORITY INTEREST................ 10,818 -- -- 54,328(b) 65,146 1,841(a) 66,987
COMMITMENTS AND CONTINGENCIES
OWNERS' EQUITY................... -- 426,459 135,768 (562,227)(b) -- --
PARTNERS' EQUITY
Limited partners............... 1,051,956 1,051,956 178,629(a) 1,230,585
General partner................ 10,626 10,626 1,804(a) 12,430
Treasury Units................. (16,736) (16,736) (16,736)
---------- -------- -------- ----------- ---------- --------- ----------
Total Equity............. 1,045,846 426,459 135,768 (562,227) 1,045,846 180,433 1,226,279
---------- -------- -------- ----------- ---------- --------- ----------
TOTAL.................... $2,792,376 $681,603 $279,739 $ 411,941 $4,165,659 $ -- $4,165,659
========== ======== ======== =========== ========== ========= ==========

The accompanying notes are an integral part of these unaudited pro forma
condensed financial statements.
F-5

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001 AND JUNE 30, 2002

These unaudited pro forma consolidated financial statements and underlying
pro forma adjustments are based upon currently available information and certain
estimates and assumptions made by us; therefore, actual results will differ from
pro forma results. However, we believe the assumptions provide a reasonable
basis for presenting the significant effects of the acquisitions noted herein
and the offering of common units. We believe the pro forma adjustments give
appropriate effect to those assumptions and are properly applied in the pro
forma financial information.

(a) This group of pro forma adjustments reflects the following:

- The net cash proceeds of $1.195 billion needed to acquire our interests
in Mid-America and Seminole consisting of a $1.2 billion borrowing under
the Term Loan, a $10 million borrowing under our revolving credit
facilities, less $15 million in prepaid loan costs.

- The sale of 9,800,000 Common Units at an offering price of $18.99 per
unit. The estimated net proceeds from this offering are $178.6 million
after deducting underwriting discounts and commissions of approximately
$6.5 million and offering expenses of approximately $1.0 million. The
underwriters will receive no discount or commission on the sale of up to
1,809,200 common units to our senior management and their affiliates. In
connection with this offering, our general partner will make a net
capital contribution of $3.6 million to the Company to maintain its
approximate 2% combined general partner interest in the Company. The
proceeds of $178.6 million from the equity offering will be used to
partially repay the Term Loan, and the proceeds of $3.6 million from the
general partner's capital contribution will be used to repay debt.

- An increase in variable rate-based interest expense due to the increase
in borrowings. Interest expense also reflects amortization of the $15
million in prepaid loan costs associated with the Term Loan (over its
respective one-year life). The combined pro forma increase in interest
expense due to these borrowings and amortization was $47.6 million for
the year ended December 31, 2001 and $23.8 million for the six months
ended June 30, 2002. If the underlying variable interest rate used in
such pro forma calculations were to increase by 0.125%, pro forma
interest expense would increase by $1.3 million for the year ended
December 31, 2001 and by $0.6 million for the six months ended June 30,
2002.

In preparing the pro forma statements of consolidated operations, we have
assumed that the net $1.0 billion principal balance of the Term Loan (e.g., the
principal balance remaining after application of the offering-related proceeds
noted above) is outstanding during the entire period covered by such statements.
Our future plans for permanent financing of the Mid-America and Seminole
acquisitions include the issuance of additional equity and debt in amounts which
are consistent with our objective of maintaining financial flexibility and an
investment grade balance sheet.

To the extent that the proceeds of any future equity offering are again
used to reduce the principal amount outstanding under the Term Loan, our
interest expense will be reduced. To the extent that the Term Loan is refinanced
with debt, our interest expense will generally be affected by any difference in
interest rates on the Term Loan and the new debt and by any fees associated with
the new debt.

F-6

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED
FINANCIAL STATEMENTS -- (CONTINUED)
DECEMBER 31, 2001 AND JUNE 30, 2002

(b) This group of pro forma adjustments primarily reflects our preliminary
allocation of the $1.195 billion purchase price of our ownership interests in
Mid-America and Seminole. The pro forma estimated allocation of the purchase
price for Mid-America and Seminole is as follows:

PRELIMINARY ALLOCATION OF
PURCHASE PRICE FOR
-----------------------------------
MID-AMERICA SEMINOLE TOTAL
----------- -------- ----------

Cash and cash equivalents.......................... $ -- $ 11,160 $ 11,160
Accounts receivable................................ 21,889 16,990 38,879
Product inventory.................................. 10,210 -- 10,210
Prepaids and other current assets.................. 868 122 990
Property, plant and equipment...................... 957,408 352,684 1,310,093
Other assets....................................... 2,844 440 3,284
Accounts payable................................... (31,904) (20,337) (52,241)
Accrued taxes...................................... (7,777) (2,665) (10,442)
Other current liabilities.......................... (368) (1,853) (2,221)
Long-term debt..................................... -- (60,000) (60,000)
Other long-term liabilities........................ (384) -- (384)
Minority interest in assets and liabilities........ (12,586) (41,741) (54,328)
-------- -------- ----------
Total.................................... $940,200 $254,800 $1,195,000
======== ======== ==========

In preparing these pro forma financial statements, we have assumed that the
estimated $426.8 million difference between the purchase price of the assets
acquired and liabilities assumed in the Mid-America and Seminole acquisitions
(or $1.195 billion) and their respective carrying values (an adjusted $768.2
million after deducting for $54.3 million of minority interest) is attributable
to the fair market value of property, plant and equipment. For purposes of
calculating pro forma depreciation expense, we have applied the straight-line
method using an estimated remaining useful life of the Mid-America and Seminole
assets of 35 years to our new basis in these assets of $1.3 billion. After
adjusting for historical depreciation recorded on Mid-America and Seminole, pro
forma depreciation expense increased $2.2 million for the year ended December
31, 2001 and $1.3 million for the six months ended June 30, 2002.

We are currently working with third-party business valuation experts to
develop a definitive allocation of the purchase price. This fair market value
study will not be complete until the fourth quarter of 2002. As a result, the
final purchase price allocation may result in some amounts being assigned to
intangible assets and/or goodwill. To the extent that any amount is assigned to
an intangible asset, this amount may ultimately be amortized to earnings over
the expected period of benefit of the intangible asset. To the extent that any
amount is assigned to goodwill, this amount would not be subject to depreciation
or amortization, but would be subject to periodic impairment testing and if
necessary, written down to fair value should circumstances warrant.

Other significant aspects of this group of pro forma adjustments are as
follows:

- The pro forma adjustment to minority interest of $54.3 million is based
on the 2% interest in Mid-America and Seminole owned by Williams and the
20% interest in Seminole owned by its other joint owners.

- The pro forma adjustments also include those associated with the
extinguishment of Mid-America's $90 million in private placement debt
(along with its associated $2.1 million interest payable) immediately
prior to our purchase of the Mid-America interest. The pro forma entries
give effect to

F-7

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED
FINANCIAL STATEMENTS -- (CONTINUED)
DECEMBER 31, 2001 AND JUNE 30, 2002

the removal of interest expense associated with this debt of $8.4 million
in 2001 and $4.1 million for the first six months of 2002.

- In connection with the Mid-America acquisition, immediately prior to the
acquisition's effective date Williams converted Mid-America from a
corporation to a limited liability company resulting in the recognition
of the historical cumulative temporary differences previously recorded on
Mid-America's books. In addition, our allocation of purchase price for
both book and tax purposes was the same, thus eliminating the need to set
up any new cumulative temporary differences on Mid-America's books. The
pro forma adjustments reflect this change in Mid-America's tax structure
by eliminating these historical tax-related account balances. The impact
on Mid-America's pro forma earnings was the elimination of $17.4 million
in income tax expense for the year ended December 31, 2001 and $16.6
million for the six months ended June 30, 2002. This pro forma adjustment
removed income taxes due from affiliates of $11.8 million and deferred
income taxes for $122.6 million from Mid-America's balance sheet.

- In connection with the Seminole acquisition, certain tax elections were
made by the buyer and seller such that the transaction was treated as an
asset purchase for tax purposes. Our allocation of purchase price for
both book and tax purposes was the same, thus eliminating any historical
cumulative temporary differences previously recorded on Seminole's books.
The pro forma adjustments reflect the elimination of these historical
deferred tax balances. This pro forma adjustment removed income taxes due
from affiliates of $1.6 million and deferred income taxes of $59.1
million from Seminole's balance sheet.

(c) Since January 1, 2001, we have acquired three other strategic
businesses that are incorporated into the pro forma statements of consolidated
operations (included under the "Other" column in these statements). These are
the acquisition of a natural gas pipeline business from Shell during the second
quarter of 2001 and the acquisition of a propylene fractionation business and
NGL and petrochemical storage business from Diamond-Koch during the first
quarter of 2002. Our June 30, 2002 historical balance sheet already reflects
these acquisitions; thus, no pro forma adjustments to the balance sheet are
necessary. The unaudited pro forma statements of consolidated operations have
been prepared as if these acquisitions had occurred on January 1 of the
respective periods presented.

This group of pro forma adjustments reflects the following:

- As a result of the Diamond-Koch business acquisitions, we acquired
certain contract-based intangible assets that are subject to
amortization. On a pro forma basis, amortization expense associated with
these intangible assets increased by $1.7 million for the year ended
December 31, 2001 and $0.1 million for the six months ended June 30,
2002.

- Of the cumulative $612.3 million paid to acquire these three businesses,
the natural gas pipeline business acquired from Shell and the propylene
fractionation business acquired from Diamond-Koch were financed using
$482.2 million of fixed and variable rate debt. This resulted in pro
forma interest expense of $9.0 million for the year ended December 31,
2001 and $0.7 million for the six months ended June 30, 2002. If the
variable-interest rate used in such pro forma calculations were to
increase by 0.125%, pro forma interest expense would increase by $0.3
million for the year ended December 31, 2001 and by less than $0.1
million for the six months ended June 30, 2002.

(d) Represents the allocation of pro forma earnings to minority interest
holders. Williams has a 2% minority interest in Mid-America and Seminole. The
other owners of Seminole hold a 20% minority interest. Finally, our general
partner holds an approximate 1% minority interest in the earnings of our
Operating Partnership.

(e) Represents the adjustments necessary to allocate pro forma earnings
between our limited partners and our general partner.

(f) Reflects the elimination of material intercompany receivables,
payables, revenues and expenses between acquired companies and our Company as
appropriate in consolidation.

F-8

INDEPENDENT AUDITORS' REPORT

Enterprise Products Partners L.P.:

We have audited the accompanying consolidated balance sheets of Enterprise
Products Partners L.P. and subsidiaries (the "Company") as of December 31, 2001
and 2000, and the related statements of consolidated operations, consolidated
cash flows and consolidated partners' equity for each of the years in the
three-year period ended December 31, 2001. These consolidated financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these consolidated financial
statements based on our audits.

We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in
all material respects, the consolidated financial position of the Company at
December 31, 2001 and 2000, and the results of its consolidated operations and
its consolidated cash flows for each of the years in the three-year period ended
December 31, 2001 in conformity with accounting principles generally accepted in
the United States of America.

As discussed in Note 13 to the consolidated financial statements, the
Company changed its method of accounting for derivative instruments in 2001.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas
March 8, 2002
(May 15, 2002 as to Note 16 for the effects of a two-for-one split of Limited
Partner Units)

F-9

ENTERPRISE PRODUCTS PARTNERS L.P.

STATEMENTS OF CONSOLIDATED OPERATIONS
(DOLLARS IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)

FOR YEAR ENDED DECEMBER 31,
------------------------------------
2001 2000 1999
---------- ---------- ----------

REVENUES
Revenues from consolidated operations.................... $3,154,369 $3,049,020 $1,332,979
Equity income in unconsolidated affiliates............... 25,358 24,119 13,477
---------- ---------- ----------
Total.......................................... 3,179,727 3,073,139 1,346,456
COST AND EXPENSES
Operating costs and expenses............................. 2,861,743 2,801,060 1,201,605
Selling, general and administrative...................... 30,296 28,345 12,500
---------- ---------- ----------
Total.......................................... 2,892,039 2,829,405 1,214,105
---------- ---------- ----------
OPERATING INCOME......................................... 287,688 243,734 132,351
---------- ---------- ----------
OTHER INCOME (EXPENSE)
Interest expense......................................... (52,456) (33,329) (16,439)
Interest income from unconsolidated affiliates........... 31 1,787 1,667
Dividend income from unconsolidated affiliates........... 3,462 7,091 3,435
Interest income -- other................................. 7,029 3,748 886
Other, net............................................... (1,104) (272) (379)
---------- ---------- ----------
Other income (expense)......................... (43,038) (20,975) (10,830)
---------- ---------- ----------
INCOME BEFORE MINORITY INTEREST.......................... 244,650 222,759 121,521
MINORITY INTEREST........................................ (2,472) (2,253) (1,226)
---------- ---------- ----------
NET INCOME............................................... $ 242,178 $ 220,506 $ 120,295
========== ========== ==========
ALLOCATION OF NET INCOME TO:
Limited partners............................... $ 236,570 $ 217,909 $ 119,092
========== ========== ==========
General partner................................ $ 5,608 $ 2,597 $ 1,203
========== ========== ==========
BASIC EARNINGS PER UNIT
Income before minority interest................ $ 1.72 $ 1.64 $ .90
========== ========== ==========
Net income per Common and Subordinated unit.... $ 1.70 $ 1.63 $ .90
========== ========== ==========
DILUTED EARNINGS PER UNIT
Income before minority interest................ $ 1.40 $ 1.34 $ .83
========== ========== ==========
Net income per Common, Subordinated and Special
unit......................................... $ 1.39 $ 1.32 $ .82
========== ========== ==========

See Notes to Consolidated Financial Statements
F-10

ENTERPRISE PRODUCTS PARTNERS L.P.

CONSOLIDATED BALANCE SHEETS
(DOLLARS IN THOUSANDS)

DECEMBER 31,
-----------------------
2001 2000
---------- ----------

ASSETS
CURRENT ASSETS
Cash and cash equivalents (includes restricted cash of
$5,752 at December 31, 2001)........................... $ 137,823 $ 60,409
Accounts receivable -- trade, net of allowance for
doubtful accounts of $20,642 at December 31, 2001 and
$10,916 at December 31, 2000........................... 256,927 409,085
Accounts receivable -- affiliates......................... 4,375 6,533
Inventories............................................... 69,443 93,222
Prepaid and other current assets.......................... 50,207 12,107
---------- ----------
Total current assets.............................. 518,775 581,356
PROPERTY, PLANT AND EQUIPMENT, NET.......................... 1,306,790 975,322
INVESTMENTS IN AND ADVANCES TO UNCONSOLIDATED AFFILIATES.... 398,201 298,954
INTANGIBLE ASSETS, NET OF ACCUMULATED AMORTIZATION OF
$13,084 AT DECEMBER 31, 2001 AND $5,374 AT DECEMBER 31,
2000...................................................... 202,226 92,869
OTHER ASSETS................................................ 5,201 2,867
---------- ----------
TOTAL............................................. $2,431,193 $1,951,368
========== ==========
LIABILITIES AND PARTNERS' EQUITY
CURRENT LIABILITIES
Accounts payable -- trade................................. $ 54,269 $ 96,559
Accounts payable -- affiliates............................ 29,885 56,447
Accrued gas payables...................................... 233,536 377,126
Accrued expenses.......................................... 22,460 21,488
Accrued interest.......................................... 24,302 10,068
Other current liabilities................................. 44,764 24,691
---------- ----------
Total current liabilities......................... 409,216 586,379
LONG-TERM DEBT.............................................. 855,278 403,847
OTHER LONG-TERM LIABILITIES................................. 8,061 15,613
MINORITY INTEREST........................................... 11,716 9,570
COMMITMENTS AND CONTINGENCIES
PARTNERS' EQUITY
Common Units (102,721,830 Units outstanding at December
31, 2001 and 92,514,630 at December 31, 2000).......... 651,872 514,896
Subordinated Units (42,819,740 Units outstanding at
December 31, 2001 and December 31, 2000)............... 193,107 165,253
Special Units (29,000,000 Units outstanding at December
31, 2001 and 33,000,000 at December 31, 2000).......... 296,634 251,132
Treasury Units acquired by Trust, at cost (327,200 Common
Units outstanding at December 31, 2001 and 534,400 at
December 31, 2000)..................................... (6,222) (4,727)
General Partner........................................... 11,531 9,405
---------- ----------
Total Partners' Equity............................ 1,146,922 935,959
---------- ----------
TOTAL............................................. $2,431,193 $1,951,368
========== ==========

See Notes to Consolidated Financial Statements
F-11

ENTERPRISE PRODUCTS PARTNERS L.P.

STATEMENTS OF CONSOLIDATED CASH FLOWS
(DOLLARS IN THOUSANDS)

FOR YEAR ENDED DECEMBER 31,
---------------------------------
2001 2000 1999
--------- --------- ---------

OPERATING ACTIVITIES
Net income................................................ $ 242,178 $ 220,506 $ 120,295
Adjustments to reconcile net income to cash flows provided
by (used for) operating activities:
Depreciation and amortization........................... 51,903 41,045 25,315
Equity in income of unconsolidated affiliates........... (25,358) (24,119) (13,477)
Distributions received from unconsolidated affiliates... 45,054 37,267 6,008
Leases paid by EPCO..................................... 10,309 10,537 10,557
Minority interest....................................... 2,472 2,253 1,226
Loss (gain) on sale of assets........................... (390) 2,270 123
Changes in fair market value of financial instruments
(see Note 13)........................................ (5,697)
Net effect of changes in operating accounts............. (37,143) 71,111 27,906
--------- --------- ---------
Operating activities cash flows...................... 283,328 360,870 177,953
--------- --------- ---------
INVESTING ACTIVITIES
Capital expenditures...................................... (149,896) (243,913) (21,234)
Proceeds from sale of assets.............................. 568 92 8
Business acquisitions, net of cash received............... (225,665) (208,095)
Collection of notes receivable from unconsolidated
affiliates.............................................. 6,519 19,979
Investments in and advances to unconsolidated
affiliates.............................................. (116,220) (31,496) (61,887)
--------- --------- ---------
Investing activities cash flows...................... (491,213) (268,798) (271,229)
--------- --------- ---------
FINANCING ACTIVITIES
Long-term debt borrowings................................. 449,717 598,818 350,000
Long-term debt repayments................................. (490,000) (154,923)
Debt issuance costs....................................... (3,125) (4,043) (3,135)
Cash distributions paid to partners....................... (164,308) (139,577) (111,758)
Cash distributions paid to minority interest by Operating
Partnership............................................. (1,687) (1,429) (1,140)
Unit repurchased and retired.............................. (770)
Cash contributions from EPCO to minority interest......... 105 108 86
Treasury Units purchased by Trust......................... (18,003) (4,727)
Treasury Units reissued by Trust.......................... 22,600
Increase in restricted cash............................... (5,752)
--------- --------- ---------
Financing activities cash flows...................... 279,547 (36,893) 74,403
--------- --------- ---------
NET CHANGE IN CASH AND CASH EQUIVALENTS................... 71,662 55,179 (18,873)
CASH AND CASH EQUIVALENTS, JANUARY 1...................... 60,409 5,230 24,103
--------- --------- ---------
CASH AND CASH EQUIVALENTS, DECEMBER 31.................... $ 132,071 $ 60,409 $ 5,230
========= ========= =========

See Notes to Consolidated Financial Statements
F-12

ENTERPRISE PRODUCTS PARTNERS L.P.

STATEMENTS OF CONSOLIDATED PARTNERS' EQUITY
(DOLLARS IN THOUSANDS)

LIMITED PARTNERS
-------------------------------
COMMON SUBORD. SPECIAL TREASURY GENERAL
UNITS UNITS UNITS UNITS PARTNER TOTAL
--------- -------- -------- -------- ------- ----------

Balance, December 31, 1998.......................... $ 433,082 $123,829 $ 5,625 $ 562,536
Net income........................................ 80,998 38,094 1,203 120,295
Leases paid by EPCO............................... 7,109 3,342 106 10,557
Special Units issued to Shell in connection with
TNGL acquisition................................ $210,436 2,126 212,562
Cash distributions to Unitholders................. (81,993) (28,647) (1,118) (111,758)
Treasury Units acquired by consolidated Trust..... $(4,727) (4,727)
--------- -------- -------- ------- ------- ----------
Balance, December 31, 1999.......................... 439,196 136,618 210,436 (4,727) 7,942 789,465
Net income........................................ 148,656 69,253 2,597 220,506
Leases paid by EPCO............................... 7,117 3,315 105 10,537
Additional Special Units issued to Shell in
connection with contingency agreement........... 55,241 557 55,798
Conversion of 2.0 million Shell Special Units into
Common Units.................................... 14,513 (14,513)
Units repurchased and retired in connection with
buy-back program................................ (687) (43) (32) (8) (770)
Cash distributions to Unitholders................. (93,899) (43,890) (1,788) (139,577)
--------- -------- -------- ------- ------- ----------
Balance, December 31, 2000.......................... 514,896 165,253 251,132 (4,727) 9,405 935,959
Net income........................................ 163,795 72,775 5,608 242,178
Leases paid by EPCO............................... 7,078 3,128 103 10,309
Additional Special Units issued to Shell in
connection with contingency agreement........... 117,066 1,183 118,249
Conversion of 10.0 million Shell Special Units
into Common Units............................... 72,554 (72,554)
Cash distributions to Unitholders................. (109,969) (49,510) (4,829) (164,308)
Treasury Units acquired by consolidated Trust..... (18,003) (18,003)
Treasury Units reissued by consolidated Trust..... 16,508 16,508
Gain on reissuance of Treasury Units by
consolidated Trust.............................. 3,518 1,461 990 61 6,030
--------- -------- -------- ------- ------- ----------
Balance, December 31, 2001.......................... $ 651,872 $193,107 $296,634 $(6,222) $11,531 $1,146,922
========= ======== ======== ======= ======= ==========

See Notes to Consolidated Financial Statements
F-13

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

ENTERPRISE PRODUCTS PARTNERS L.P. including its consolidated subsidiaries
is a publicly-traded Delaware limited partnership listed on the New York Stock
Exchange under symbol "EPD". Unless the context requires otherwise, references
to "we","us","our" or the "Company" are intended to mean Enterprise Products
Partners L.P. and subsidiaries. We (including our operating subsidiary,
Enterprise Products Operating L.P. (the "Operating Partnership")) were formed in
April 1998 to own and operate the natural gas liquids ("NGL") business of
Enterprise Products Company ("EPCO"). We conduct substantially all of our
business through the Operating Partnership, in which we own a 98.9899% limited
partner interest. Enterprise Products GP, LLC (the "General Partner") owns
1.0101% of the Operating Partnership and 1% of the Company and serves as the
general partner of both entities. We and the General Partner are affiliates of
EPCO.

Prior to their consolidation, EPCO and its affiliate companies were
controlled by members of a single family, who collectively owned at least 90% of
each of the entities for all periods prior to the formation of the Company. As
of April 30, 1998, the owners of all the affiliated companies exchanged their
ownership interests for shares of EPCO. Accordingly, each of the affiliated
companies became a wholly-owned subsidiary of EPCO or was merged into EPCO as of
April 30, 1998. In accordance with generally accepted accounting principles, the
consolidation of the affiliated companies with EPCO was accounted for as a
reorganization of entities under common control in a manner similar to a pooling
of interests.

Under terms of a contract entered into on May 8, 1998 between EPCO and our
Operating Partnership, EPCO contributed all of its NGL assets through the
Company and the General Partner to the Operating Partnership and the Operating
Partnership assumed certain of EPCO's debt. As a result, we became the successor
to the NGL operations of EPCO.

Effective July 27, 1998, we filed a registration statement pursuant to an
initial public offering of 24,000,000 Common Units. The Common Units sold for
$11 per unit. We received approximately $243.3 million net of underwriting
commissions and offering costs.

The accompanying consolidated financial statements include the historical
accounts and operations of the NGL business of EPCO, including NGL operations
conducted by affiliated companies of EPCO prior to their consolidation with
EPCO. The consolidated financial statements include our accounts and those of
our majority-owned subsidiaries, after elimination of all material intercompany
accounts and transactions. In general, investments in which we own 20% to 50%
and exercise significant influence over operating and financial policies are
accounted for using the equity method. Investments in which we own less than 20%
are accounted for using the cost method unless we exercise significant influence
over operating and financial policies of the investee in which case the
investment is accounted for using the equity method.

Certain reclassifications have been made to the prior years' financial
statements to conform to the current year presentation. These reclassifications
had no effect on previously reported results of consolidated operations.

CASH FLOWS are computed using the indirect method. For cash flow purposes,
we consider all highly liquid investments with an original maturity of less than
three months at the date of purchase to be cash equivalents.

FINANCIAL INSTRUMENTS such as swaps, forwards and other contracts to manage
the price risks associated with inventories, firm commitments and certain
anticipated transactions are used by the Company. We are required to recognize
in earnings changes in fair value of these financial instruments that are not
offset by changes in the fair value of the inventories, firm commitments and
certain anticipated transactions. Fair value is generally defined as the amount
at which the financial instrument could be exchanged in a current transaction
between willing parties, not in a forced or liquidation sale.

F-14

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The effective portion of these hedged transactions will be deferred until
the firm commitment or anticipated transaction affects earnings. To qualify as a
hedge, the item to be hedged must expose us to commodity or interest rate risk
and the hedging instrument must reduce that exposure and meet the hedging
requirements of SFAS No. 133. Any contracts held or issued that do not meet the
requirements of a hedge (as defined by SFAS No. 133) will be recorded at fair
value on the balance sheet and any changes in that fair value recognized in
earnings (using mark-to-market accounting). A contract designated as a hedge of
an anticipated transaction that is no longer likely to occur is immediately
recognized in earnings.

DOLLAR AMOUNTS (except per Unit amounts) presented in the tabulations
within the notes to our financial statements are stated in thousands of dollars,
unless otherwise indicated.

EARNINGS PER UNIT is based on the amount of income allocated to limited
partners and the weighted-average number of Units outstanding during the period.
Specifically, basic earnings per Unit is calculated by dividing the amount of
income allocated to limited partners by the weighted-average number of Common
and Subordinated Units outstanding during the period. Diluted earnings per Unit
is based on the amount of income allocated to limited partners and the
weighted-average number of Common, Subordinated and Special Units outstanding
during the period. The Special Units are excluded from the computation of basic
earnings per Unit because, under the terms of the Special Units, they do not
share in income nor are they entitled to cash distributions until they are
converted to Common Units. See Notes 7 and 8 for additional information on the
capital structure and earnings per Unit computation.

ENVIRONMENTAL COSTS for remediation are accrued based on the estimates of
known remediation requirements. Such accruals are based on management's best
estimate of the ultimate costs to remediate the site. Ongoing environmental
compliance costs are charged to expense as incurred, and expenditures to
mitigate or prevent future environmental contamination are capitalized.
Environmental costs, accrued environmental liabilities and expenditures to
mitigate or eliminate future environmental contamination for each of the years
in the three-year period ended December 31, 2001 were not significant to the
consolidated financial statements. Costs of environmental compliance and
monitoring aggregated $1.3 million, $1.3 million and $0.9 million for the years
ended December 31, 2001, 2000 and 1999, respectively. Our estimated liability
for environmental remediation is not discounted.

EXCESS COST OVER UNDERLYING EQUITY IN NET ASSETS (or "excess cost") denotes
the excess of our cost (or purchase price) over our underlying equity in the net
assets of our investees. We have excess cost associated with our investments in
K/D/S Promix L.L.C., Dixie Pipeline Company, Neptune Pipeline Company L.L.C. and
Nemo Pipeline Company, LLC. The excess cost of these investments is reflected in
our investments in and advances to unconsolidated affiliates for these entities.
See Note 4 for a further discussion of the excess cost related to these
investments.

EXCHANGES are movements of NGL and petrochemical products and natural gas
between parties to satisfy timing and logistical needs of the parties. Volumes
borrowed from us under such agreements are included in inventory, and volumes
loaned to us under such agreements are accrued as a liability in accrued gas
payables.

FEDERAL INCOME TAXES are not provided because we are a master limited
partnership. As a result, our earnings or losses for Federal income tax purposes
are included in the tax returns of the individual partners. Accordingly, no
recognition has been given to income taxes in our financial statements. State
income taxes are not material to us. Net earnings for financial statement
purposes may differ significantly from taxable income reportable to unitholders
as a result of differences between the tax basis and financial reporting basis
of assets and liabilities and the taxable income allocation requirements under
the partnership agreement.

INVENTORIES are valued at the lower of average cost or market (normal trade
inventories of natural gas, NGLs and petrochemicals) or using specific
identification (volumes dedicated to forward sales contracts).
F-15

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

INTANGIBLE ASSETS include the values assigned to a 20-year natural gas
processing agreement and the excess cost of the purchase price over the fair
market value of the assets acquired from Mont Belvieu Associates (the "MBA
excess cost"), both of which were initially recorded in 1999. Of the intangible
values at December 31, 2001, $194.4 million is assigned to the natural gas
processing agreement and is being amortized on a straight-line basis over the
contract term.

The remaining $7.9 million balance of intangibles relates to the MBA excess
cost which has been amortized on a straight-line basis over 20 years. Upon
adoption of SFAS No. 142 on January 1, 2002, this amount was reclassified to
goodwill and will no longer be amortized but will be subject to periodic
impairment testing in accordance with the new standard. For additional
information regarding this reclassification and other details pertaining to the
adoption of SFAS No. 142, see Note 5.

LONG-LIVED ASSETS are reviewed for impairment whenever events or changes in
circumstances indicate that the carrying amount of an asset may not be
recoverable. We have not recognized any impairment losses for any of the periods
presented.

PROPERTY, PLANT AND EQUIPMENT is recorded at cost and is depreciated using
the straight-line method over the asset's estimated useful life. Maintenance,
repairs and minor renewals are charged to operations as incurred. The cost of
assets retired or sold, together with the related accumulated depreciation, is
removed from the accounts, and any gain or loss on disposition is included in
income.

Additions and improvements to and major renewals of existing assets are
capitalized and depreciated using the straight-line method over the estimated
useful life of the new equipment or modifications. These expenditures result in
a long-term benefit to the Company. We generally classify improvements and major
renewals of existing assets as sustaining capital expenditures and all other
capital spending on existing and new assets referred to as expansion capital
expenditures.

RESTRICTED CASH includes amounts held by a brokerage firm as margin
deposits associated with our financial instruments portfolio and for physical
purchase transactions made on the NYMEX exchange. At December 31, 2001, cash and
cash equivalents includes $5.8 million of restricted cash related to these
requirements.

REVENUE is recognized by our five reportable business segments using the
following criteria: (i) persuasive evidence of an exchange arrangement exists,
(ii) delivery has occurred or services have been rendered, (iii) the buyer's
price is fixed or determinable and (iv) collectibility is reasonably assured.
When the contracts settle (i.e., either physical delivery of product has taken
place or the services designated in the contract have been performed), a
determination of the necessity of an allowance is made and recorded accordingly.

In our Fractionation segment, we enter into NGL fractionation,
isomerization and propylene fractionation tolling arrangements, NGL
fractionation in-kind contracts and propylene fractionation merchant contracts.
Under our tolling arrangements, we recognize revenue once contract services have
been performed. These tolling arrangements typically include a base processing
fee per gallon subject to adjustment for changes in natural gas, electricity and
labor costs, which are the principal variable costs of fractionation and
isomerization operations. At our Norco NGL fractionation facility, certain
tolling arrangements involves the retention of a contractually-determined
percentage of the NGLs produced for the processing customer in lieu of a cash
tolling fee per gallon (i.e., an "in-kind" fee). We recognize revenue from these
in-kind contracts when we sell (at market-related prices) and deliver the NGLs
retained by our fractionator to customers. In our propylene fractionation
merchant contracts, we recognize revenue once the products have been delivered
to the customer. These merchant contracts are based upon market-related prices
as determined by the individual contracts.

F-16

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

In our Pipelines segment, we enter into pipeline, storage and product
loading contracts. Under our liquids pipeline and certain natural gas pipeline
throughput contracts, revenue is recognized when volumes have been physically
delivered for the customer through the pipeline. Revenue from this type of
throughput contract is typically based upon a fixed fee per gallon of liquids or
MMBtus of natural gas transported, whichever the case may be, multiplied by the
volume delivered. The throughput fee is generally contractual or as regulated by
the Federal Energy Regulatory Commission ("FERC"). Additionally, we have
merchant contracts associated with our natural gas pipeline business whereby
revenue is recognized once a quantity of natural gas has been delivered to a
customer. These merchant contracts are based upon market-related prices as
determined by the individual contracts.

In our storage contracts, we collect a fee based on the number of days a
customer has NGL or petrochemical volumes in storage multiplied by a storage
rate for each product. Under these contracts, revenue is recognized ratably over
the length of the storage contract based on the storage rates specified in each
contract. Revenues from product loading contracts (applicable to EPIK, an
unconsolidated affiliate of the Company) are recorded once the loading services
have been performed with the loading rates stated in the individual contracts.

As part of our Processing business, we have entered into a significant
20-year natural gas processing agreement with Shell ("Shell Processing
Agreement"), whereby we have the right to process Shell's current and future
natural gas production (including deepwater developments) from the Gulf of
Mexico within the state and federal waters off Texas, Louisiana, Mississippi,
Alabama and Florida. In addition to the Shell Processing Agreement, we have
contracts to process natural gas for other customers.

Under these contracts, the fee for our natural gas processing services is
based upon contractual terms with Shell or other third parties and may be
specified as either a cash fee or the retention of a percentage of the NGLs
extracted from the natural gas stream. If a cash fee for services is stipulated
by the contract, we record revenue once the natural gas has been processed and
sent back to Shell or other third parties (i.e., delivery has taken place).

If the contract stipulates that we retain a percentage of the NGLs
extracted as payment for its services, revenue is recorded when the NGLs are
sold and delivered to third parties. The Processing segment's merchant
activities may also buy and sell NGLs in the open market (including forward
sales contracts). The revenues recorded for these contracts are recognized upon
the delivery of the products specified in each individual contract. Pricing
under both types of arrangements is based upon market-related prices plus or
minus other determining factors specific to each contract such as location
pricing differentials.

The Octane Enhancement segment consists of our equity interest in Belvieu
Environmental Fuels ("BEF") which owns and operates a facility that produces
motor gasoline additives to enhance octane. This facility currently produces
MTBE. BEF's operations primarily occur as a result of a contract with Sunoco,
Inc. ("Sun") whereby Sun is obligated to purchase all of the facility's MTBE
output at market-related prices through September 2004. Revenue is recognized
once the product has been delivered to Sun.

The Other segment is primarily comprised of fee-based marketing services.
We perform NGL marketing services for a small number of customers for which we
charge a commission. Commissions are based on either a percentage of the final
sales price negotiated on behalf of the client or a fixed-fee per gallon based
on the volume sold for the client. Revenues are recorded at the time the
services are complete.

USE OF ESTIMATES AND ASSUMPTIONS by management that affect the reported
amounts of assets and liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period are required for the
preparation of financial statements in conformity with accounting principles
generally accepted in the United States of America. Our actual results could
differ from these estimates.

F-17

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

2. BUSINESS ACQUISITIONS

ACQUISITION OF ACADIAN GAS IN APRIL 2001

On April 2, 2001, we acquired Acadian Gas from an affiliate of Shell, for
approximately $226 million in cash using proceeds from the issuance of the $450
million Senior Notes B (see Note 6). Acadian Gas is involved in the purchase,
sale, transportation and storage of natural gas in Louisiana. Its assets are
comprised of the 438-mile Acadian and 577-mile Cypress natural gas pipelines and
a leased natural gas storage facility. Acadian Gas owns an approximate 49.5% of
Evangeline which owns a 27-mile natural gas pipeline. We operate the systems.
Overall, the Acadian Gas and Evangeline systems are comprised of 1,042 miles of
pipeline with an optimal design capacity of 1.1 Bcf/d.

The Acadian Gas and Evangeline systems link supplies of natural gas from
Gulf of Mexico production (through connections with offshore pipelines) and
various onshore developments to industrial, electrical and local distribution
customers primarily located in Louisiana. In addition, these systems have
interconnects with twelve interstate and four intrastate pipelines and a
bi-directional interconnect with the U.S. natural gas marketplace at the Henry
Hub.The Acadian Gas acquisition was accounted for under the purchase method of
accounting and, accordingly, the initial purchase price has been allocated to
the assets acquired and liabilities assumed based on their estimated fair values
at April 1, 2001 as follows (in millions):

Current assets.............................................. $ 83,123
Investments in unconsolidated affiliates.................... 2,723
Property, plant and equipment............................... 225,169
Current liabilities......................................... (83,890)
Other long-term liabilities................................. (1,460)
--------
Total purchase price...................................... $225,665
========

The balances related to the Acadian Gas acquisition included in the
consolidated balance sheet dated December 31, 2001 are based upon preliminary
information and are subject to change as additional information is obtained. The
initial purchase price is subject to certain post-closing adjustments
attributable to working capital items and is expected to be finalized during the
first half of 2002.

Historical information for periods prior to April 1, 2001 do not reflect
any impact associated with the Acadian Gas acquisition.

PRO FORMA EFFECT OF BUSINESS COMBINATIONS

The following table presents selected unaudited pro forma information for
the years ended December 31, 2001 and 2000 as if the acquisition of Acadian Gas
had been made as of the beginning of the years presented. This table also
incorporates selected unaudited pro forma information for the year ended
December 31, 2000 relating to our equity investments in Starfish and Neptune
(see Note 4).

The pro forma information is based upon data currently available to and
certain estimates and assumptions by management and, as a result, are not
necessarily indicative of our financial results had the transactions actually
occurred on these dates. Likewise, the unaudited pro forma information is not
necessarily indicative of our future financial results.

F-18

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

FOR YEAR ENDED DECEMBER 31,
----------------------------
2001 2000
------------ ------------

Revenues.................................................... $3,391,654 $3,673,049
Income before extraordinary item and minority interest...... $ 248,934 $ 217,223
Net income.................................................. $ 246,419 $ 215,026
Allocation of net income to
Limited partners.......................................... $ 240,745 $ 212,483
General Partner........................................... $ 5,674 $ 2,542
Units used in earnings per Unit calculations
Basic..................................................... 139,452 134,216
Diluted................................................... 170,786 164,888
Income per Unit before minority interest
Basic..................................................... $ 1.75 $ 1.60
Diluted................................................... $ 1.43 $ 1.30
Net income per Unit
Basic..................................................... $ 1.73 $ 1.59
Diluted................................................... $ 1.41 $ 1.29

3. PROPERTY, PLANT AND EQUIPMENT

Our property, plant and equipment and accumulated depreciation are as
follows:

ESTIMATED
USEFUL LIFE
IN YEARS 2001 2000
----------- ---------- ----------

Plants and pipelines............................ 5-35 $1,398,843 $1,108,519
Underground and other storage facilities........ 5-35 127,900 109,760
Transportation equipment........................ 3-35 3,736 2,620
Land............................................ 15,517 14,805
Construction in progress........................ 98,844 34,358
---------- ----------
Total......................................... 1,644,840 1,270,062
Less accumulated depreciation................... 338,050 294,740
---------- ----------
Property, plant and equipment, net............ $1,306,790 $ 975,322
========== ==========

Depreciation expense for the years ended December 31, 2001, 2000 and 1999
was $43.4 million, $33.3 million and $22.4 million, respectively. The increase
in depreciation expense is primarily due to acquisitions and expansion capital
projects over the last three years.

4. INVESTMENTS IN AND ADVANCES TO UNCONSOLIDATED AFFILIATES

We own interests in a number of related businesses that are accounted for
under the equity or cost method. The investments in and advances to these
unconsolidated affiliates are grouped according to the operating segment to
which they relate. For a general discussion of our operating segments, see Note
15.

F-19

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following table shows investments in and advances to unconsolidated
affiliates at:

DECEMBER 31,
--------------------
2001 2000
-------- --------

Accounted for on equity basis:
Fractionation:
BRF.................................................... $ 29,417 $ 30,599
BRPC................................................... 18,841 25,925
Promix................................................. 45,071 48,670
Pipeline:
EPIK................................................... 14,280 15,998
Wilprise............................................... 8,834 9,156
Tri-States............................................. 26,734 27,138
Belle Rose............................................. 11,624 11,653
Dixie.................................................. 37,558 38,138
Starfish............................................... 25,352
Neptune................................................ 76,880
Nemo................................................... 12,189
Evangeline............................................. 2,578
Octane Enhancement:
BEF.................................................... 55,843 58,677
Accounted for on cost basis:
Processing:
VESCO.................................................. 33,000 33,000
-------- --------
Total..................................................... $398,201 $298,954
======== ========

F-20

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following table shows equity in income (loss) of unconsolidated
affiliates for the year ended December 31:

FOR YEAR ENDED DECEMBER 31,
---------------------------
2001 2000 1999
------- ------- -------

Fractionation:
BRF................................................ $ 1,583 $ 1,369 $ (336)
BRPC............................................... 1,161 (284) 16
Promix............................................. 4,201 5,306 630
Other.............................................. 1,256
Pipeline:
EPIK............................................... 345 3,273 1,173
Wilprise........................................... 472 497 160
Tri-States......................................... 1,565 2,499 1,035
Belle Rose......................................... 103 301 (29)
Dixie.............................................. 2,092 751
Starfish........................................... 4,122
Ocean Breeze....................................... 32
Neptune............................................ 4,081
Nemo............................................... 75
Evangeline......................................... (145)
Other.............................................. 1,389
Octane Enhancement:
BEF................................................ 5,671 10,407 8,183
------- ------- -------
Total.............................................. $25,358 $24,119 $13,477
======= ======= =======

At December 31, 2001, our share of accumulated earnings of equity method
unconsolidated affiliates that had not been remitted to us was approximately
$7.0 million.

FRACTIONATION SEGMENT:

At December 31, 2001, the Fractionation segment included the following
unconsolidated affiliates accounted for using the equity method:

- Baton Rouge Fractionators LLC ("BRF") -- an approximate 32.25% interest
in an NGL fractionation facility located in southeastern Louisiana.

- Baton Rouge Propylene Concentrator, LLC ("BRPC") -- a 30.0% interest in a
propylene concentration unit located in southeastern Louisiana.

- K/D/S Promix LLC ("Promix") -- a 33.33% interest in an NGL fractionation
facility and related storage assets located in south Louisiana. Our
investment includes excess cost over the underlying equity in the net
assets of Promix of $8.0 million. The excess cost, which relates to plant
assets, is being amortized against our share of Promix's earnings over a
period of 20 years, which is the estimated useful life of the plant
assets that gave rise to the difference. The unamortized balance of
excess cost was $7.0 million at December 31, 2001.

The combined balance sheet information for the last two years and results
of operations data for the last three years of the Fractionation segment's
equity method investments are summarized below. As used in the

F-21

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

following tables, gross operating margin for equity investments represents
operating income before depreciation and amortization expense (both on operating
assets) and selling, general and administrative costs.

AS OF OR FOR THE YEAR ENDED
DECEMBER 31,
------------------------------
2001 2000 1999
-------- -------- --------

BALANCE SHEET DATA:
Current Assets............................................ $ 27,424 $ 31,168
Property, plant and equipment, net........................ 251,519 264,618
Other assets.............................................. 67
-------- --------
Total assets........................................... $278,943 $295,853
======== ========
Current liabilities....................................... $ 9,950 $ 13,661
Combined equity........................................... 268,993 282,192
-------- --------
Total liabilities and combined equity.................. $278,943 $295,853
======== ========
INCOME STATEMENT DATA:
Revenues.................................................. $ 76,480 $ 71,287 $ 36,293
Gross operating margin.................................... 36,321 33,240 14,970
Operating income.......................................... 22,396 19,997 5,930
Net income................................................ 22,738 20,661 4,200

PIPELINES SEGMENT:

At December 31, 2001, our Pipelines operating segment included the
following unconsolidated affiliates accounted for using the equity method:

- EPIK Terminalling L.P. and EPIK Gas Liquids, LLC (collectively,
"EPIK") -- a 50% aggregate interest in a refrigerated NGL marine terminal
loading facility located in southeast Texas. The Company owns 50% of EPIK
Terminalling L.P. which owns 99% of such facilities. We own 50% of EPIK
Gas Liquids, LLC which owns 1% of such facilities. We do not exercise
control over these entities; therefore, we are precluded from
consolidating such entities into our financial statements.

- Wilprise Pipeline Company, LLC ("Wilprise") -- a 37.35% interest in an
NGL pipeline system located in southeastern Louisiana.

- Tri-States NGL Pipeline LLC ("Tri-States") -- an aggregate 33.33%
interest in an NGL pipeline system located in Louisiana, Mississippi and
Alabama.

- Belle Rose NGL Pipeline LLC ("Belle Rose") -- a 41.67% interest in an NGL
pipeline system located in south Louisiana.

- Dixie Pipeline Company ("Dixie") -- an aggregate 19.88% interest in a
1,301-mile propane pipeline and associated facilities extending from Mont
Belvieu, Texas to North Carolina. Our investment includes excess cost
over the underlying equity in the net assets of Dixie of $37.4 million.
The excess cost, which relates to pipeline assets, is being amortized
against our share of Dixie's earnings over a period of 35 years, which is
the estimated useful life of the pipeline assets that gave rise to the
difference. The unamortized balance of excess cost over the underlying
equity in the net assets of Dixie was $35.7 million at December 31, 2001.

F-22

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

- Starfish Pipeline Company LLC ("Starfish") -- a 50% interest in a natural
gas gathering system and related dehydration and other facilities located
in south Louisiana and the Gulf of Mexico offshore Louisiana.

- Neptune Pipeline Company LLC ("Neptune") -- a 25.67% interest in the
natural gas gathering and transmission systems owned by Manta Ray
Offshore Gathering Company, LLC and Nautilus Pipeline Company LLC located
in the Gulf of Mexico offshore Louisiana.

- Nemo Gathering Company, LLC ("Nemo") -- a 33.92% interest in a natural
gas gathering system located in the Gulf of Mexico offshore Louisiana
that became operational in August 2001.

- Evangeline Gas Pipeline Company, L.P. and Evangeline Gas Corp.
(collectively, "Evangeline") -- an approximate 49.5% aggregate interest
in a natural gas pipeline system located in south Louisiana. We acquired
our interest in Evangeline as a result of the Acadian Gas acquisition
(see Note 2 for a description of this acquisition).

The combined balance sheet information for the last two years and results
of operations data for the last three years of the Pipelines segment's equity
method investments are summarized below:

AS OF OR FOR THE YEAR
ENDED DECEMBER 31,
---------------------
2001 2000 1999
--------- --------- -------

BALANCE SHEET DATA:
Current Assets...................................... $ 68,325 $ 25,464
Property, plant and equipment, net.................. 515,327 188,724
Other assets........................................ 50,265 3,666
-------- --------
Total assets..................................... $633,917 $217,854
======== ========
Current liabilities................................. $ 62,347 $ 31,085
Other liabilities................................... 57,965 4,018
Combined equity..................................... 513,605 182,751
-------- --------
Total liabilities and combined equity............ $633,917 $217,854
======== ========
INCOME STATEMENT DATA:
Revenues............................................ $305,404 $ 96,270 $52,386
Gross operating margin.............................. 98,682 51,414 24,845
Operating income.................................... 54,459 41,757 19,988
Net income.......................................... 41,015 31,241 15,637

Equity investments in Gulf of Mexico natural gas pipeline systems in January
2001

On January 29, 2001, we acquired a 50% equity interest in Starfish which
owns the Stingray natural gas pipeline system and a related natural gas
dehydration facility. The Stingray system is a 379-mile, FERC-regulated natural
gas pipeline system that transports natural gas and condensate from certain
production areas located in the Gulf of Mexico offshore Louisiana to onshore
transmission systems located in south Louisiana. The natural gas dehydration
facility is connected to the onshore terminal of the Stingray system in south
Louisiana. The optimal design capacity of the Stingray pipeline is 1.2 Bcf/d.
Shell is the operator of these systems and owns the remaining equity interests
in Starfish.

In addition to Starfish, we acquired a 25.67% interest in Ocean Breeze
Pipeline Company ("Ocean Breeze") and Neptune and a 33.92% interest in Nemo.
Ocean Breeze and Neptune collectively owned the Manta Ray and Nautilus natural
gas pipeline systems located in the Gulf of Mexico offshore Louisiana. The Manta
Ray system comprises approximately 235 miles of unregulated pipelines and
related equipment with an
F-23

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

optimal design capacity of 0.75 Bcf/d and the Nautilus system comprises
approximately 101 miles of FERC-regulated pipelines with an optimal design
capacity of 0.6 Bcf/d. The Nemo system, which became operational in August 2001,
comprises 24-mile natural gas pipeline with an optimal design capacity of 0.3
Bcf/d. Like Stingray, Shell is the operator of the Manta Ray and Nemo systems.
Shell is the administrative agent for Nautilus. In November 2001, Ocean Breeze
was merged into Neptune with the Company retaining its 25.67% interest in
Neptune. Shell and Marathon are the co-owners of Neptune and Shell owns the
remaining interest in Nemo.

The cash purchase price of the Starfish interest was $25 million with the
purchase price of the Ocean Breeze, Neptune and Nemo interests being $87
million. The investments were paid for using proceeds from the issuance of the
$450 million Senior Notes B (see Note 6).

Our investment in Neptune and Nemo includes excess cost over the underlying
equity in the net assets of these entities of $13.5 million. The excess cost,
which relates to pipeline assets, is being amortized against our share of
earnings from Neptune and Nemo over a period of 35 years, which is the estimated
useful life of the pipeline assets that gave rise to the difference. The
unamortized balance of excess cost over the underlying equity in the net assets
of Neptune and Nemo was $12.4 million and $0.7 million, respectively, at
December 31, 2001.

Historical information for periods prior to January 1, 2001 do not reflect
any impact associated with our equity investments in Starfish, Neptune and Nemo.

OCTANE ENHANCEMENT SEGMENT:

At December 31, 2001, the Octane Enhancement segment included our 33.33%
interest in Belvieu Environmental Fuels ("BEF"), a facility located in southeast
Texas that produces motor gasoline additives to enhance octane. The BEF facility
currently produces MTBE. The production of MTBE is driven by oxygenated fuel
programs enacted under the federal Clean Air Act Amendments of 1990 and other
legislation and as an additive to increase octane in motor gasoline. Any changes
to these oxygenated fuel programs that enable localities to elect to not
participate in these programs, lessen the requirements for oxygenates or favor
the use of non-isobutane based oxygenated fuels reduce the demand for MTBE and
could have an adverse effect on our results of operations.

In recent years, MTBE has been detected in water supplies. The major source
of the ground water contamination appears to be leaks from underground storage
tanks. Although these detections have been limited and the great majority have
been well below levels of public health concern, there have been calls for the
phase-out of MTBE in motor gasoline in various federal and state governmental
agencies and advisory bodies.

In light of these regulatory developments, the owners of BEF have been
formulating a contingency plan for use of the BEF facility if MTBE were banned
or significantly curtailed. Management is exploring a possible conversion of the
BEF facility from MTBE production to alkylate production. The Company believes
that if MTBE usage is banned or significantly curtailed, the motor gasoline
industry would need a substitute additive to maintain octane levels in motor
gasoline and that alkylate would be an attractive substitute. Depending upon the
type of alkylate process chosen and the level of alkylate production desired,
the cost to convert the facility from MTBE production to alkylate production
would range from $20 million to $90 million, with our share of these costs
ranging from $6.7 million to $30 million.

F-24

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Balance sheet information for the last two years and results of operations
data for the last three years for BEF are summarized below:

AS OF OR FOR THE
YEAR ENDED DECEMBER 31,
------------------------------
2001 2000 1999
-------- -------- --------

BALANCE SHEET DATA:
Current Assets..................................... $ 29,301 $ 20,640
Property, plant and equipment, net................. 140,009 150,603
Other assets....................................... 10,067 11,439
-------- --------
Total assets.................................... $179,377 $182,682
======== ========
Current liabilities................................ $ 13,352 $ 8,042
Other liabilities.................................. 3,438 5,779
Combined equity.................................... 162,587 168,861
-------- --------
Total liabilities and combined equity........... $179,377 $182,682
======== ========
INCOME STATEMENT DATA:
Revenues........................................... $213,734 $258,180 $193,219
Gross operating margin............................. 28,701 43,328 43,479
Operating income................................... 15,984 30,529 30,025
Income before accounting change.................... 17,014 31,220 29,029
Net income......................................... 17,014 31,220 24,550

PROCESSING SEGMENT:

At December 31, 2001, our investments in and advances to unconsolidated
affiliates also includes Venice Energy Services Company, LLC ("VESCO"). The
VESCO investment consists of a 13.1% interest in a company owning a natural gas
processing plant, fractionation facilities, storage, and gas gathering pipelines
in Louisiana. We account for this investment using the cost method.

5. RECENTLY ISSUED ACCOUNTING STANDARDS

In June 2001, the FASB issued two new pronouncements: SFAS No. 141,
"Business Combinations", and SFAS No. 142, "Goodwill and Other Intangible
Assets". SFAS No. 141 prohibits the use of the pooling-of-interest method for
business combinations initiated after June 30, 2001 and also applies to all
business combinations accounted for by the purchase method that are completed
after June 30, 2001. There are also transition provisions that apply to business
combinations completed before July 1, 2001, that were accounted for by the
purchase method. SFAS No. 142 is effective for our fiscal year that began
January 1, 2002 for all goodwill and other intangible assets recognized in our
consolidated balance sheet at that date, regardless of when those assets were
initially recognized. We adopted SFAS No. 141 on January 1, 2002.

Within six months of our adoption of SFAS No. 142 (by June 30, 2002), we
will have completed a transitional impairment review to identify if there is an
impairment to the December 31, 2001 recorded goodwill or intangible assets of
indefinite life using a fair value methodology. Professionals in the business
valuation industry will be consulted to validate the assumptions used in such
methodologies. Any impairment loss resulting from the transitional impairment
test will be recorded as a cumulative effect of a change in accounting principle
for the quarter ended June 30, 2002. Subsequent impairment losses will be
reflected in operating income in the Statements of Consolidated Operations.

F-25

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

At January 1, 2002, our intangible assets included the values assigned to
the 20-year Shell natural gas processing agreement (the "Shell agreement") and
the excess cost of the purchase price over the fair market value of the assets
acquired from Mont Belvieu Associates (the "MBA excess cost"), both of which
were initially recorded in 1999. The value of the Shell agreement ($194.4
million net book value at December 31, 2001) is being amortized on a
straight-line basis over its contract term. Likewise, the MBA excess cost ($7.9
million net book value at December 31, 2001) was being amortized on a
straight-line basis over 20 years. Based upon initial interpretations of the new
accounting standards, we anticipate that the intangible asset related to the
Shell agreement will continue to be amortized over its contract term ($11.1
million annually for 2002 through July 2019); however, the MBA excess cost will
be reclassified to goodwill in accordance with the new standard and its
amortization will cease (currently, $0.5 million annually). This goodwill would
then be subject to impairment testing as prescribed in SFAS No. 142. We are
continuing to evaluate the complex provisions of SFAS No. 142 and will fully
adopt the standard during 2002 within the prescribed time periods.

In addition to SFAS No. 141 and No. 142, the FASB also issued SFAS No. 143,
"Accounting for Asset Retirement Obligations", in June 2001. This statement
establishes accounting standards for the recognition and measurement of a
liability for an asset retirement obligation and the associated asset retirement
cost. This statement is effective for our fiscal year beginning January 1, 2003.
We are continuing to evaluate the provisions of this statement. In August 2001,
the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of
Long-Lived Assets". This statement addresses financial accounting and reporting
for the impairment and/or disposal of long-lived assets. We adopted this
statement effective January 1, 2002 and determined that it will have no material
impact on our financial statements as of that date.

6. LONG-TERM DEBT

Our long-term debt consisted of the following at:

DECEMBER 31,
-------------------
2001 2000
-------- --------

Borrowings under:
Senior Notes A, 8.25% fixed rate, due March 2005.......... $350,000 $350,000
MBFC Loan, 8.70% fixed rate, due March 2010............... 54,000 54,000
Senior Notes B, 7.50% fixed rate, due February 2011....... 450,000
-------- --------
Total principal amount............................ 854,000 404,000
Unamortized balance of increase in fair value related to
hedging a portion of fixed-rate debt...................... 1,653
Less unamortized discount on:
Senior Notes A............................................ (117) (153)
Senior Notes B............................................ (258)
Less current maturities of long-term debt................... --
-------- --------
Long-term debt.................................... $855,278 $403,847
======== ========

Long-term debt does not reflect the $250 million Multi-Year Credit Facility
or the $150 million 364-Day Credit Facility. No amount was outstanding under
either of these two revolving credit facilities at December 31, 2001. See below
for a complete description of these facilities.

At December 31, 2001, we had a total of $75 million of standby letters of
credit capacity under our $250 Million Multi-Year Credit Facility of which $2.4
million was outstanding.

Enterprise Products Partners L.P. acts as guarantor of certain debt
obligations of its major subsidiary, the Operating Partnership. This
parent-subsidiary guaranty provision exists under the Company's Senior Notes,
F-26

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

MBFC Loan and its two current revolving credit facilities. In the descriptions
that follow, the term "MLP" denotes Enterprise Products Partners L.P. in this
guarantor role.

SENIOR NOTES A. On March 13, 2000, we completed a public offering of $350
million in principal amount of 8.25% fixed-rate Senior Notes due March 15, 2005
at a price to the public of 99.948% per Senior Note (the "Senior Notes A").
These notes were issued to retire certain revolving credit loan balances that
were created as a result of the TNGL acquisition and other general partnership
activities.

The Senior Notes A are subject to a make-whole redemption right. The notes
are an unsecured obligation and rank equally with existing and future unsecured
and unsubordinated indebtedness and senior to any future subordinated
indebtedness. The notes are guaranteed by the MLP through an unsecured and
unsubordinated guarantee and were issued under an indenture containing certain
restrictive covenants. These covenants restrict our ability, with certain
exceptions, to incur debt secured by liens and engage in sale and leaseback
transactions. We were in compliance with these restrictive covenants at December
31, 2001.

SENIOR NOTES B. On January 24, 2001, we completed a public offering of $450
million in principal amount of 7.50% fixed-rate Senior Notes due February 1,
2011 at a price to the public of 99.937% per Senior Note (the "Senior Notes B").
These notes were issued to finance the acquisition of Acadian Gas, Ocean Breeze,
Neptune, Nemo and Starfish; to cover construction costs of certain NGL pipelines
and related projects; and to fund other general partnership activities.

The Senior Notes B were issued under the same indenture as Senior Notes A
and therefore are subject to similar terms and restrictive covenants. The Senior
Notes B are guaranteed by the MLP through an unsecured and unsubordinated
guarantee. We were in compliance with the restrictive covenants at December 31,
2001.

MBFC LOAN. On March 27, 2000, we executed a $54 million loan agreement with
the Mississippi Business Finance Corporation ("MBFC") having a 8.70% fixed-rate
and a maturity date of March 1, 2010. In general, the proceeds from this loan
were used to retire certain revolving credit loan balances attributable to
acquiring and constructing the Pascagoula, Mississippi natural gas processing
facility.

The MBFC Loan is subject to a make-whole redemption right and is guaranteed
by the MLP through an unsecured and unsubordinated guarantee. The indenture
agreement contains an acceleration clause whereby the outstanding principal and
interest on the loan may become due and payable if our credit ratings decline
below a Baa3 rating by Moody's (currently Baa2) and below a BBB- rating by
Standard and Poors (currently BBB). Under these circumstances, the trustee (as
defined in the indenture agreement) may, and if requested to do so by holders of
at least 25% in aggregate of the principal amount of the outstanding underlying
bonds, shall accelerate the maturity of the MBFC Loan, whereby the principal and
all accrued interest would become immediately due and payable. If such an event
occurred, we would have the option (a) to redeem the MBFC loan or (b) to provide
an alternate credit agreement (as defined in the indenture agreement) to support
our obligation under the MBFC loan, with both options exercisable within 120
days of receiving notice of the decline in our credit ratings from the ratings
agencies.

The loan agreement contains certain covenants including maintaining
appropriate levels of insurance on the Pascagoula facility and restrictions
regarding mergers. We were in compliance with the restrictive covenants at
December 31, 2001.

MULTI-YEAR CREDIT FACILITY. On November 17, 2000, we entered into a $250
million five-year revolving credit facility that includes a sublimit of $75
million for letters of credit. The November 17, 2005 maturity date may be
extended for one year at our option with the consent of the lenders, subject to
the extension provisions in the agreement. We can increase the amount borrowed
under this facility, with the consent of the Administrative Agent (whose consent
may not be unreasonably withheld), up to an amount not exceeding $350 million by
adding to the facility one or more new lenders and/or increasing the commitments
of existing lenders, so long as the aggregate amount of the funds borrowed under
this credit facility and the 364-Day

F-27

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Credit Facility (described below) does not exceed $500 million. No lender will
be required to increase its original commitment, unless it agrees to do so at
its sole discretion. This credit facility is guaranteed by the MLP through an
unsecured guarantee.

Proceeds from this credit facility will be used for working capital,
acquisitions and other general partnership purposes. No amount was outstanding
for this credit facility at December 31, 2001.

Our obligations under this bank credit facility are unsecured general
obligations and are non-recourse to the General Partner. As defined within the
agreement, borrowings under this bank credit facility will generally bear
interest at either (i) the greater of the Prime Rate or the Federal Funds
Effective Rate plus one-half percent or (ii) a Eurodollar Rate plus an
applicable margin or (iii) a Competitive Bid Rate. We elect the basis for the
interest rate at the time of each borrowing.

The credit agreement contains various affirmative and negative covenants
applicable to the Company to, among other things, (i) incur certain
indebtedness, (ii) grant certain liens, (iii) enter into certain merger or
consolidation transactions and (iv) make certain investments. In addition, we
may not directly or indirectly make any distribution in respect of its
partnership interests, except those payments in connection with the Buy-Back
Program (not to exceed $30 million in the aggregate, see Note 7) and
distributions from Available Cash from Operating Surplus, both as defined within
the agreement.

The credit agreement also requires that we satisfy certain financial
covenants at the end of each fiscal quarter. As defined within the agreement, we
(i) must maintain Consolidated Net Worth of $750 million and (ii) not permit our
ratio of Consolidated Indebtedness to Consolidated EBITDA, including pro forma
adjustments (as defined within the agreement), for the previous four quarter
period to exceed 4.0 to 1.0. We were in compliance with the restrictive
covenants at December 31, 2001.

364-DAY CREDIT FACILITY. In conjunction with the Multi-Year Credit
Agreement, we entered into a 364-day $150 million revolving bank credit
facility. In November 2001, we and our lenders amended the revolving credit
agreement to extend the maturity date to November 15, 2002 with the option to
convert any revolving credit balance outstanding at November 15, 2002 to a
one-year term loan.

We can increase the amount borrowed under this facility, with the consent
of the Administrative Agent (whose consent may not be unreasonably withheld), up
to an amount not exceeding $250 million by adding to the facility one or more
new lenders and/or increasing the commitments of existing lenders, so long as
the aggregate amount of the funds borrowed under this credit facility and the
Multi-Year Credit Facility do not exceed $500 million. No lender will be
required to increase its original commitment, unless it agrees to do so at its
sole discretion. This credit facility is guaranteed by the MLP through an
unsecured guarantee.

Proceeds from this credit facility will be used for working capital,
acquisitions and other general partnership purposes. No amount was outstanding
for this credit facility at December 31, 2001.

Limitations on certain actions by the Company and financial condition
covenants of this bank credit facility are substantially consistent with those
existing for the Multi-Year Credit Facility as described previously. We were in
compliance with the restrictive covenants at December 31, 2001.

F-28

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

February 2001 Registration Statement

On February 23, 2001, we filed a $500 million universal shelf registration
(the "February 2001 Shelf") covering the issuance of an unspecified amount of
equity or debt securities or a combination thereof. We expect to use the net
proceeds from any sale of securities for future business acquisitions and other
general corporate purposes, such as working capital, investments in
subsidiaries, the retirement of existing debt and/or the repurchase of Common
Units or other securities. The exact amounts to be used and when the net
proceeds will be applied to partnership purposes will depend on a number of
factors, including our funding requirements and the availability of alternative
funding sources. We routinely review acquisition opportunities.

Increase in fair value of fixed-rate debt

Upon adoption of SFAS No. 133 (see Note 13), we recorded a $2.3 million
fair value adjustment associated with our fixed-rate debt. The fair value
adjustment is not a cash obligation of the Company and does not alter the amount
of our indebtedness. Under the specific rules of SFAS 133, the fair value
adjustment will be amortized over the remaining life of the fixed-rate debt to
which it is associated, which approximates 10 years. See "Interest Rate Swaps"
under Note 13 for additional information concerning this item.

Impact of interest rate swap agreements upon interest expense

During 2001 and 2000, we utilized interest rate swap agreements to manage
debt service costs by converting a portion of our fixed-rate debt into
variable-rate debt. Income or losses sustained on these financial instruments
are reflected as a component of consolidated interest expense. At December 31,
2000, we had three interest rate swaps outstanding having a combined notional
value of $154 million (attributable to fixed-rate debt) with an estimated fair
value of $2.0 million. Due to the early termination of two of the swaps, the
notional amount and fair value of the remaining swap was $54 million and $2.3
million (an asset), respectively, at December 31, 2001.

We recorded as a reduction of interest expense $13.2 million from our
interest rates swaps during 2001 and $10.0 million during 2000. The income
recognized in 2001 from these swaps includes the $2.3 million in non-cash
mark-to-market income at December 31, 2001 (attributable to the sole remaining
swap). The remaining $10.9 million has been realized. No mark-to-market income
was recorded prior to the implementation of SFAS No. 133. For additional
information regarding our interest rate swaps, see Note 13.

7. CAPITAL STRUCTURE

The Second Amended and Restated Agreement of Limited Partnership of the
Company (the "Partnership Agreement") sets forth the calculation to be used to
determine the amount and priority of cash distributions that the Common and
Subordinated Unitholders and the General Partner will receive. The Partnership
Agreement also contains provisions for the allocation of net earnings and losses
to the Unitholders and the General Partner. For purposes of maintaining partner
capital accounts, the Partnership Agreement specifies that items of income and
loss shall be allocated among the partners in accordance with their respective
percentage interests. Normal allocations according to percentage interests are
done only, however, after giving effect to priority earnings allocations in an
amount equal to incentive cash distributions allocated 100% to the General
Partner. As an incentive, the General Partner's percentage interest in quarterly
distributions is increased after certain specified target levels are met. When
quarterly distributions exceed $0.253 per Unit, the General Partner receives a
percentage of the excess between the actual distribution rate and the target
level ranging from approximately 15% to 50% depending on the target level
achieved.

The Partnership Agreement generally authorizes us to issue an unlimited
number of additional limited partner interests and other equity securities for
such consideration and on such terms and conditions as shall

F-29

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

be established by the General Partner in its sole discretion without the
approval of Unitholders. During the Subordination Period (as described under
"Subordinated Units" below), however, we are limited with regards to the number
of equity securities that we may issue that rank senior to Common Units (except
for Common Units upon conversion of Subordinated Units, pursuant to employee
benefit plans, upon conversion of the general partner interest as a result of
the withdrawal of the General Partner or in connection with acquisitions or
capital improvements that are accretive on a per Unit basis) or an equivalent
number of securities ranking on a parity with the Common Units, without the
approval of the holders of at least a Unit Majority. A Unit Majority is defined
as at least a majority of the outstanding Common Units (during the Subordination
Period), excluding Common Units held by the General Partner and its affiliates,
and at least a majority of the outstanding Common Units (after the Subordination
Period). After adjusting for the Units issued in connection with the TNGL
acquisition, the number of Common Units available (and unreserved) to us for
general partnership purposes during the Subordination Period was 54,550,000 at
December 31, 2001.

SUBORDINATED UNITS. The 42,819,740 Subordinated Units have no voting rights
until converted into Common Units at the end of the Subordination Period. The
Subordination Period will generally extend until the first day of any quarter
beginning after June 30, 2003 when the Conversion Tests have been satisfied.
Generally, the Conversion Test will have been satisfied when we have paid from
Operating Surplus and generated from Adjusted Operating Surplus the minimum
quarterly distribution on all Units for each of the three preceding four-quarter
periods. Upon expiration of the Subordination Period, all remaining Subordinated
Units will convert into Common Units on a one-for-one basis and will thereafter
participate pro rata with the other Common Units in distributions of Available
Cash.

The Partnership Agreement stipulates that 50% of the Subordinated Units may
undergo an early conversion into Common Units should certain criteria be
satisfied. Based upon these criteria, the earliest that the first 25% of the
Subordinated Units would convert into Common Units is May 1, 2002. Should the
criteria continue to be satisfied through the first quarter of 2003, an
additional 25% of the Subordinated Units would undergo an early conversion into
Common Units on May 1, 2003. The remaining 50% of Subordinated Units would
convert on August 1, 2003 should the balance of the conversion requirements be
met.

SPECIAL UNITS. The Special Units issued to Shell in conjunction with the
1999 TNGL acquisition and a related-contingent unit agreement do not accrue
distributions and are not entitled to cash distributions until their conversion
into Common Units on a one for one basis. For financial accounting and tax
purposes, the Special Units are generally not allocated any portion of net
income; however, for tax purposes, the Special Units are allocated a certain
amount of depreciation until their conversion into Common Units.

We issued 29.0 million Special Units to Shell in August 1999 in connection
with TNGL acquisition. Subsequently, Shell met certain performance criteria in
2000 and 2001 that obligated us to issue an additional 12.0 million Special
Units to Shell -- 6.0 million were issued in August 2000 and 6.0 million in
August 2001 under a contingent unit agreement. Of the cumulative 41.0 million
Special Units issued, 12.0 million have already converted to Common Units (2.0
million in August 2000 and 10.0 million in August 2001). The remaining Special
Units will convert to Common Units on a one for one basis as follows: 19.0
million in August 2002 and 10.0 million in August 2003. These conversions have a
dilutive effect on basic earnings per Unit.

Under the rules of the New York Stock Exchange, the conversion of Special
Units into Common Units requires the approval of a majority of Common
Unitholders. An affiliate of EPCO, which owns in excess of 62% of the
outstanding Common Units, has voted its Units in favor of past conversions,
which provided the necessary votes for approval.

BUY-BACK PROGRAM. In 2000, the General Partner authorized us to repurchase
and retire up to 2,000,000 of our publicly-held Common Units. The repurchase and
retirements will be made during periods of temporary market weakness at price
levels that would be accretive to our remaining Unitholders.

F-30

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

In September 2001, the General Partner approved a modification to the
Buy-Back Program that allows both the Company (specifically, Enterprise Products
Partners L.P.) and its consolidated revocable grantor trust (EPOLP 1999 Grantor
Trust or the "Trust") to repurchase Common Units under the program. Under the
terms of the modification, purchases made by the Company will continue to be
retired whereas purchases made by the Trust will remain outstanding and not be
retired. The Common Units purchased by the Trust will be accounted for as
Treasury Units.

During 2000, the Company repurchased and retired 56,800 Common Units under
this program. The Trust purchased 792,800 Common Units under this program in
2001. At December 31, 2001, 1,150,400 Common Units could be repurchased and/or
retired under this program. (see Note 16 for a discussion of a subsequent event
involving the declaration of a two-for-one split of Common Units that occurred
in May 2002).

TREASURY UNITS ACQUIRED BY TRUST. During the first quarter of 1999, the
Operating Partnership established the Trust to fund potential future obligations
under the EPCO Agreement with respect to EPCO's long-term incentive plan
(through the exercise of options granted to EPCO employees or directors of the
General Partner). The Common Units purchased by the Trust are accounted for in a
manner similar to treasury stock under the cost method of accounting. The Trust
purchased 534,400 Common Units in 1999 at a cost of $4.7 million and 792,800
Common Units in 2001 at a cost of $18.0 million.

In November 2001, the Trust sold 1,000,000 Common Units previously held in
treasury to EPCO for $22.6 million. The sales price of the treasury Common Units
sold exceeded the purchase price of the Treasury Units by $6.0 million and has
been credited to Partners' Equity accounts in a manner similar to additional
paid-in capital.

UNIT HISTORY. The following table details the outstanding balance of each
class of Units at the end of the periods indicated:

LIMITED PARTNERS
---------------------------
COMMON SUBORDINATED TREASURY
UNITS UNITS SPECIAL UNITS UNITS
----------- ------------ ------------- ----------

Balance, December 31, 1997.............. 67,105,830 42,819,740
Units issued to public................ 24,000,000
----------- ----------
Balance, December 31, 1998.............. 91,105,830 42,819,740
Special Units issued to Shell in
connection with TNGL acquisition... 29,000,000
Treasury Units purchased by
consolidated Trust................. (534,400) 534,400
----------- ---------- ----------- ----------
Balance, December 31, 1999.............. 90,571,430 42,819,740 29,000,000 534,400
Additional Special Units issued to
Coral Energy, LLC in connection
with contingency agreement......... 6,000,000
Conversion of 2.0 million Coral
Energy, LLC Special Units into
Common Units....................... 2,000,000 (2,000,000)
Units repurchased and retired in
connection with buy-back program... (56,800)
----------- ---------- ----------- ----------
Balance, December 31, 2000.............. 92,514,630 42,819,740 33,000,000 534,400

F-31

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

LIMITED PARTNERS
---------------------------
COMMON SUBORDINATED TREASURY
UNITS UNITS SPECIAL UNITS UNITS
----------- ------------ ------------- ----------

Additional Special Units issued to
Coral Energy, LLC in connection
with contingency agreement......... 6,000,000
Conversion of 10.0 million Coral
Energy, LLC Special Units into
Common Units....................... 10,000,000 (10,000,000)
Treasury Units purchased by
consolidated Trust................. (792,800) 792,800
Treasury Units reissued by
consolidated Trust................. 1,000,000 (1,000,000)
----------- ---------- ----------- ----------
Balance, December 31, 2001.............. 102,721,830 42,819,740 29,000,000 327,200
=========== ========== =========== ==========

8. EARNINGS PER UNIT

Basic earnings per Unit is computed by dividing net income available to
limited partner interests by the weighted-average number of Common and
Subordinated Units outstanding during the period. Diluted earnings per Unit is
computed by dividing net income available to limited partner interests by the
weighted-average number of Common, Subordinated and Special Units outstanding
during the period. The following table reconciles the number of Units used in
the calculation of basic earnings per Unit and diluted earnings per Unit for
each of the three years ended December 31, 2001, 2000 and 1999.

The weighted-average number of Common Units outstanding in 2001 and 2000
reflect the conversion of a portion of Shell's Special Units to Common Units in
August of each year. Specifically, ten million Special Units converted to Common
Units in August 2001 and two million Special Units converted in August 2000. The
weighted-average number of Special Units outstanding in 2001 and 2000 reflect
the above conversions and the issuance of six million Special Units in August
2001 and August 2000. See Note 7 for additional information regarding Shell's
Special Units.

FOR YEAR ENDED DECEMBER 31,
--------------------------------
2001 2000 1999
-------- -------- --------

Income before minority interest.................... $244,650 $222,759 $121,521
General partner interest........................... (5,608) (2,597) (1,203)
-------- -------- --------
Income before minority interest available to
Limited Partners................................. 239,042 220,162 120,318
Minority interest.................................. (2,472) (2,253) (1,226)
-------- -------- --------
Net income available to Limited Partners........... $236,570 $217,909 $119,092
======== ======== ========
BASIC EARNINGS PER UNIT
NUMERATOR
Income before minority interest available to
Limited Partners............................ $239,042 $220,162 $120,318
======== ======== ========
Net income available to Limited Partners...... $236,570 $217,909 $119,092
======== ======== ========
DENOMINATOR (WEIGHTED-AVERAGE)
Common Units outstanding...................... 96,632 91,396 90,600
Subordinated Units outstanding................ 42,820 42,820 42,820
-------- -------- --------
Total......................................... 139,452 134,216 133,420
======== ======== ========

F-32

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

FOR YEAR ENDED DECEMBER 31,
--------------------------------
2001 2000 1999
-------- -------- --------

BASIC EARNINGS PER UNIT
Income before minority interest available to
Limited Partners............................ $ 1.72 $ 1.64 $ .90
======== ======== ========
Net income available to Limited Partners...... $ 1.70 $ 1.63 $ .90
======== ======== ========
DILUTED EARNINGS PER UNIT
NUMERATOR
Income before minority interest available to
Limited Partners............................ $239,042 $220,162 $120,318
======== ======== ========
Net income available to Limited Partners...... $236,570 $217,909 $119,092
======== ======== ========
DENOMINATOR (WEIGHTED-AVERAGE)
Common Units outstanding...................... 96,632 91,396 90,600
Subordinated Units outstanding................ 42,820 42,820 42,820
Special Units outstanding..................... 31,334 30,672 12,156
-------- -------- --------
Total......................................... 170,786 164,888 145,576
======== ======== ========
DILUTED EARNINGS PER UNIT
Income before minority interest available to
Limited Partners............................ $ 1.40 $ 1.34 $ .83
======== ======== ========
Net income available to Limited Partners...... $ 1.39 $ 1.32 $ .82
======== ======== ========

9. DISTRIBUTIONS

We intend, to the extent there is sufficient available cash from Operating
Surplus, as defined by the Partnership Agreement, to distribute to each holder
of Common Units at least a minimum quarterly distribution of $0.225 per Common
Unit. The minimum quarterly distribution is not guaranteed and is subject to
adjustment as set forth in the Partnership Agreement. With respect to each
quarter during the Subordination Period, the Common Unitholders will generally
have the right to receive the minimum quarterly distribution, plus any
arrearages thereon, and the General Partner will have the right to receive the
related distribution on its interest before any distributions of available cash
from Operating Surplus are made to the Subordinated Unitholders. As an
incentive, the General Partner's interest in quarterly distributions is
increased after certain specified target levels are met. We made incentive
distributions to the General Partner of $3.2 million during 2001 and $0.4
million during 2000.

F-33

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following table is a summary of cash distributions to partnership
interests since the first quarter of 1999.

CASH DISTRIBUTION HISTORY
------------------------------------------------------
PER PER
COMMON SUBORDINATED
UNIT UNIT RECORD DATE PAYMENT DATE
------- ------------ ------------- -------------

1999
1st Quarter....................... $0.2250 $0.0350 Apr. 30, 1999 May 12, 1999
2nd Quarter....................... $0.2250 $0.1850 Jul. 30, 1999 Aug. 11, 1999
3rd Quarter....................... $0.2250 $0.2250 Oct. 29, 1999 Nov. 10, 1999
4th Quarter....................... $0.2500 $0.2500 Jan. 31, 2000 Feb. 10, 2000
2000
1st Quarter....................... $0.2500 $0.2500 Apr. 28, 2000 May 10, 2000
2nd Quarter....................... $0.2625 $0.2625 Jul. 31, 2000 Aug. 10, 2000
3rd Quarter....................... $0.2625 $0.2625 Oct. 31, 2000 Nov. 10, 2000
4th Quarter....................... $0.2750 $0.2750 Jan. 31, 2001 Feb. 9, 2001
2001
1st Quarter....................... $0.2750 $0.2750 Apr. 30, 2001 May 10, 2001
2nd Quarter....................... $0.2938 $0.2938 Jul. 31, 2001 Aug. 10, 2001
3rd Quarter....................... $0.3125 $0.3125 Oct. 31, 2001 Nov. 9, 2001
4th Quarter....................... $0.3125 $0.3125 Jan. 31, 2002 Feb. 11, 2002

The quarterly cash distribution amounts shown in the table correspond to
the cash flows for the quarters indicated. The actual cash distributions (i.e.,
payments to our limited partners) occur within 45 days after the end of such
quarter.

10. RELATED PARTY TRANSACTIONS

We have no employees. All management, administrative and operating
functions are performed by employees of EPCO pursuant to the EPCO Agreement (in
effect since July 1998). Under the terms of the EPCO Agreement, EPCO agreed to:

- employ the personnel necessary to manage our business and affairs
(through the General Partner);

- employ the operating personnel involved our business for which we
reimburse EPCO at cost (based upon EPCO's actual salary costs and related
fringe benefits);

- allow us to participate as named insureds in EPCO's current insurance
program with the costs being allocated among the parties on the basis of
formulas set forth in the agreement;

- grant us an irrevocable, non-exclusive worldwide license to use all of
the EPCO trademarks and trade names;

- indemnify us against any losses resulting from certain lawsuits; and to

- sublease to us all of the equipment which it holds pursuant to operating
leases relating to an isomerization unit, a deisobutanizer tower, two
cogeneration units and approximately 100 railcars for one dollar per year
and to assign its' purchase option under such leases to us. EPCO remains
liable for the lease payments associated with these assets.

F-34

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Operating costs and expenses (as shown in the audited Statements of
Consolidated Operations) treat the full amount of lease payments being made by
EPCO as a non-cash operating expense (with the offset to Partners' Equity on the
Consolidated Balance Sheet). In addition, operating costs and expenses include
compensation charges for EPCO's employees who operate the facilities.Pursuant to
the EPCO Agreement, we reimburse EPCO for our portion of the costs of certain of
its employees who manage our business and affairs. In general, our reimbursement
of EPCO's expense associated with administrative positions that were active at
the time of our initial public offering in July 1998 is capped by the
Administrative Services Fee that we pay (currently at $16 million annually). The
General Partner, with the approval and consent of the Audit and Conflicts
Committee, may agree to annual increases of such fee up to ten percent per year
during the 10-year term of the EPCO Agreement. Any difference between the actual
costs of this "pre-expansion" group (including those associated with
equity-based awards granted to certain individuals within this group) and the
Administrative Services Fee will be retained by EPCO (i.e., EPCO solely bears
any shortfall in reimbursement for this group).

Beginning in January 2000, we began reimbursing EPCO for our share of the
compensation of administrative personnel that it had hired in response to our
expansion and business development activities (through the construction of new
facilities, business acquisitions or the like). EPCO began hiring "expansion"
administrative personnel during 1999 in connection with the TNGL acquisition and
other development activities. In general, we reimburse EPCO for our share of its
compensation expense associated with these "expansion" administrative positions,
including those costs attributable to equity-based awards.

The following table summarizes the Administrative Services Fee paid to EPCO
during the last three years. In addition, the table shows the total compensation
reimbursed to EPCO for operations personnel and "expansion" administrative
positions.

FOR YEAR ENDED DECEMBER 31,
-----------------------------
2001 2000 1999
------- ------- -------

Administrative Services Fee paid to EPCO.............. $15,125 $13,750 $12,500
Compensation reimbursed to EPCO....................... 48,507 44,717 26,889
------- ------- -------
Total............................................... $63,632 $58,467 $39,389
======= ======= =======

We elected to prepay EPCO a discounted amount of $15.7 million for the 2002
Administrative Services Fee in December 2001 (the undiscounted amount was $16.0
million). We will owe EPCO for any undiscounted amount above the $16.0 million
if the General Partner approves an increase in the fee during 2002.

Other related party and similar transactions with EPCO or its affiliates

EPCO also operates the facilities owned by BEF and EPIK and charges them
for actual salary costs and related fringe benefits. In addition, EPCO is paid a
management fee by these entities in lieu of reimbursement for the actual cost of
providing management services; such charges aggregated $0.8 for 2001, $0.9
million for 2000 and $0.8 million in 1999.

We have entered into an agreement with EPCO to provide trucking services
related to the loading and transportation of NGL products. EPCO charged us $9.0
million in 2001, $7.9 million in 2000 and $5.7 million in 1999 for these
services. On occasion, in the normal course of business, we may engage in
transactions with EPCO involving the buying and selling of NGL products. No such
sales or purchases were transacted with EPCO during 2001 and 2000; however, we
purchased a net $20.6 million of such products from EPCO during 1999.

F-35

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

In addition, trust affiliates of EPCO (Enterprise Products 1998 Unit Option
Plan Trust and the Enterprise Products 2000 Rabbi Trust) purchase Common Units
for the purpose of granting options to EPCO management and certain key employees
(many of whom also serve in similar capacities with the General Partner). During
2001, these trusts purchased 423,036 Common Units on the open market or through
privately negotiated transactions. At December 31, 2001, these trusts owned a
total of 2,923,036 Common Units. In November 2001, EPCO directly purchased
1,000,000 Common Units at market prices from our consolidated trust, EPOLP 1999
Grantor Trust, on behalf of a key executive.

Relationships with Shell

We have an extensive and ongoing relationship with Shell as a partner,
customer and vendor. Shell, through its subsidiary Shell US Gas & Power LLC,
owns approximately 23.2% of our limited partnership interests and 30.0% of the
General Partner. Currently, three members of the Board of Directors of the
General Partner are employees of Shell.

The most significant contract affecting our natural gas processing business
is the 20-year Shell Processing Agreement which grants us the right to process
Shell's current and future production from the Gulf of Mexico within the state
and federal waters off Texas, Louisiana, Mississippi, Alabama and Florida (on a
keepwhole basis). This includes natural gas production from deepwater
developments. Shell is the largest oil and gas producer and holds one of the
largest lease positions in the deepwater Gulf of Mexico. Generally, this
contract has the following rights and obligations:

- the exclusive right to process any and all of Shell's Gulf of Mexico
natural gas production from existing and future dedicated leases; plus

- the right to all title, interest and ownership in the mixed NGL stream
extracted by our gas plants from Shell's natural gas production from such
leases; with

- the obligation to deliver to Shell the natural gas stream after the mixed
NGL stream is extracted.

Apart from operating expenses arising from the Shell Processing Agreement,
we also sell NGL and petrochemical products to Shell.

The following table shows the related party amounts by major category in
the Company's Statements of Consolidated Operations for the last three years.
The table also shows the total amounts paid to EPCO separately under the EPCO
Agreement for employee-related costs for the last three years.

FOR YEAR ENDED DECEMBER 31,
------------------------------
2001 2000 1999
-------- -------- --------

REVENUES FROM CONSOLIDATED OPERATIONS
Unconsolidated affiliates.......................... $173,684 $ 61,988 $ 40,352
Shell.............................................. 333,333 292,741 56,301
EPCO and subsidiaries.............................. 5,439 4,750 9,148
OPERATING COSTS AND EXPENSES
Unconsolidated affiliates.......................... 41,062 58,202 20,696
Shell.............................................. 705,440 736,655 188,570
EPCO and subsidiaries.............................. 10,075 9,492 35,046
EPCO AGREEMENT....................................... 63,632 58,467 39,389

F-36

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

11. COMMITMENTS AND CONTINGENCIES

REDELIVERY COMMITMENTS

From time to time, we store NGL, petrochemical and natural gas volumes for
third parties under various processing, storage and similar agreements. Under
the terms of these agreements, we are generally required to redeliver to the
owner volumes on demand. We are insured for any physical loss of such volumes
due to catastrophic events. At December 31, 2001, NGL and petrochemical volumes
aggregating 320 million gallons were due to be redelivered to their owners along
with 887,414 MMBtus of natural gas.

LEASE COMMITMENTS

We lease certain equipment and processing facilities under noncancelable
and cancelable operating leases. Minimum future rental payments on such leases
with terms in excess of one year at December 31, 2001 are as follows:

2002........................................................ $ 5,115
2003........................................................ 4,862
2004........................................................ 4,324
2005........................................................ 279
2006........................................................ 181
Thereafter.................................................. 1,077
-------
Total minimum obligations................................. $15,838
=======

The operating lease commitments shown above exclude the expense associated
with various equipment leases contributed to us by EPCO at our formation for
which EPCO has retained the liability. During 2001, 2000 and 1999, our non-cash
lease expense associated with these EPCO "retained" leases was $10.4 million,
$10.6 million and $10.6 million, respectively.

Lease and rental expense (including Retained Leases) included in operating
income for the years ended December 31, 2001, 2000 and 1999 was approximately
$23.4 million, $21.2 million and $20.6 million. EPCO has assigned us the
purchase options associated with the retained leases. Should we decide to
exercise our purchase options under the retained leases, up to $26.0 million
will be payable in 2004, $3.4 million in 2008 and $3.1 million in 2016.

PURCHASE COMMITMENTS

Gas purchase commitments. We have long-term purchase commitments for NGL
products and related-streams including natural gas with several suppliers. The
purchase prices contained within these contracts

F-37

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

approximate market value at the time of delivery. The following table shows our
long-term volume commitments under these contracts.

2002 2003 2004 2005 2006 THEREAFTER
------ ------ ------ ------ ------ ----------

NGLs (000s barrels):
Ethane................................ 2,154 2,154 1,677 1,089 126
Propane............................... 2,898 2,826 1,899 900 102
Isobutane............................. 498 498 387 252 30
Normal Butane......................... 1,134 964 735 303 34
Natural Gasoline...................... 1,944 1,944 1,488 846 48
Other................................. 960 460 180
------ ------ ------ ------ ------
Total NGLs.................... 9,588 8,846 6,366 3,390 340
====== ====== ====== ====== ======
Natural gas (BBtus)..................... 13,726 13,726 12,996 12,996 12,996 75,600
====== ====== ====== ====== ====== ======

Capital spending commitments. As of December 31, 2001, we had capital
expenditure commitments totaling approximately $5.3 million, of which $0.3
million relates to our portion of internal growth projects of unconsolidated
affiliates.

LITIGATION

We are indemnified for any litigation pending as of the date of our
formation by EPCO. We are sometimes named as a defendant in litigation relating
to our normal business operations. Although we insure against various business
risks, to the extent management believes it is prudent, there is no assurance
that the nature and amount of such insurance will be adequate, in every case, to
indemnify us against liabilities arising from future legal proceedings asa
result of ordinary business activity. Except as noted below, management is not
aware of any significant litigation, pending or threatened, that would have a
significant adverse effect on our financial position or results of operations.

Regulations imposing more strict air emissions requirements on existing
facilities in the Houston-Galveston area were issued in December 2000. These
regulations may necessitate extensive redesign and modification of our Mont
Belvieu facilities to achieve the air emissions reductions needed for federal
Clean Air Act compliance. The technical practicality and economic reasonableness
of these regulations have been challenged under state law in litigation filed on
January 19, 2001, against the Texas Natural Resource Conservation Commission and
its principal officials in the District Court of Travis County, Texas, by a
coalition of major Houston-Galveston area industries, including us. Until this
litigation is resolved, the precise level of technology to be employed and the
cost for modifying the facilities to achieve the required amount of reductions
cannot be determined. Currently, the litigation has been stayed by agreement of
the parties pending the outcome of expanded, cooperative scientific research to
more precisely define sources and mechanisms of air pollution in the
Houston-Galveston area. Completion of this research is anticipated in mid-2002.

F-38

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

12. SUPPLEMENTAL CASH FLOWS DISCLOSURE

The net effect of changes in operating assets and liabilities is as
follows:

FOR YEAR ENDED DECEMBER 31,
--------------------------------
2001 2000 1999
--------- -------- ---------

(Increase) decrease in:
Accounts receivable....................................... $ 230,629 $(93,716) $(152,363)
Inventories............................................... 30,862 (21,452) 7,471
Prepaid and other current assets.......................... (25,524) 2,352 (7,523)
Intangible assets......................................... (5,226)
Other assets.............................................. 162 (1,410) 1,164
Increase (decrease) in:
Accounts payable.......................................... (82,075) 18,723 (6,276)
Accrued gas payable....................................... (197,916) 143,457 206,178
Accrued expenses.......................................... (1,576) 4,978 (27,788)
Accrued interest.......................................... 14,234 8,743 863
Other current liabilities................................. 3,073 6,540 5,884
Other liabilities......................................... (9,012) 8,122 296
--------- -------- ---------
Net effect of changes in operating accounts................. $ (37,143) $ 71,111 $ 27,906
========= ======== =========
Cash payments for interest, net of $2,946,
$3,277 and $153 capitalized in 2001,
2000 and 1999, respectively............................... $ 37,536 $ 17,774 $ 15,780
========= ======== =========

On April 1, 2001, we paid approximately $225.7 million in cash to Shell to
acquire Acadian Gas. This acquisition was recorded using the purchase method of
accounting and as a result the initial purchase price has been allocated to
various balance sheet asset and liability accounts. For additional information
regarding the acquisition of Acadian Gas (including the allocation of the
purchase price), see Note 2.

On August 1, 1999, we paid $166 million in cash and issued 29.0 million
non-distribution bearing, convertible Special Units (valued at $210.4 million at
time of issuance) to Shell in connection with the TNGL acquisition. Also, we
issued 12.0 million additional non-distribution bearing, convertible Special
Units to Shell based on Shell having met certain performance criteria in
calendar years 2000 and 2001. Of the 12.0 million additional Special Units
issued, 6.0 million were issued in 2000 and 6.0 million during 2001. The value
of the Special Units issued in 2000 was $55.2 million while the value of those
issued during 2001 was $117.1 million, both values determined using present
value techniques. The $172.3 million combined value of these two issues
increased the overall purchase price of the TNGL acquisition and was allocated
to the intangible asset, Shell Processing Agreement. In addition, during 2000,
we increased the value of the Shell Processing Agreement by $25.2 million for
non-cash purchase accounting adjustments related to the acquisition. The offset
to such adjustment was various working capital accounts. With these adjustments
completed, the final purchase price of TNGL increased to $528.8 million.

On July 1, 1999, we paid approximately $42.1 million in cash to EPCO and
Kinder Morgan and assumed approximately $4 million of debt in connection with
the acquisition of an additional interest in the Mont Belvieu NGL fractionation
facility.

As a result of our adoption of SFAS No. 133 on January 1, 2001, we record
various financial instruments relating to commodity positions and interest rate
swaps at their respective fair values using mark-to-market accounting. During
2001, we recognized a net $5.7 million in non-cash mark-to-market income
F-39

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

related to increases in the fair value of these financial instruments. See Note
13 for additional information on our financial instruments.

13. FINANCIAL INSTRUMENTS

We are exposed to financial market risks, including changes in commodity
prices in our natural gas and NGL businesses and in interest rates with respect
to a portion of our debt obligations. We may use financial instruments (i.e.,
futures, forwards, swaps, options, and other financial instruments with similar
characteristics) to mitigate the risks of certain identifiable and anticipated
transactions, primarily in its Processing segment. In general, the types of
risks hedged are those relating to the variability of future earnings and cash
flows caused by changes in commodity prices and interest rates. As a matter of
policy, we do not use financial instruments for speculative (or trading)
purposes.

Our disclosure of fair value estimates are determined using available
market information and appropriate valuation methodologies. We must use
considerable judgment, however, in interpreting market data and to develop the
related estimates of fair value. Accordingly, the estimates presented herein are
not necessarily indicative of the amounts that we could realize upon disposition
of the financial instruments. The use of different market assumptions and/or
estimation methodologies may have a material effect on our estimates of fair
value.

COMMODITY FINANCIAL INSTRUMENTS

Our Processing and Octane Enhancement segments are directly exposed to
commodity price risk through their respective business operations. The prices of
natural gas, NGLs and MTBE are subject to fluctuations in response to changes in
supply, market uncertainty and a variety of additional factors that are beyond
our control. In order to manage the risks associated with its Processing
segment, we may enter into swaps, forwards, commodity futures, options and other
commodity financial instruments with similar characteristics that are permitted
by contract or business custom to be settled in cash or with another financial
instrument. The primary purpose of these risk management activities is to hedge
exposure to price risks associated with natural gas, NGL production and
inventories, firm commitments and certain anticipated transactions. We do not
hedge our exposure to the MTBE markets. Also, in its Pipelines segment, we may
utilize a limited number of commodity financial instruments to manage the price
Acadian Gas charges certain of its customers for natural gas.

We have adopted a commercial policy to manage our exposure to the risks of
its natural gas and NGL businesses. The objective of this policy is to assist us
in achieving our profitability goals while maintaining a portfolio with an
acceptable level of risk, defined as remaining within the position limits
established by the General Partner. We enter into risk management transactions
to manage price risk, basis risk, physical risk or other risks related to its
commodity positions on both a short-term (less than 30 days) and long-term
basis, not to exceed 18 months. The General Partner oversees the our strategies
associated with physical and financial risks (such as those mentioned
previously), approves specific activities subject to the policy (including
authorized products, instruments and markets) and establishes specific
guidelines and procedures for implementing and ensuring compliance with the
policy.

On January 1, 2001, we adopted SFAS No. 133 (as amended and interpreted)
which required us to recognize the fair value of our commodity financial
instrument portfolio on the balance sheet based upon then current market
conditions. The fair market value of the then outstanding commodity financial
instruments portfolio was a net payable of $42.2 million (the "cumulative
transition adjustment") with an offsetting equal amount recorded in Other
Comprehensive Income ("OCI"). The amount in OCI was fully reclassified to
earnings during 2001.

F-40

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

At December 31, 2001, we had open commodity financial instruments that
settle at different dates extending through December 2002. We routinely review
our outstanding instruments in light of current market conditions. If market
conditions warrant, some instruments may be closed out in advance of their
contractual settlement dates thus realizing income or loss depending on the
specific exposure. When this occurs, we may enter into a new commodity financial
instrument to reestablish the economic hedge to which the closed instrument
relates.

These commodity financial instruments may not qualify for hedge accounting
treatment under the specific guidelines of SFAS No. 133 because of
ineffectiveness. A hedge is normally regarded as effective if, among other
things, at inception and throughout the term of the financial instrument, we
could expect changes in the fair value of the hedged item to be almost fully
offset by the changes in the fair value of the financial instrument. Currently,
a majority of our commodity financial instruments do not qualify as effective
hedges under the guidelines of SFAS No. 133, with the result being that changes
in the fair value of these positions are recorded on the balance sheet and in
earnings through mark-to-market accounting. The use of mark-to-market accounting
for these commodity financial instruments results in a degree of non-cash
earnings volatility that is dependent upon changes in the underlying commodity
prices. Even though these financial instruments do not qualify for hedge
accounting treatment under the specific guidelines of SFAS No. 133, we continue
to view these financial instruments as hedges inasmuch as this was the intent
when such contracts were executed. This characterization is consistent with the
actual economic performance of these contracts to date and we expect these
financial instruments to continue to mitigate (or offset) commodity price risk
in future. The specific accounting for these contracts, however, is consistent
with the requirements of SFAS No. 133.

We recognized income of $101.3 million in 2001 from our commodity hedging
activities that is treated as a decrease of operating costs and expenses in the
Statements of Consolidated Operations. Of this amount, $95.7 million was
realized during 2001. The remaining $5.6 million represents mark-to-market
income on positions open at December 31, 2001 (based on market prices at that
date).

INTEREST RATE SWAPS

Our interest rate exposure results from variable-rate borrowings from
commercial banks and fixed-rate borrowings pursuant to its Senior Notes and MBFC
Loan. We manage its exposure to changes in interest rates by utilizing interest
rate swaps. The objective of holding interest rate swaps is to manage debt
service costs by converting a portion of fixed-rate debt into variable-rate debt
or a portion of variable-rate debt into fixed-rate debt. An interest rate swap,
in general, requires one party to pay a fixed-rate on the notional amount while
the other party pays a floating-rate based on the notional amount. We believe
that it is prudent to maintain an appropriate mixture of variable-rate and
fixed-rate debt.

We assess interest rate cash flow risk by identifying and measuring changes
in interest rate exposure that impact future cash flows and evaluating hedging
opportunities. We use analytical techniques to measure its exposure to
fluctuations in interest rates, including cash flow sensitivity analysis to
estimate the expected impact of changes in interest rates on our future cash
flows.

The General Partner oversees the strategies associated with financial risks
and approves instruments that are appropriate for our requirements. The notional
amount of an interest rate swap does not represent exposure to credit loss. We
monitor our positions and the credit ratings of counterparties. Management
believes the risk of incurring a credit loss is remote, and that if incurred,
such losses would be immaterial.

At December 31, 2001, we had one interest rate swap outstanding having a
notional amount of $54 million extending through March 2010. Under this
agreement, we exchanged a fixed-rate of 8.70% for a variable-rate that ranged
from 4.28% to 7.66% during 2001 (the variable-rate may fluctuate over time
depending on market conditions). If it elects to do so, the counterparty may
terminate this swap in March

F-41

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

2003. During 2001, two counterparties terminated their swap agreements with us
either through early termination clauses or negotiation. The closed agreements
had a combined notional amount of $100 million.

Upon adoption of SFAS No. 133, we were required to recognize the fair value
of the interest rate swaps on the balance sheet offset by an equal increase in
the fair value of associated fixed-rate debt and, therefore, the adoption of the
new standard had no impact on earnings at transition. Subsequently, it was
determined that the interest rate swaps would not qualify for hedge accounting
treatment under SFAS No. 133 due to differences between the maturity dates of
the swaps and the associated fixed-rate debt; thus, changes in the fair value of
the interest rate swaps would be recorded in earnings through mark-to-market
accounting (i.e., the interest rate swaps were deemed ineffective under SFAS No.
133). As a result, the increase in fair value of the associated fixed-rate debt
will not be adjusted for future changes in its fair value and will be amortized
to earnings over the remaining life of the underlying debt instrument, which
approximates 10 years.

We recognized income of $13.2 million in 2001 from our interest rate swaps
that is treated as a reduction of interest expense in the Statements of
Consolidated Operations. Of this amount, $2.3 million represents the
mark-to-market income on the remaining swap at December 31, 2001 (estimated fair
value of swap based on market rates at that date). The balance of $10.9 million
was realized during 2001.

The $2.3 million estimated fair value of the remaining swap at December 31,
2001 is based on market rates (assuming its early termination option in March
2003 is exercised). The fair value estimate represents the amount that we would
receive to terminate the swap, taking into consideration current interest rates.

FUTURE ISSUES CONCERNING SFAS NO. 133

Due to the complexity of SFAS No. 133, the FASB is continuing to provide
guidance about implementation issues. Since this guidance is still continuing,
our initial conclusions regarding the application of SFAS No. 133 upon adoption
may be altered. As a result, additional SFAS No. 133 transition adjustments may
be recorded in future periods as we adopt new FASB interpretations.

OTHER FAIR VALUE INFORMATION

Cash and cash equivalents, Accounts Receivable, Accounts Payable and
Accrued Expenses are carried at amounts which reasonably approximate their fair
value at year end due to their short-term nature.

Fixed-rate long term debt. The estimated fair value of our fixed-rate
long-term debt is estimated based on quoted market prices for debt of similar
terms and maturities. No variable rate long-term debt was outstanding at
December 31, 2001.

F-42

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following table summarizes the estimated fair values of our various
financial instruments at December 31, 2001 and 2000:

2001 2000
------------------- -------------------
CARRYING FAIR CARRYING FAIR
FINANCIAL INSTRUMENTS AMOUNT VALUE AMOUNT VALUE
--------------------- -------- -------- -------- --------

Financial assets:
Cash and cash equivalents........................ $137,823 $137,823 $ 60,409 $ 60,409
Accounts receivable(1)........................... 261,302 261,302 415,618 415,618
Commodity financial instruments(2)............... 9,992 9,992 n/a n/a
Interest rate swaps(3)........................... 2,324 2,324 n/a n/a
Financial liabilities:
Accounts payable and accrued expenses............ 364,452 364,452 561,688 561,688
Fixed-rate debt (principal amount)............... 854,000 894,005 404,000 423,836
Commodity financial instruments(4)............... 3,206 3,206 725 705
Off-balance sheet instruments:(5)
Interest rate swaps receivable................... n/a n/a 2,030 2,030
Commodity financial instruments payable.......... n/a n/a 40,020 39,266

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

(1) 2001 includes a $1.2 million receivable related to the remaining interest
rate swap.

(2) 2001 values are a component of other current assets in our consolidated
balance sheet.

(3) 2001 value represents the aggregate fair value of the remaining swap (net of
the $1.2 million receivable reflected under accounts receivable). $1.3
million of the $2.3 million mark-to-market value is a component of other
current assets while the balance of $1.0 million is reflected in other
assets.

(4) 2001 values are a component of other current liabilities in our consolidated
balance sheet.

(5) Prior to our adoption of SFAS No. 133 on January 1, 2001, interest rate
swaps and certain commodity financial instruments were off-balance sheet
instruments. As a result of SFAS No. 133, these financial instruments are
now recorded as part of balance sheet assets and liabilities, as the
circumstances warrant.

14. SIGNIFICANT CONCENTRATIONS OF RISK

CREDIT RISK. A substantial portion of our revenues are derived from
various companies in the NGL and petrochemical industry, located in the United
States. Although this concentration could affect our overall exposure to credit
risk since these customers might be affected by similar economic or other
conditions, management believes we are exposed to minimal credit risk, since the
majority of our business is conducted with major companies within the industry
including those with whom it has joint operations. We do not require collateral
for our accounts receivable.

NATURE OF OPERATIONS. We are subject to a number of risks inherent in the
industry in which it operates, including fluctuating gas and liquids prices. Our
financial condition and results of operation will depend significantly on the
prices received for NGLs and the price paid for gas consumed in the NGL
extraction process. These prices are subject to fluctuations in response to
changes in supply, market uncertainty, weather and a variety of additional
factors that are beyond our control.

In addition, we must obtain access to new natural gas volumes along the
Gulf Coast of the United States for its processing business in order to maintain
or increase gas plant throughput levels to offset natural declines in field
reserves. The number of wells drilled by third-parties to obtain new volumes
will depend on,

F-43

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

among other factors, the price of gas and oil, the energy policy of the federal
government and the availability of foreign oil and gas, none of which is in our
control.

The products that we process, sell or transport are principally used as
feedstocks in petrochemical manufacturing and in the production of motor
gasoline and as fuel for residential and commercial heating. A reduction in
demand for our products or services by industrial customers, whether because of
general economic conditions, reduced demand for the end products made with NGL
products, increased competition from petroleum-based products due to pricing
differences, adverse weather conditions, governmental regulations affecting
prices and production levels of natural gas or the content of motor gasoline or
other reasons, could have a negative impact on our results of operation. A
material decrease in natural gas production or crude oil refining, as a result
of depressed commodity prices or otherwise, or a decrease in imports of mixed
butanes, could result in a decline in volumes processed and sold by us.

COUNTERPARTY RISK. From time to time, we have credit risk with our
counterparties in terms of settlement risk associated with its financial
instruments. On all transactions where we are exposed to credit risk, we analyze
the counterparty's financial condition prior to entering into an agreement,
establish credit and/or margin limits and monitor the appropriateness of these
limits on an ongoing basis.

In December 2001, Enron Corp., or Enron, filed for protection under Chapter
11 of the U.S. Bankruptcy Code. As a result, we established a $10.6 million
reserve for amounts owed to us by Enron North America, a subsidiary of Enron.
Enron North America was our counterparty to various past financial instruments.
The Enron amounts were unsecured and the amount that we may ultimately recover,
if any, is not presently determinable. Of the reserve amount established, $4.3
million was attributable to various unbilled commodity financial instrument
positions that terminate during the first quarter of 2002.

15. SEGMENT INFORMATION

Operating segments are components of a business about which separate
financial information is available and that are regularly evaluated by the chief
operating decision maker in deciding how to allocate resources and in assessing
performance. Generally, financial information is required to be reported on the
basis that it is used internally for evaluating segment performance and deciding
how to allocate resources to segments.

We have five reportable operating segments: Fractionation, Pipelines,
Processing, Octane Enhancement and Other. The reportable segments are generally
organized according to the type of services rendered (or process employed) and
products produced and/or sold, as applicable. The segments are regularly
evaluated by the Chief Executive Officer of the General Partner. Fractionation
primarily includes NGL fractionation, isomerization, and polymer grade propylene
fractionation services. Pipelines consists of both liquids and natural gas
pipeline systems, storage and import/export terminal services. Processing
includes the natural gas processing business and its related merchant
activities. Octane Enhancement represents our equity interest in BEF, a facility
that produces motor gasoline additives to enhance octane (currently producing
MTBE). The Other operating segment consists of fee-based marketing services and
other plant support functions.

We evaluate segment performance based on gross operating margin. Gross
operating margin reported for each segment represents operating income before
depreciation and amortization, lease expense obligations retained by EPCO, gains
and losses on the sale of assets and general and administrative expenses. In
addition, segment gross operating margin is exclusive of interest expense,
interest income (from unconsolidated affiliates or others), dividend income from
unconsolidated affiliates, minority interest, extraordinary charges and other
income and expense transactions.

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

enables us to achieve favorable economies of scale relative to the level of
investment and business risk assumed versus what we could accomplish on a stand
alone basis. Many of these businesses perform supporting or complementary roles
to our other business operations. For example, we use the Promix NGL
fractionator to process NGLs extracted by our gas plants. The NGLs received from
Promix then can be sold by our merchant businesses. Another example would be our
relationship with the BEF MTBE facility. Our isomerization facilities process
normal butane for this plant and our HSC pipeline transports MTBE for delivery
to BEF's storage facility on the Houston Ship Channel.

Consolidated property, plant and equipment and investments in and advances
to unconsolidated affiliates are allocated to each segment on the basis of each
asset's or investment's principal operations. The principal reconciling item
between consolidated property, plant and equipment and segment property is
construction-in-progress. Segment property represents those facilities and
projects that contribute to gross operating margin and is net of accumulated
depreciation on these assets. Since assets under construction do not generally
contribute to segment gross operating margin, these assets are not included in
the operating segment totals until they are deemed operational.

Segment gross operating margin is inclusive of intersegment revenues, which
are generally based on transactions made at market-related rates. These revenues
have been eliminated from the consolidated totals.

F-45

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Information by operating segment, together with reconciliations to the
consolidated totals, is presented in the following table:

OPERATING SEGMENTS
----------------------------------------------------------------------
OCTANE ADJS. AND CONSOL.
FRACTIONATION PIPELINES PROCESSING ENHANCEMENT OTHER ELIMS. TOTALS
------------- ---------- ------------------ ----------- ------ --------- ----------

Revenues from external
customers:
2001.................... $324,276 $403,430 $2,424,281 $2,382 $3,154,369
2000.................... 396,995 28,172 2,620,975 2,878 3,049,020
1999.................... 247,579 11,498 1,073,171 731 1,332,979
Intersegment revenues:
2001.................... 158,853 89,907 683,524 389 $(932,673)
2000.................... 177,963 55,690 630,155 375 (864,183)
1999.................... 118,103 43,688 216,720 444 (378,955)
Equity income in
unconsolidated affiliates:
2001.................... 6,945 12,742 $ 5,671 25,358
2000.................... 6,391 7,321 10,407 24,119
1999.................... 1,566 3,728 8,183 13,477
Total revenues:
2001.................... 490,074 506,079 3,107,805 5,671 2,771 (932,673) 3,179,727
2000.................... 581,349 91,183 3,251,130 10,407 3,253 (864,183) 3,073,139
1999.................... 367,248 58,914 1,289,891 8,183 1,175 (378,955) 1,346,456
Gross operating margin by
segment:
2001.................... 118,610 96,569 154,989 5,671 944 376,783
2000.................... 129,376 56,099 122,240 10,407 2,493 320,615
1999.................... 110,424 31,195 28,485 8,183 908 179,195
Segment assets:
2001.................... 357,122 717,348 124,555 8,921 98,844 1,306,790
2000.................... 356,207 448,920 126,895 8,942 34,358 975,322
1999.................... 362,198 249,453 122,495 113 32,810 767,069
Investments in and advances
to unconsolidated
affiliates:
2001.................... 93,329 216,029 33,000 55,843 398,201
2000.................... 105,194 102,083 33,000 58,677 298,954
1999.................... 99,110 85,492 33,000 63,004 280,606

Our revenues are derived from a wide customer base. Shell accounted for
10.5% of consolidated revenues in 2001 (up from 9.5% of consolidated revenues in
2000). No single external customer accounted for more than 10% of consolidated
revenues during 2000 and 1999. Approximately 80% of our revenues from Shell
during 2001 and 2000 are attributable to sales of NGL products which are
recorded in our Processing segment. No single third-party customer provided more
than 10% of consolidated revenues during 2000 or 1999. All consolidated revenues
were earned in the United States. Our operations are centered along the Texas,
Louisiana and Mississippi Gulf Coast areas.

F-46

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

A reconciliation of segment gross operating margin to consolidated income
before minority interest follows:

FOR YEAR ENDED DECEMBER 31,
------------------------------
2001 2000 1999
-------- -------- --------

Total segment gross operating margin................. $376,783 $320,615 $179,195
Depreciation and amortization...................... (48,775) (35,621) (23,664)
Retained lease expense, net........................ (10,414) (10,645) (10,557)
(Gain) loss on sale of assets...................... 390 (2,270) (123)
Selling, general and administrative................ (30,296) (28,345) (12,500)
-------- -------- --------
Consolidated operating income........................ 287,688 243,734 132,351
Interest expense................................... (52,456) (33,329) (16,439)
Interest income from unconsolidated affiliates..... 31 1,787 1,667
Dividend income from unconsolidated affiliates..... 3,462 7,091 3,435
Interest income -- other........................... 7,029 3,748 886
Other, net......................................... (1,104) (272) (379)
-------- -------- --------
Consolidated income before minority interest......... $244,650 $222,759 $121,521
======== ======== ========

16. SUBSEQUENT EVENTS (UNAUDITED)

PURCHASE OF DIAMOND-KOCH STORAGE ASSETS. On January 17, 2002, we completed
the purchase of various hydrocarbon storage assets from affiliates of Valero
Energy Corporation and Koch Industries, Inc. The purchase price of the storage
assets was approximately $129 million (subject to certain post-closing
adjustments) and will be accounted for as an asset purchase. The purchase price
was funded entirely by internally generated funds.

The storage facilities include 30 salt dome storage caverns with a total
useable capacity of 68 million barrels, local distribution pipelines and related
equipment. The facilities provide storage services for mixed natural gas
liquids, ethane, propane, butanes, natural gasoline and olefins (such as
ethylene), polymer grade propylene, chemical grade propylene and refinery grade
propylene. The facilities are located in Mont Belvieu, Texas.

PURCHASE OF DIAMOND-KOCH PROPYLENE FRACTIONATION ASSETS. On February 1,
2002, we completed the purchase of various propylene fractionation assets from
affiliates of Valero Energy Corporation and Koch Industries, Inc. and certain
inventories of refinery grade propylene, propane and polymer grade propylene
owned by such affiliates. The purchase price of these assets was approximately
$238.5 million (subject to certain post-closing adjustments) and will be
accounted for as an asset purchase. The purchase price was funded by a drawdown
on our existing revolving bank credit facilities.

The propylene fractionation assets being acquired include a 66.67% interest
in a polymer grade propylene fractionation facility located in Mont Belvieu,
Texas, a 50.0% interest in an entity which owns a polymer grade propylene export
terminal located on the Houston Ship Channel in La Porte, Texas and varying
interests in several supporting distribution pipelines and related equipment.
The propylene fractionation facility has the gross capacity to produce
approximately 41,000 barrels per day of polymer grade propylene.

Both the storage and propylene fractionation acquisitions have been
approved by the requisite regulatory authorities. The post-closing purchase
price adjustments of both transactions are expected to be completed during the
second quarter of 2002.

F-47

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

TWO-FOR-ONE SPLIT OF LIMITED PARTNER UNITS. On February 27, 2002, the
General Partner approved a two-for-one split for each class of our partnership
Units. The partnership Unit split was accomplished by distributing one
additional partnership Unit for each partnership Unit outstanding to holders of
record on April 30, 2002. The Units were distributed on May 15, 2002. All
references to number of Units or earnings per Unit contained in this document
reflect the Unit split, unless otherwise indicated.

17. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER
-------- -------- -------- --------

FOR THE YEAR ENDED DECEMBER 31, 2000:
Revenues......................................... $753,724 $604,010 $721,863 $993,542
Operating income................................. 75,434 50,046 55,864 62,390
Income before minority interest.................. 70,156 46,026 50,777 55,800
Minority interest................................ (709) (466) (514) (564)
Net income....................................... 69,447 45,560 50,263 55,236
Net income per Unit, basic....................... $ 0.52 $ 0.34 $ 0.37 $ 0.41
Net income per Unit, diluted..................... $ 0.43 $ 0.28 $ 0.30 $ 0.33
FOR THE YEAR ENDED DECEMBER 31, 2001:
Revenues......................................... $838,326 $968,447 $729,618 $643,336
Operating income................................. 54,417 109,071 87,406 36,794
Income before minority interest.................. 52,804 93,975 75,774 22,097
Minority interest................................ (534) (944) (767) (227)
Net income....................................... 52,270 93,031 75,007 21,870
Net income per Unit, basic....................... $ 0.38 $ 0.68 $ 0.52 $ 0.14
Net income per Unit, diluted..................... $ 0.31 $ 0.55 $ 0.43 $ 0.12

Earnings in the fourth quarter of 2001 declined relative to the third
quarter of 2001 primarily due to a decrease in the mark-to-market value of our
commodity financial instruments. The decrease was due to (1) the settlement of
certain positions during the fourth quarter, (2) a decrease in the relative
amount of hedging activities at December 31, 2001 versus September 30, 2001 and
(3) a decrease in the value of certain outstanding financial instruments from
September 30, 2001 due to changes in natural gas prices.

F-48

ENTERPRISE PRODUCTS PARTNERS L.P.

CONSOLIDATED BALANCE SHEETS
(DOLLARS IN THOUSANDS)

JUNE 30, DECEMBER 31,
2002 2001
----------- ------------
(UNAUDITED)

ASSETS
CURRENT ASSETS
Cash and cash equivalents (includes restricted cash of
$5,034 at June 30, 2002 and $5,752 at December 31,
2001).................................................. $ 7,929 $ 137,823
Accounts and notes receivable -- trade, net of allowance
for doubtful accounts of $21,098 at June 30, 2002 and
$20,642 at December 31, 2001........................... 284,021 256,927
Accounts receivable -- affiliates......................... 1,740 4,375
Inventories............................................... 153,280 69,443
Prepaid and other current assets.......................... 34,089 50,207
---------- ----------
Total current assets.............................. 481,059 518,775
PROPERTY, PLANT AND EQUIPMENT, NET.......................... 1,570,571 1,306,790
INVESTMENTS IN AND ADVANCES TO UNCONSOLIDATED AFFILIATES.... 403,070 398,201
INTANGIBLE ASSETS, NET OF ACCUMULATED AMORTIZATION OF
$18,235 AT JUNE 30, 2002 AND $13,084 AT DECEMBER 31,
2001...................................................... 249,222 202,226
GOODWILL.................................................... 81,543
OTHER ASSETS................................................ 6,911 5,201
---------- ----------
TOTAL............................................. $2,792,376 $2,431,193
========== ==========
LIABILITIES AND PARTNERS' EQUITY
CURRENT LIABILITIES
Accounts payable -- trade................................. $ 70,716 $ 54,269
Accounts payable -- affiliates............................ 21,233 29,885
Accrued gas payables...................................... 303,983 233,536
Accrued expenses.......................................... 12,961 22,460
Accrued interest.......................................... 24,676 24,302
Other current liabilities................................. 70,672 44,764
---------- ----------
Total current liabilities......................... 504,241 409,216
LONG-TERM DEBT.............................................. 1,223,552 855,278
OTHER LONG-TERM LIABILITIES................................. 7,919 8,061
MINORITY INTEREST........................................... 10,818 11,716
COMMITMENTS AND CONTINGENCIES
PARTNERS' EQUITY
Common Units (112,954,266 Units outstanding at June 30,
2002 and 102,721,830 at December 31, 2001)............. 589,504 651,872
Subordinated Units (32,114,804 Units outstanding at June
30, 2002 and 42,819,740 December 31, 2001)............. 165,818 193,107
Special Units (29,000,000 Units outstanding at June 30,
2002 and December 31, 2001)............................ 296,634 296,634
Treasury Units, at cost (799,700 Common Units outstanding
at June 30, 2002 and 327,200 at December 31, 2001)..... (16,736) (6,222)
General Partner........................................... 10,626 11,531
---------- ----------
Total Partners' Equity............................ 1,045,846 1,146,922
---------- ----------
TOTAL............................................. $2,792,376 $2,431,193
========== ==========

See Notes to Unaudited Consolidated Financial Statements
F-49

ENTERPRISE PRODUCTS PARTNERS L.P.

STATEMENTS OF CONSOLIDATED OPERATIONS
(DOLLARS IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)
(UNAUDITED)

THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------- -----------------------
2002 2001 2002 2001
-------- -------- ---------- ----------

REVENUES
Revenues from consolidated operations........... $786,257 $959,397 $1,448,311 $1,795,712
Equity income in unconsolidated affiliates...... 7,068 9,050 16,295 11,061
-------- -------- ---------- ----------
Total................................. 793,325 968,447 1,464,606 1,806,773
-------- -------- ---------- ----------
COST AND EXPENSES
Operating costs and expenses.................... 745,621 851,639 1,410,044 1,629,380
Selling, general and administrative............. 7,740 7,737 15,702 13,905
-------- -------- ---------- ----------
Total................................. 753,361 859,376 1,425,746 1,643,285
-------- -------- ---------- ----------
OPERATING INCOME................................ 39,964 109,071 38,860 163,488
OTHER INCOME (EXPENSE)
Interest expense................................ (19,032) (16,331) (37,545) (23,318)
Interest income from unconsolidated
affiliates.................................... 62 7 92 31
Dividend income from unconsolidated
affiliates.................................... 1,242 -- 2,196 1,632
Interest income -- other........................ 241 1,479 1,575 5,477
Other, net...................................... 46 (251) (31) (531)
-------- -------- ---------- ----------
Other income (expense)................ (17,441) (15,096) (33,713) (16,709)
-------- -------- ---------- ----------
INCOME BEFORE MINORITY INTEREST................. 22,523 93,975 5,147 146,779
MINORITY INTEREST............................... (203) (944) (30) (1,478)
-------- -------- ---------- ----------
NET INCOME...................................... $ 22,320 $ 93,031 $ 5,117 $ 145,301
======== ======== ========== ==========
ALLOCATION OF NET INCOME TO:
Limited partners...................... $ 19,672 $ 91,643 $ 1,223 $ 142,931
======== ======== ========== ==========
General partner....................... $ 2,648 $ 1,388 $ 3,894 $ 2,370
======== ======== ========== ==========
BASIC EARNINGS PER UNIT
Income before minority interest....... $ 0.14 $ 0.68 $ 0.01 $ 1.07
======== ======== ========== ==========
Net income per Common and Subordinated
unit................................ $ 0.14 $ 0.68 $ 0.01 $ 1.06
======== ======== ========== ==========
DILUTED EARNINGS PER UNIT
Income before minority interest....... $ 0.11 $ 0.55 $ 0.01 $ 0.86
======== ======== ========== ==========
Net income per Common, Subordinated
and Special unit.................... $ 0.11 $ 0.54 $ 0.01 $ 0.85
======== ======== ========== ==========

See Notes to Unaudited Consolidated Financial Statements
F-50

ENTERPRISE PRODUCTS PARTNERS L.P.

STATEMENTS OF CONSOLIDATED CASH FLOWS
(DOLLARS IN THOUSANDS)
(UNAUDITED)

SIX MONTHS ENDED
JUNE 30,
---------------------
2002 2001
--------- ---------

OPERATING ACTIVITIES
Net income.................................................. $ 5,117 $ 145,301
Adjustments to reconcile net income to cash flows provided
by (used for) operating activities:
Depreciation and amortization............................. 35,349 23,234
Equity in income of unconsolidated affiliates............. (16,295) (11,061)
Distributions received from unconsolidated affiliates..... 29,113 13,212
Leases paid by EPCO....................................... 4,534 5,267
Minority interest......................................... 30 1,478
Loss (gain) on sale of assets............................. 12 (387)
Changes in fair market value of financial instruments (see
Note 13)............................................... 19,702 (55,880)
Net effect of changes in operating accounts............... (32,379) (30,569)
--------- ---------
Operating activities cash flows........................ 45,183 90,595
--------- ---------
INVESTING ACTIVITIES
Capital expenditures........................................ (26,755) (57,090)
Proceeds from sale of assets................................ 12 563
Business acquisitions, net of cash received................. (394,775) (225,665)
Investments in and advances to unconsolidated affiliates.... (10,137) (115,282)
--------- ---------
Investing activities cash flows........................ (431,655) (397,474)
--------- ---------
FINANCING ACTIVITIES
Long-term debt borrowings................................... 538,000 449,716
Long-term debt repayments................................... (170,000)
Debt issuance costs......................................... (418) (3,125)
Cash dividends paid to partners............................. (99,010) (76,112)
Cash dividends paid to minority interest by Operating
Partnership............................................... (1,014) (783)
Cash contributions from EPCO to minority interest........... 86 53
Treasury Units purchased.................................... (11,066)
Increase in restricted cash................................. 718 (7,321)
--------- ---------
Financing activities cash flows........................ 257,296 362,428
--------- ---------
NET CHANGE IN CASH AND CASH EQUIVALENTS..................... (129,176) 55,549
CASH AND CASH EQUIVALENTS, JANUARY 1........................ 132,071 60,409
--------- ---------
CASH AND CASH EQUIVALENTS, JUNE 30.......................... $ 2,895 $ 115,958
========= =========

See Notes to Unaudited Consolidated Financial Statements
F-51

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

1. GENERAL

In the opinion of Enterprise Products Partners L.P., the accompanying
unaudited consolidated financial statements include all adjustments consisting
of normal recurring accruals necessary for a fair presentation of its
consolidated financial position as of June 30, 2002 and consolidated results of
operations and cash flows for the three and six months ended June 30, 2002 and
2001. Within these footnote disclosures of Enterprise Products Partners L.P.,
references to "we", "us", "our" or "the Company" shall mean the consolidated
financial statements of Enterprise Products Partners L.P.

References to "Operating Partnership" shall mean the consolidated financial
statements of our primary operating subsidiary, Enterprise Products Operating
L.P., which are included elsewhere in this combined report on Form 10-Q. We own
98.9899% of the Operating Partnership and act as guarantor of certain debt
obligations of the Operating Partnership. Our General Partner, Enterprise
Products GP, LLC, owns the remaining 1.0101% of the Operating Partnership.
Essentially all of our assets, liabilities, revenues and expenses are recorded
at the Operating Partnership level in our consolidated financial statements.

Although we believe the disclosures in these financial statements are
adequate to make the information presented not misleading, certain information
and footnote disclosures normally included in annual financial statements
prepared in accordance with generally accepted accounting principles have been
condensed or omitted pursuant to the rules and regulations of the SEC. These
unaudited financial statements should be read in conjunction with our annual
report on Form 10-K (File No. 1-14323) for the year ended December 31, 2001.

The results of operations for the three and six months ended June 30, 2002
are not necessarily indicative of the results to be expected for the full year.

Dollar amounts presented within these footnote disclosures are stated in
thousands of dollars, unless otherwise indicated.

Certain abbreviated entity names and other capitalized terms are described
within the glossary of this quarterly report on Form 10-Q.

TWO-FOR-ONE SPLIT OF LIMITED PARTNER UNITS

On February 27, 2002, the General Partner approved a two-for-one split for
each class of our partnership Units. The partnership Unit split was accomplished
by distributing one additional partnership Unit for each partnership Unit
outstanding to holders of record on April 30, 2002. The Units were distributed
on May 15, 2002. All references to number of Units or earnings per Unit
contained in this document reflect the Unit split, unless otherwise indicated.

2. BUSINESS ACQUISITIONS

ACQUISITION OF DIAMOND-KOCH PROPYLENE FRACTIONATION BUSINESS IN FEBRUARY 2002

In February 2002, we purchased various propylene fractionation assets and
certain inventories of refinery grade propylene, propane, and polymer grade
propylene from Diamond-Koch. These include a 66.7% interest in a polymer grade
propylene fractionation facility located in Mont Belvieu, Texas (the "Mont
Belvieu III" facility), a 50% interest in an entity which owns a polymer grade
propylene export terminal located on the Houston Ship Channel in La Porte,
Texas, and varying interests in several supporting distribution pipelines and
related equipment. Mont Belvieu III has the capacity to produce approximately 41
MBPD of polymer grade propylene. These assets are part of our Mont Belvieu
propylene fractionation operations, which is part of the Fractionation segment.
The purchase price of $239.0 million was funded by a drawdown on our Multi-Year
and 364-Day Credit Facilities (see Note 8).

F-52

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

ACQUISITION OF DIAMOND-KOCH STORAGE BUSINESS IN JANUARY 2002

In January 2002, we purchased various hydrocarbon storage assets from
Diamond-Koch. The storage facilities consist of 30 salt dome storage caverns
with a useable capacity of 68 million barrels, local distribution pipelines and
related equipment. The facilities provide storage services for mixed natural gas
liquids, ethane, propane, butanes, natural gasoline and olefins (such as
ethylene), polymer grade propylene, chemical grade propylene and refinery grade
propylene.

The facilities are located in Mont Belvieu, Texas and serve the largest
petrochemical and refinery complex in the United States. Collectively, these
facilities represent the largest underground storage operation of its kind in
the world. The size and location of the business provide it with a competitive
position to increase its services to expanding Gulf Coast petrochemical
complexes. These assets are part of our Mont Belvieu storage operations, which
is part of the Pipelines segment. The purchase price of $129.6 million was
funded by utilizing cash on hand.

ALLOCATION OF PURCHASE PRICE OF DIAMOND-KOCH ACQUISITIONS

The Diamond-Koch acquisitions were accounted for under the purchase method
of accounting and, accordingly, the purchase price of each has been allocated to
the assets acquired and liabilities assumed based on their estimated fair values
as follows:

ESTIMATED FAIR VALUES AT
----------------------------
FEB. 1, 2002
PROPYLENE JAN. 1, 2002
FRACTIONATION STORAGE TOTAL
------------- ------------ --------

Inventories....................................... $ 4,994 $ 4,994
Prepaid and other current assets.................. 3,148 $ 890 4,038
Property, plant and equipment..................... 96,772 120,571 217,343
Investments in unconsolidated affiliates.......... 7,550 7,550
Intangible assets (see Note 7).................... 53,000 8,127 61,127
Goodwill (see Note 7)............................. 73,686 73,686
Current liabilities............................... (107) (107)
-------- -------- --------
Total purchase price......................... $239,043 $129,588 $368,631
======== ======== ========

The fair value estimates were developed by independent appraisers using
recognized business valuation techniques. The allocation of the purchase price
is preliminary pending the results of a repermitting process expected to be
complete during the fourth quarter of 2002.

The purchase price paid for the propylene fractionation business resulted
in $73.7 million in goodwill. The goodwill primarily represents the value
management has attached to future earnings improvements and to the strategic
location of the assets. Earnings from the propylene business are expected to
improve substantially from the last few years with the years 2003 and 2004
projected to be peak years in the petrochemical business cycle. Additionally,
the demand for chemical grade and polymer grade propylene is forecast to grow at
an average of 4.4% per year from 2002 to 2006.

The propylene fractionation assets are located in Mont Belvieu, Texas on
the Gulf Coast, the largest natural gas liquids and petrochemical marketplace in
the U.S. The assets have access to substantial supply from major Gulf Coast and
central U.S. producers of refinery grade propylene. The polymer grade products
produced at the facility have competitive advantages because of distribution
direct to customers via affiliated pipelines and through an affiliated export
facility.

F-53

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

ACADIAN GAS POST-CLOSING ADJUSTMENTS COMPLETED IN APRIL 2002

In April 2002, we finalized the post-closing purchase price adjustment
associated with our April 2001 acquisition of Acadian Gas. Acadian Gas was
acquired from an affiliate of Shell and is involved in the purchase, sale,
transportation and storage of natural gas in Louisiana. As a result, we paid
Shell $18.0 million for various working capital items, of which the majority
were related to natural gas inventories. The Acadian Gas acquisition was
accounted for under the purchase method of accounting and, accordingly, the
final purchase price has been allocated to the assets acquired and liabilities
assumed based on their estimated fair values at April 1, 2001 as follows:

Current assets.............................................. $ 83,123
Investments in unconsolidated affiliates.................... 2,723
Property, plant and equipment............................... 232,187
Current liabilities......................................... (72,896)
Other long-term liabilities................................. (1,460)
--------
Total purchase price................................... $243,677
========

PRO FORMA EFFECT OF DIAMOND-KOCH AND ACADIAN GAS BUSINESS ACQUISITIONS

As noted earlier, the Acadian Gas acquisition occurred on April 1, 2001. We
acquired Diamond-Koch's storage business on January 1, 2002 and its propylene
fractionation business on February 1, 2002. As a result, our actual fiscal 2002,
Statements of Consolidated Operations reflect the Diamond-Koch propylene
fractionation business and the Diamond-Koch storage business from their
respective acquisition dates through June 2002 and the results of Acadian Gas.
For the first six months of fiscal 2001, our Statements of Consolidated
Operations reflect only three months of Acadian Gas.

The following table presents unaudited pro forma financial information
incorporating the historical (pre-acquisition) financial results of the
propylene fractionation and storage assets we acquired from Diamond-Koch and
those of Acadian Gas that we acquired from Shell. This information is helpful in
gauging the possible impact that these acquisitions might have had on our
results of operations had they been completed on January 1, 2001 as opposed to
the actual dates that these acquisitions occurred. The pro forma information is
based upon data currently available to and certain estimates and assumptions
made by management and, as a result, are not necessarily indicative of our
financial results had the transactions actually occurred on these dates.
Likewise, the unaudited pro forma information is not necessarily indicative of
our future financial results.

F-54

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

SIX MONTHS ENDED
THREE MONTHS JUNE 30,
ENDED JUNE 30, -----------------------
2001 2002 2001
-------------- ---------- ----------

Revenues....................................... $1,043,671 $1,482,040 $2,195,472
Income before extraordinary item and minority
interest..................................... $ 90,424 $ 5,085 $ 147,174
Net income..................................... $ 89,517 $ 5,055 $ 145,692
Allocation of net income to
Limited partners............................. $ 88,128 $ 1,161 $ 143,322
General Partner.............................. $ 1,389 $ 3,894 $ 2,370
Units used in earnings per Unit calculations
Basic........................................ 135,334 145,404 135,334
Diluted...................................... 168,334 174,404 168,334
Income per Unit before minority interest
Basic........................................ $ 0.66 $ 0.01 $ 1.07
Diluted...................................... $ 0.53 $ 0.01 $ 0.86
Net income per Unit
Basic........................................ $ 0.65 $ 0.01 $ 1.06
Diluted...................................... $ 0.52 $ 0.01 $ 0.85

MINOR ACQUISITIONS INITIATED DURING THE SECOND QUARTER OF 2002

We initiated the purchase of an additional interest in our Mont Belvieu NGL
fractionation from ChevronTexaco and the acquisition of a gas processing plant
and NGL fractionator in Louisiana from Western Resources during the second
quarter of 2002. Due to the immaterial nature and incomplete status of these two
transactions, our discussion of each minor purchase is limited to the following:

Acquisition of ChevronTexaco's interest in our Mont Belvieu NGL
fractionator. In April 2002, we executed an agreement with an affiliate of
ChevronTexaco to purchase their 12.5% undivided ownership interest in our Mont
Belvieu, Texas NGL fractionator. The purchase price was approximately $8.0
million. The Mont Belvieu facility has a gross NGL fractionation capacity of 210
MBPD of which 26.2 MBPD was ChevronTexaco's net share. ChevronTexaco was
required to sell their 12.5% interest in a consent order by the FTC as a
condition of approving the merger between Chevron and Texaco. The effective date
of the purchase was June 1, 2002.

The other joint owners of the facility (affiliates of Duke Energy Field
Services and Burlington Resources Inc.) have the option to acquire their pro
rata share of the ChevronTexaco interest. These preferential purchase rights
expire on September 30, 2002. If the other joint owners fully exercise their
option to acquire their share of the interest, our ownership interest would
increase to approximately 71.4% from 62.5% currently. Should the joint owners
decline to exercise their options, we would own 75.0% of the facility. If the
other joint owners acquire any portion of their share of the ChevronTexaco
interest, our purchase price will be reduced accordingly. We expect to complete
this transaction during the third quarter of 2002.

Acquisition of gas processing and NGL fractionator assets from Western Gas
Resources, Inc. In June 2002, we executed an agreement to acquire a natural gas
processing plant, NGL fractionator and supporting assets (including contracts)
from Western Gas Resources, Inc. for $32.5 million plus certain post-closing
purchase price adjustments. The "Toca-Western" facilities are located in St.
Bernard Parish, Louisiana near our existing Toca natural gas processing plant.
The gas processing facility has a capacity of 160 MMcf/d and the NGL
fractionator can fractionate up to 14.2 MBPD of NGLs.

F-55

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

This purchase is subject to a preferential purchase right by the other
joint owners of our Yscloskey gas processing facility that expires on September
24, 2002. We are one of the largest owners in the Yscloskey plant with a 28.2%
ownership interest. Should any of the other owners exercise their respective
right to acquire their pro rata interest in the Toca-Western facilities, it
would reduce the ownership interest we ultimately acquire and the purchase price
we pay. Because of the preferential rights, we expect to close this transaction
during the third quarter of 2002.

3. INVENTORIES

Our inventories are as follows at the dates indicated:

JUNE 30, DECEMBER 31,
2002 2001
-------- ------------

Regular trade inventory..................................... $ 70,340 $35,894
Forward-sales inventory..................................... 45,960 33,549
Peak Season inventory....................................... 20,959 --
Other....................................................... 16,021 --
-------- -------
Inventory................................................. $153,280 $69,443
======== =======

A description of each inventory is as follows:

- Our regular trade (or "working") inventory is comprised of inventories of
natural gas, NGLs and petrochemicals that are available for immediate
sale. This inventory is valued at the lower of average cost or market,
with "market" being determined by spot-market related prices.

- The forward-sales inventory is comprised of segregated NGL volumes
dedicated to the fulfillment of forward sales contracts and is valued at
the lower of average cost or market, with "market" being defined as the
weighted-average of the sales prices of the forward sales contracts.

- The peak season inventory is comprised of segregated NGL volumes that are
expected to be sold outside of the current summer-winter season and is
valued at the lower of average cost or market, with "market" being
determined by spot-market related prices. These volumes are generally
expected to be sold within the next twelve months, but may be held for
longer periods depending on market conditions.

- Other inventories generally consist of segregated NGL volumes set aside
for possible short-term use as fuel on an equivalent MMBtu basis. This
inventory is carried at the lower of average cost or market, with
"market" being determined by spot-market related prices. The volumes
associated with this inventory are anticipated to be used and/or sold
within the next twelve months.

Due to fluctuating market conditions in the NGL, natural gas and
petrochemical industry, we occasionally recognize lower of average cost or
market adjustments when the cost of our inventories exceed their net realizable
value. These non-cash adjustments are charged to operating costs and expenses in
the period they are recognized and affect our segment operating results in the
following manner:

- NGL inventory write downs are recorded as a cost of the Processing
segment's merchant activities;

- Natural gas inventory write downs are recorded as a cost of the Pipeline
segment's Acadian Gas operations; and

- Petrochemical inventory write downs are recorded as a cost of the
Fractionation segment's propylene fractionation business.

F-56

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

For the second quarter of 2002, we recognized an adjustment of $4.5 million
to write down NGL inventories to their net realizable value. For the second
quarter of 2001, we recorded $25.8 million of such write downs: $19.4 million
against NGL inventories, $4.9 million against natural gas inventories and $1.5
million against petrochemical inventories.

For the first six months of 2002, we recognized $4.6 million in NGL
inventory write downs. For the same six month period in 2001, we recorded $27.8
million in lower of average cost or market write downs. The 2001 adjustments
were $21.4 million against NGL inventories, $4.9 million against natural gas
inventories and $1.5 million against petrochemical inventories. To the extent
our commodity hedging strategies address inventory-related risks and are
successful, these inventory value adjustments are mitigated (or in some cases,
reversed). See Note 13 for a description of our commodity hedging activities.

4. PROPERTY, PLANT AND EQUIPMENT

Our property, plant and equipment and accumulated depreciation are as
follows at the dates indicated:

ESTIMATED
USEFUL LIFE JUNE 30, DECEMBER 31,
IN YEARS 2002 2001
----------- ---------- ------------

Plants and pipelines.............................. 5-35 $1,626,739 $1,398,843
Underground and other storage facilities.......... 5-35 241,806 127,900
Transportation equipment.......................... 3-35 3,952 3,736
Land.............................................. 20,014 15,517
Construction in progress.......................... 44,003 98,844
---------- ----------
Total................................... 1,936,514 1,644,840
Less accumulated depreciation..................... 365,943 338,050
---------- ----------
Property, plant and equipment, net...... $1,570,571 $1,306,790
========== ==========

Property, plant and equipment is recorded at cost and is depreciated using
the straight-line method over the asset's estimated useful life. Maintenance,
repairs and minor renewals are charged to operations as incurred. The cost of
assets retired or sold, together with the related accumulated depreciation, is
removed from the accounts, and any gain or loss on disposition is included in
income.

Additions and improvements to and major renewals of existing assets are
capitalized and depreciated using the straight-line method over the estimated
useful life of the new equipment or modifications. These expenditures result in
a long-term benefit to the Company. We generally classify improvements and major
renewals of existing assets as sustaining capital expenditures and all other
capital spending (on existing and new assets) as expansion capital expenditures.

Depreciation expense for the three months ended June 30, 2002 and 2001 was
$13.8 million and $11.0 million, respectively. For the six months ended June 30,
2002 and 2001, it was $27.9 million and $20.3 million, respectively.

5. INVESTMENTS IN AND ADVANCES TO UNCONSOLIDATED AFFILIATES

We own interests in a number of related businesses that are accounted for
under the equity or cost method. The investments in and advances to these
unconsolidated affiliates are grouped according the operating segment to which
they relate. For a general discussion of our operating segments, see Note 14.

We acquired three equity method unconsolidated affiliates as part of our
acquisition of Diamond-Koch's propylene fractionation business (see Note 2). We
purchased an aggregate 50% interest in La Porte Pipeline Company, L.P. and La
Porte Pipeline GP, L.L.C. (collectively, "La Porte") which together own a
private

F-57

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

polymer grade propylene pipeline extending from Mont Belvieu to La Porte, Texas.
In addition, we acquired 50% of the outstanding capital stock of Olefins
Terminal Corporation ("OTC") which owns a polymer grade propylene storage
facility and related dock infrastructure (located on the Houston Ship Channel)
for loading waterborne propylene vessels. Both the La Porte and OTC investments
are considered an integral part of our Mont Belvieu III propylene fractionation
operations. These investments are classified as part of our Fractionation
operating segment.

The following table shows the aggregate amount of investments in and
advances to (and our ownership percentages in) unconsolidated affiliates at June
30, 2002 and December 31, 2001:

OWNERSHIP JUNE 30, DECEMBER 31,
PERCENTAGE 2002 2001
---------- -------- ------------

Accounted for on equity basis:
Fractionation:
BRF........................................... 32.25% $ 28,687 $ 29,417
BRPC.......................................... 30.00% 18,197 18,841
Promix........................................ 33.33% 43,513 45,071
La Porte...................................... 50.00% 5,814
OTC........................................... 50.00% 1,818
Pipeline:
EPIK.......................................... 50.00% 14,375 14,280
Wilprise...................................... 37.35% 8,663 8,834
Tri-States.................................... 33.33% 26,448 26,734
Belle Rose.................................... 41.67% 11,211 11,624
Dixie......................................... 19.88% 37,284 37,558
Starfish...................................... 50.00% 23,777 25,352
Neptune....................................... 25.67% 77,226 76,880
Nemo.......................................... 33.92% 12,211 12,189
Evangeline.................................... 49.50% 2,657 2,578
Octane Enhancement:
BEF........................................... 33.33% 58,189 55,843
Accounted for on cost basis:
Processing:
VESCO......................................... 13.10% 33,000 33,000
-------- --------
Total......................................... $403,070 $398,201
======== ========

The following table shows equity in income (loss) of unconsolidated
affiliates for the three and six months ended June 30, 2002 and 2001:

THREE MONTHS
ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
OWNERSHIP --------------- -----------------
PERCENTAGE 2002 2001 2002 2001
---------- ------ ------ ------- -------

Fractionation:
BRF................................. 32.25% $ 743 $ 42 $ 1,292 $ 60
BRPC................................ 30.00% 278 252 527 404
Promix.............................. 33.33% 996 1,396 2,039 1,789
La Porte............................ 50.00% (173) (265)
OTC................................. 50.00% 128 18

F-58

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

THREE MONTHS
ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
OWNERSHIP --------------- -----------------
PERCENTAGE 2002 2001 2002 2001
---------- ------ ------ ------- -------

Pipelines:
EPIK................................ 50.00% (54) (172) 1,629 (1,094)
Wilprise............................ 37.35% 320 85 467 (137)
Tri-States.......................... 33.33% 365 135 834 100
Belle Rose.......................... 41.67% 40 29 114 (60)
Dixie............................... 19.88% (156) 69 561 960
Starfish............................ 50.00% 973 1,022 1,785 1,973
Ocean Breeze........................ 25.67% -- 12 -- 14
Neptune............................. 25.67% 682 1,095 1,460 1,789
Nemo................................ 33.92% 44 1 22 10
Evangeline.......................... 49.50% 5 (149) (71) (149)
Octane Enhancement:
BEF................................. 33.33% 2,877 5,233 5,883 5,402
------ ------ ------- -------
Total............................... $7,068 $9,050 $16,295 $11,061
====== ====== ======= =======

Our initial investment in Promix, La Porte, Dixie, Neptune and Nemo
exceeded our share of the historical cost of the underlying net assets of such
entities ("excess cost").The excess cost of these investments is reflected in
our investments in and advances to unconsolidated affiliates for these entities.
The excess cost amounts related to Promix, La Porte and Nemo are attributable to
the tangible plant and pipeline assets of each entity, the excess cost of which
is amortized against equity earnings from these entities in a manner similar to
depreciation. The excess cost of Dixie includes amounts attributable to both
goodwill and tangible pipeline assets, with that portion assigned to the
pipeline assets being amortized in a manner similar to depreciation. The
goodwill inherent in Dixie's excess cost is subject to periodic impairment
testing and is not amortized. The following table summarizes our excess cost
information:

AMORTIZATION
UNAMORTIZED BALANCE AT CHARGED TO
INITIAL ----------------------- EQUITY EARNINGS
EXCESS JUNE 30, DECEMBER 31, DURING AMORTIZATION
COST 2002 2001 2002 PERIOD
------- -------- ------------ --------------- ------------

Fractionation segment:
Promix................... $ 7,955 $ 6,794 $ 7,083 $199 20 years
La Porte................. 873 855 n/a 18 35 years
Pipelines segment:
Dixie
Attributable to
pipeline assets..... 28,448 26,480 26,887 406 35 years
Goodwill.............. 9,246 8,827 8,827 n/a n/a
Neptune.................. 12,768 12,221 12,404 182 35 years
Nemo..................... 727 708 718 10 35 years

F-59

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following tables presents summarized income statement information for
our unconsolidated investments accounted for under the equity method (for the
periods indicated on a 100% basis).

SUMMARIZED INCOME STATEMENT DATA FOR THE THREE MONTHS ENDED
-----------------------------------------------------------------------
JUNE 30, 2002 JUNE 30, 2001
---------------------------------- ----------------------------------
OPERATING NET OPERATING NET
REVENUES INCOME INCOME REVENUES INCOME INCOME
-------- ------------- ------- -------- ------------- -------

Fractionation:
BRF................ $ 5,750 $ 2,295 $ 2,305 $ 3,802 $ 265 $ 294
BRPC............... 3,150 923 930 3,400 793 842
Promix............. 10,819 3,274 3,285 12,340 4,447 4,487
La Porte........... -- (301) (306)
OTC................ 1,421 302 258
Pipeline:
EPIK............... 1,577 (117) (109) 792 (375) (348)
Wilprise........... 1,033 855 857 494 224 227
Tri-States......... 3,680 1,088 1,097 2,321 388 403
Belle Rose......... 433 95 96 407 13 21
Dixie.............. 6,270 (1,853) (1,191) 8,799 2,001 1,124
Starfish........... 6,714 2,169 1,943 7,051 2,571 2,299
Ocean Breeze....... 53 39 39
Neptune............ 6,926 2,046 2,338 9,362 5,223 5,195
Nemo............... 887 114 118 (27) 2
Evangeline......... 35,551 1,030 9 47,609 1,010 (144)
Octane Enhancement:
BEF................ 58,132 8,570 8,628 76,054 15,509 15,700
-------- ------- ------- -------- ------- -------
Total.............. $142,343 $20,490 $20,258 $172,484 $32,081 $30,141
======== ======= ======= ======== ======= =======

SUMMARIZED INCOME STATEMENT DATA FOR THE SIX MONTHS ENDED
-----------------------------------------------------------------------
JUNE 30, 2002 JUNE 30, 2001
---------------------------------- ----------------------------------
OPERATING NET OPERATING NET
REVENUES INCOME INCOME REVENUES INCOME INCOME
-------- ------------- ------- -------- ------------- -------

Fractionation:
BRF................ $ 10,355 $ 3,960 $ 4,007 $ 7,825 $ 300 $ 350
BRPC............... 6,102 1,742 1,758 6,833 1,232 1,347
Promix............. 20,683 6,683 6,713 21,343 5,888 5,964
La Porte........... -- (535) (541)
OTC................ 1,792 109 37

F-60

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Pipeline:
EPIK............... 9,849 3,237 3,257 1,967 (1,782) (1,725)
Wilprise........... 1,804 1,248 1,251 893 (378) (367)
Tri-States......... 6,780 2,490 2,503 3,953 262 299
Belle Rose......... 941 271 273 554 (205) (192)
Dixie.............. 21,398 5,552 3,331 24,036 8,301 4,829
Starfish........... 13,143 4,105 3,569 13,467 4,390 3,916
Ocean Breeze....... -- -- -- 87 87 65
Neptune............ 14,629 5,561 5,645 16,747 8,648 8,581
Nemo............... 1,282 40 48 (42) 36
Evangeline......... 61,060 1,880 (170) 47,609 1,010 (144)
Octane Enhancement:
BEF................ 106,061 17,548 17,648 113,918 15,922 16,207
-------- ------- ------- -------- ------- -------
Total.............. $275,879 $53,891 $49,329 $259,232 $43,633 $39,166
======== ======= ======= ======== ======= =======

6. RECENTLY ISSUED ACCOUNTING STANDARDS

In June 2001, the FASB issued two new pronouncements: SFAS No. 141,
"Business Combinations", and SFAS No. 142, "Goodwill and Other Intangible
Assets". SFAS No. 141 prohibits the use of the pooling-of-interests method for
business combinations initiated after June 30, 2001 and also applies to all
business combinations accounted for by the purchase method that are completed
after June 30, 2001. There are also transition provisions that apply to business
combinations completed before July 1, 2001, that were accounted for by the
purchase method. SFAS No. 142 was effective for our fiscal year that began
January 1, 2002 for all goodwill and other intangible assets recognized in our
consolidated balance sheet at that date, regardless of when those assets were
initially recognized.

At December 31, 2001, our intangible assets were comprised of the values
associated with the Shell natural gas processing agreement and the goodwill
related to the 1999 MBA acquisition. In accordance with SFAS No. 141, we
reclassified the MBA goodwill to a separate line item on our consolidated
balance sheet apart from the Shell contract. Based upon SFAS No. 142, the value
of the Shell natural gas processing agreement will continue to be amortized over
its remaining contract term of approximately 18 years; however, amortization of
the MBA goodwill will cease. The MBA goodwill will be subject to periodic
impairment testing in accordance with SFAS No. 142 due to its indefinite life.
For additional information regarding our intangible assets and goodwill
(including additions to both classes of assets as a result of the Diamond-Koch
acquisitions), see Note 7.

In accordance with the transition provisions of SFAS No. 142, we have
completed an impairment review of the December 31, 2001 MBA goodwill balance.
Professionals in the business valuation industry were consulted regarding the
assumptions and techniques used in our analysis. As a result of this review, no
impairment loss was indicated. Any subsequent impairment losses stemming from
future goodwill impairment studies will be reflected as a component of operating
income in the Statements of Consolidated Operations.

F-61

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

statement is effective for our fiscal year beginning January 1, 2003. We are
evaluating the provisions of this statement.

In August 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets". This statement addresses financial
accounting and reporting for the impairment and/or disposal of long-lived
assets. We adopted this statement effective January 1, 2002 and determined that
it did not have any significant impact on our financial statements as of that
date.

In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities." This standard requires companies
to recognize costs associated with exit or disposal activities when they are
incurred rather than at the date of a commitment to exit or disposal plan.
Examples of costs covered by the standard include lease termination costs and
certain employee severance costs that are associated with a restructuring,
discontinued operation, plant closing, or other exit or disposal activity.
Previous accounting guidance was provided by EITF Issue No. 94-3, "Liability
Recognition for Certain Employee Termination Benefits and Other Costs to Exit an
Activity (including Certain Costs Incurred in a Restructuring)." SFAS No. 146
replaces Issue 94-3. SFAS No. 146 is to be applied prospectively to exit or
disposal activities initiated after December 31, 2002. This statement is
effective for our fiscal year beginning January 1, 2003. We are evaluating the
provisions of this statement.

7. INTANGIBLE ASSETS AND GOODWILL

INTANGIBLE ASSETS

Our recorded intangible assets are comprised of the estimated values
assigned to contract rights we own arising from agreements with customers.
According to SFAS No. 141, a contract-based intangible asset with a finite
useful life is amortized over its estimated useful life, which is the period
over which the asset is expected to contribute directly or indirectly to the
future cash flows of the entity. It is based on an analysis of all pertinent
factors including (a) the expected use of the asset by the entity, (b) the
expected useful life of related assets (i.e., fractionation facility, storage
well, etc.), (c) any legal, regulatory or contractual provisions, including
renewal or extension periods that would not cause substantial costs or
modifications to existing agreements, (d) the effects of obsolescence, demand,
competition, and other economic factors and (e) the level of maintenance
required to obtain the expected future cash flows.

The specific, identifiable intangible assets of a business enterprise
depend largely upon the nature of its operations. Potential intangible assets
include intellectual property such as technology, patents, trademarks and trade
names, customer contracts and relationships, and non-compete agreements, as well
as other intangible assets. The approach to the valuation of each intangible
asset will vary depending upon the nature of the asset, the business in which it
is utilized, and the economic returns it is generating or is expected to
generate.

At June 30, 2002, our intangible assets consisted of the Shell natural gas
processing agreement that we acquired as part of the TNGL acquisition in August
1999 and certain propylene fractionation and storage contracts we acquired in
connection with the Diamond-Koch acquisitions in January and February 2002. The
value of the Shell natural gas processing agreement is being amortized on a
straight-line basis over its remaining contract term (currently $11.1 million
annually from 2002 through 2019). At June 30, 2002, the unamortized value of the
Shell contract was $188.8 million.

F-62

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The value of the propylene fractionation and storage contracts acquired
from Diamond-Koch is being amortized on a straight-line basis over the economic
life of the assets to which they relate, which is currently estimated at 35
years. Although the majority of these contracts have terms of one to two years,
we have assumed that our relationship with these customers will extend beyond
the contractually-stated term primarily based on historically low customer
contract turnover rates within these operations. At June 30, 2002, the
unamortized value of these contracts was $60.4 million.

GOODWILL

At June 30, 2002, the value of goodwill was $81.5 million. Our goodwill is
attributable to the excess of the purchase price over the fair value of assets
acquired and is comprised of the following (values as of June 30, 2002):

- $73.7 million associated with the purchase of propylene fractionation
assets from Diamond-Koch in February 2002; and,

- $7.8 million related to the July 1999 purchase of Kinder Morgan's
ownership interest in MBA which in turn owned an interest in our Mont
Belvieu NGL fractionation facility.

Since our adoption of SFAS No. 142 on January 1, 2002, our goodwill amounts
are no longer amortized. Instead, we periodically review the reporting units to
which the goodwill amounts relate for indications of possible impairment. If
such indicators are present (i.e., loss of a significant customer, economic
obsolescence of plant assets, etc.), the fair value of the reporting unit,
including its related goodwill, will be calculated and compared to its combined
book value. Our goodwill amounts are classified as part of the Fractionation
segment since they are related to assets recorded in this operating segment.

The fair value of a reporting unit refers to the amount at which it could
be bought or sold in a current transaction between willing parties. Quoted
market prices in active markets are the best evidence of fair value and are used
to the extent they are available. If quoted market prices are not available, an
estimate of fair value is determined based on the best information available to
us, including prices of similar assets and the results of using other valuation
techniques such as discounted cash flow analysis and multiples of earnings
approaches. The underlying assumptions in such models rely on information
available to us at a given point in time and are viewed as reasonable and
supportable considering available evidence.

If the fair value of the reporting unit exceeds its book value, goodwill is
not considered impaired and no adjustment to earnings would be required. Should
the fair value of the reporting unit (including its goodwill) be less than its
book value, a charge to earnings would be recorded to adjust goodwill to its
implied fair value.

PRO FORMA IMPACT OF DISCONTINUATION OF AMORTIZATION OF GOODWILL

The following table discloses the unaudited pro forma impact on earnings of
discontinuing amortization of the MBA goodwill (for the three and six months
ended June 30, 2001).

THREE MONTHS SIX MONTHS
ENDED JUNE 30, ENDED JUNE 30,
2001 2001
-------------- --------------

Reported net income...................................... $93,031 $145,301
Discontinue goodwill amortization........................ 111 222
Adjust minority interest expense......................... (1) (2)
------- --------
Adjusted net income...................................... $93,141 $145,521
======= ========

F-63

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

On a pro forma basis, earnings per Unit (both basic and diluted) were not
affected by the discontinuation of goodwill amortization due to the immaterial
nature of the pro forma adjustment.

8. DEBT OBLIGATIONS

Our debt consisted of the following at:

JUNE 30, DECEMBER 31,
2002 2001
---------- ------------

Borrowings under:
Senior Notes A, 8.25% fixed rate, due March 2005.......... $ 350,000 $350,000
MBFC Loan, 8.70% fixed rate, due March 2010............... 54,000 54,000
Senior Notes B, 7.50% fixed rate, due February 2011....... 450,000 450,000
Multi-Year Credit Facility, due November 2005............. 230,000
364-Day Credit Facility, due November 2002(a)............. 138,000
---------- --------
Total principal amount............................ 1,222,000 854,000
Unamortized balance of increase in fair value related to
hedging a portion of fixed-rate debt...................... 1,895 1,653
Less unamortized discount on:
Senior Notes A............................................ (99) (117)
Senior Notes B............................................ (244) (258)
Less current maturities of debt............................. -- --
---------- --------
Long-term debt.................................... $1,223,552 $855,278
========== ========

---------------
(a) Under the terms of this facility, the Operating Partnership has the option
to convert this facility into a term loan due November 15, 2003. Management
intends to refinance this obligation with a similar obligation at or before
maturity.

The above table does not reflect the $1.26 billion in debt we incurred on
July 31, 2002 in connection with the Mapletree and E-Oaktree acquisitions (see
Note 15 for information regarding this subsequent event).

At June 30, 2002, we had a total of $75 million of standby letters of
credit capacity under our Multi-Year Credit Facility of which $9.4 million was
outstanding.

Enterprise Products Partners L.P. acts as guarantor of certain of the
Operating Partnership's debt obligations. This parent-subsidiary guaranty
provision exists under our Senior Notes, MBFC Loan, Multi-Year and 364-Day
Credit Facility.

In April 2002, we increased the amount that we can borrow under the
Multi-Year Credit Facility by $20 million and the 364-Day Credit Facility by $80
million, up to an amount not exceeding $500 million in the aggregate for both
facilities. At June 30, 2002, we had borrowed a total of $368 million under
these two facilities.

The indentures under which the Senior Notes and the MBFC Loan were issued
contain various restrictive covenants. We were in compliance with these
covenants at June 30, 2002.

On April 24, 2002, certain covenants of our Multi-Year and 364-Day Credit
Facilities were amended to allow for the commodity hedging losses we incurred
during the first four months of 2002. As defined within the second amendment to
each of these loan agreements, the changes included allowing us to exclude from
the calculation of Consolidated EBITDA up to $50 million in losses resulting
from hedging NGLs that utilized natural gas-based financial instruments entered
into on or prior to April 24, 2002. This exclusion

F-64

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

applies to our quarterly Consolidated EBITDA calculations in which the earnings
impact of such specific instruments were recognized. This provision allows for
$45.1 million to be added back to Consolidated EBITDA for the first quarter of
2002 and $4.9 million to be added back for the second quarter of 2002. Due to
the rolling four-quarter nature of the Consolidated EBITDA calculation, this
provision will affect our financial covenants through the first quarter of 2003.
In addition, the second amendment temporarily raised the maximum ratio allowed
under the Consolidated Indebtedness to Consolidated EBITDA ratio for the
rolling-four quarter period ending September 30, 2002 (this provision was
superseded by the third amendment to these loan agreements executed on July 31,
2002, see Note 15 for information regarding this subsequent event).

We were in compliance with the covenants of our Multi-Year and 364-Day
revolving credit agreements at June 30, 2002.

9. CAPITAL STRUCTURE

CONVERSION OF EPCO SUBORDINATED UNITS TO COMMON UNITS

As a result of the Company satisfying certain financial tests, 10,704,936
(or 25%) of EPCO's Subordinated Units converted to Common Units on May 1, 2002.
Should the financial criteria continue to be satisfied through the first quarter
of 2003, an additional 25% of the Subordinated Units would undergo an early
conversion to Common Units on May 1, 2003. The remaining 50% of Subordinated
Units would convert on August 1, 2003 should the balance of the conversion
requirements be met. Subordinated Units have no voting rights until converted to
Common Units. The conversion(s) will have no impact upon our earnings per unit
since the Subordinated Units are already included in both the basic and fully
diluted EPU calculations.

CONVERSION OF SHELL SPECIAL UNITS TO COMMON UNITS

In accordance with existing agreements with Shell, 19.0 million of Shell's
non-distribution bearing Special Units converted to distribution-bearing Common
Units on August 1, 2002. The remaining 10.0 million Special Units will convert
to Common Units on a one-for-one basis in August 2003. These conversions have a
dilutive impact on basic EPU.

TREASURY UNITS

During the first quarter of 1999, the Operating Partnership established the
EPOLP 1999 Grantor Trust (the "Trust") to fund future obligations under EPCO's
long-term incentive plan (through the exercise of Common Unit options granted to
directors of the General Partner and EPCO employees who participate in the
business of the Operating Partnership). The Common Units purchased by the Trust
are accounted for in a manner similar to treasury stock under the cost method of
accounting. At June 30, 2002, the Trust held 427,200 Common Units that are
classified as Treasury Units. The Trust purchased 100,000 Common Units during
the first six months of 2002 at a cost of $2.4 million.

Beginning in July 2000 and later modified in September 2001, the General
Partner authorized the Company (specifically, "Enterprise Products Partners
L.P." in this context) and the Trust to repurchase up to 2.0 million of our
publicly-held Common Units (the "Buy-Back Program"). The repurchases will be
made during periods of temporary market weakness at price levels that would be
accretive to our remaining Unitholders. Under the terms of the original Buy-Back
Program, Common Units repurchased by the Company were to be retired and Common
Units repurchased by the Trust were to remain outstanding and be accounted for
as Treasury Units.

In April 2002, management modified the Buy-Back Program to treat Common
Units repurchased by the Company as Treasury Units. For accounting purposes,
Units repurchased by the Company will be held in

F-65

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

treasury to fund future obligations under EPCO's long-term incentive plan (i.e,
used for the same intent as that contemplated for the Common Units repurchased
by the Trust). The Company purchased 424,459 Common Units during the first six
months of 2002 at a cost of $9.3 million. At June 30, 2002, 677,900 Common Units
could be repurchased under the Buy-Back Program.

During the second quarter of 2002, 51,959 Common Units were reissued from
the Company's Treasury Units at their weighted-average cost of $1.2 million to
fulfill our obligations under certain employee Unit option agreements of EPCO.

COMPREHENSIVE INCOME

We report comprehensive income or loss in our Statements of Consolidated
Partners' Equity and Comprehensive Income. For the six months ended June 30,
2001, the cumulative transition adjustment resulting from the adoption of SFAS
No. 133, Accounting for Derivative Instruments and Hedging Activities, as
amended and interpreted, was the only item of other comprehensive income for us.
There were no differences between net income and comprehensive income for the
same period in 2002. The following table summarizes the activity in other
comprehensive income for the six months ended June 30, 2001.

COMPREHENSIVE INCOME
FOR THE SIX MONTHS ENDED JUNE 30, 2001

Net Income.................................................. $145,301
Less: Accumulated Other Comprehensive Loss.................. (9,711)
--------
Comprehensive Income........................................ $135,590
========

10. EARNINGS PER UNIT

Basic earnings per Unit is computed by dividing net income available to
limited partner interests by the weighted-average number of Common and
Subordinated Units outstanding during the period. In general, diluted earnings
per Unit is computed by dividing net income available to limited partner
interests by the weighted-average number of Common, Subordinated and Special
Units outstanding during the period. In a period of operating losses, the
Special Units are excluded from the calculation of diluted earnings per Unit due
to their antidilutive effect. The following table reconciles the number of Units
used in the calculation of basic earnings per Unit and diluted earnings per Unit
for the three and six months ended June 30, 2002 and 2001.

THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------- -------------------
2002 2001 2002 2001
-------- -------- -------- --------

Income before minority interest.................... $ 22,523 $ 93,975 $ 5,147 $146,779
General partner interest........................... (2,648) (1,388) (3,894) (2,370)
-------- -------- -------- --------
Income before minority interest available to
Limited Partners................................. 19,875 92,587 1,253 144,409
Minority interest.................................. (203) (944) (30) (1,478)
-------- -------- -------- --------
Net income available to Limited Partners........... $ 19,672 $ 91,643 $ 1,223 $142,931
======== ======== ======== ========

F-66

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------- -------------------
2002 2001 2002 2001
-------- -------- -------- --------

BASIC EARNINGS PER UNIT
NUMERATOR
Income before minority interest available to
Limited Partners............................ $ 19,875 $ 92,587 $ 1,253 $144,409
======== ======== ======== ========
Net income available to Limited Partners...... $ 19,672 $ 91,643 $ 1,223 $142,931
======== ======== ======== ========
DENOMINATOR
Common Units outstanding...................... 109,640 92,514 106,192 92,514
Subordinated Units outstanding................ 35,644 42,820 39,212 42,820
-------- -------- -------- --------
Total......................................... 145,284 135,334 145,404 135,334
======== ======== ======== ========
BASIC EARNINGS PER UNIT
Income before minority interest available to
Limited Partners............................ $ 0.14 $ 0.68 $ 0.01 $ 1.07
======== ======== ======== ========
Net income available to Limited Partners...... $ 0.14 $ 0.68 $ 0.01 $ 1.06
======== ======== ======== ========
DILUTED EARNINGS PER UNIT
NUMERATOR
Income before minority interest available to
Limited Partners............................ $ 19,875 $ 92,587 $ 1,253 $144,409
======== ======== ======== ========
Net income available to Limited Partners...... $ 19,672 $ 91,643 $ 1,223 $142,931
======== ======== ======== ========
DENOMINATOR
Common Units outstanding...................... 109,640 92,514 106,192 92,514
Subordinated Units outstanding................ 35,644 42,820 39,212 42,820
Special Units outstanding..................... 29,000 33,000 29,000 33,000
-------- -------- -------- --------
Total......................................... 174,284 168,334 174,404 168,334
======== ======== ======== ========
DILUTED EARNINGS PER UNIT
Income before minority interest available to
Limited Partners............................ $ 0.11 $ 0.55 $ 0.01 $ 0.86
======== ======== ======== ========
Net income available to Limited Partners...... $ 0.11 $ 0.54 $ 0.01 $ 0.85
======== ======== ======== ========

11. DISTRIBUTIONS

The distribution paid on February 11, 2002 (based on fourth quarter 2001
results) was $0.3125 per Common and Subordinated Unit. The distribution paid on
May 10, 2002 (based on first quarter 2002 results) was $0.335 per Common and
Subordinated Unit. As a result of these distributions, the General Partner
received $3.9 million in incentive distributions.

F-67

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The distribution rate declared by the General Partner for the second
quarter of 2002 was $0.335 per Common Unit to Unitholders of record on July 31,
2002. This distribution was paid on August 12, 2002.

12. SUPPLEMENTAL CASH FLOWS DISCLOSURE

The net effect of changes in operating assets and liabilities is as
follows:

SIX MONTHS ENDED
JUNE 30,
-------------------
2002 2001
-------- --------

(Increase) decrease in:
Accounts and notes receivable............................. $(24,455) $ 96,860
Inventories............................................... (78,843) 522
Prepaid and other current assets.......................... 9,599 (10,831)
Other assets.............................................. (3,436) (129)
Increase (decrease) in:
Accounts payable.......................................... 7,795 (55,755)
Accrued gas payable....................................... 70,447 (78,008)
Accrued expenses.......................................... (9,499) (11,232)
Accrued interest.......................................... 374 14,546
Other current liabilities................................. (4,219) 13,271
Other liabilities......................................... (142) 187
-------- --------
Net effect of changes in operating accounts................. $(32,379) $(30,569)
======== ========

During the first six months of 2002, we completed $394.8 million in
business acquisitions of which the purchase price allocations of each affected
various balance sheet accounts. See Note 2 for information regarding the
allocation of the purchase price for these acquisitions.

The $32.5 million purchase price obligation of the Toca-Western facilities
will not be paid until September 2002. This amount was accrued as additional
property, plant and equipment with the offsetting payable amount recorded under
other current liabilities (see Note 2).

We record various financial instruments relating to commodity positions and
interest rate swaps at their respective fair values using mark-to-market
accounting. For the six months ended June 30, 2002, we recognized a net $19.7
million in non-cash changes related to decreases in the fair value of these
financial instruments, primarily in our commodity financial instruments
portfolio. For the six months ended June 30, 2001, we recognized a net $55.9
million in non-cash mark-to-market income from our financial instruments
portfolio.

Cash and cash equivalents at June 30, 2002, per the Statements of
Consolidated Cash Flows, excludes $5.0 million of restricted cash. This
restricted cash represents amounts held by a brokerage firm as margin deposits
associated with our financial instruments portfolio and for physical purchase
transactions made on the NYMEX exchange.

Of the $9.3 million spent by the Company for Treasury Units during the
first six months of 2002, $0.7 million will not result in cash settlements until
July 2002.

13. FINANCIAL INSTRUMENTS

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

to mitigate the risks of certain identifiable and anticipated transactions,
primarily in our Processing segment. As a matter of policy, we do not use
financial instruments for speculative (or trading) purposes.

COMMODITY FINANCIAL INSTRUMENTS

Our Processing and Octane Enhancement segments are directly exposed to
commodity price risk through their respective business operations. The prices of
natural gas, NGLs and MTBE are subject to fluctuations in response to changes in
supply, market uncertainty and a variety of additional factors that are beyond
our control. In order to manage the risks associated with our Processing
segment, we may enter into swaps, forwards, commodity futures, options and other
commodity financial instruments with similar characteristics that are permitted
by contract or business custom to be settled in cash or with another financial
instrument. The primary purpose of these risk management activities (or hedging
strategies) is to hedge exposure to price risks associated with natural gas, NGL
inventories, firm commitments and certain anticipated transactions. We do not
hedge our exposure to the MTBE markets. Also, in our Pipelines segment, we may
utilize a limited number of commodity financial instruments to manage the price
we charge certain of our customers for natural gas.

We have adopted a financial commodity and commercial policy to manage our
exposure to the risks of our natural gas and NGL businesses. The objective of
these policies is to assist us in achieving our profitability goals while
maintaining a portfolio with an acceptable level of risk, defined as remaining
within the position limits established by the General Partner. Under these
policies, we enter into risk management transactions to manage price risk, basis
risk, physical risk or other risks related to our commodity positions on both a
short-term (less than one month) and long-term basis, generally not to exceed 24
months. The General Partner oversees our hedging strategies associated with
physical and financial risks (such as those mentioned previously), approves
specific activities subject to the policies (including authorized products,
instruments and markets) and establishes specific guidelines and procedures for
implementing and ensuring compliance with the policies.

We routinely review our outstanding financial instruments in light of
current market conditions. If market conditions warrant, some financial
instruments may be closed out in advance of their contractual settlement dates
thus realizing income or loss depending on the specific exposure. When this
occurs, we may enter into a new commodity financial instrument to reestablish
the economic hedge to which the closed instrument relates.

Our commodity financial instruments may not qualify for hedge accounting
treatment under the specific guidelines of SFAS No. 133 because of
ineffectiveness. A hedge is normally regarded as effective if, among other
things, at inception and throughout the term of the financial instrument, we
could expect changes in the fair value of the hedged item to be almost fully
offset by the changes in the fair value of the financial instrument. When
financial instruments do not qualify as effective hedges under the guidelines of
SFAS No. 133, changes in the fair value of these positions are recorded on the
balance sheet and in earnings through mark-to-market accounting. The use of
mark-to-market accounting for these ineffective instruments results in a degree
of non-cash earnings volatility that is dependent upon changes in the underlying
commodity prices.

We recognized a loss of $50.9 million in the first six months of 2002 from
our commodity hedging activities, of which $45.1 million was attributable to the
first quarter of 2002. These losses are treated as an increase in operating
costs and expenses in our Statements of Consolidated Operations. Of this amount,
$31.9 million has been realized (e.g., paid out to counterparties). The
remaining $19.0 million represents the negative change in value of the open
positions between December 31, 2001 and June 30, 2002 (based on market prices at
those dates). The market value of our open positions at June 30, 2002 was $11.1
million payable (a loss).

F-69

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

For the first six months of 2001, we recognized income of $70.3 million
from these activities of which $5.6 million was recorded in the first quarter
and $64.7 million in the second quarter. Of the $70.3 million recorded for the
first six months of 2001, $52.4 million was attributable to the market value of
open positions at June 30, 2001.

INTEREST RATE SWAPS

Our interest rate exposure results from variable-rate borrowings from
commercial banks and fixed-rate borrowings pursuant to the Company's Senior
Notes and MBFC Loan. We manage a portion of our exposure to changes in interest
rates by utilizing interest rate swaps. The objective of holding interest rate
swaps is to manage debt service costs by converting a portion of fixed-rate debt
into variable-rate debt or a portion of variable-rate debt into fixed-rate debt.
An interest rate swap, in general, requires one party to pay a fixed-rate on the
notional amount while the other party pays a floating-rate based on the notional
amount.

The General Partner oversees the strategies associated with financial risks
and approves instruments that are appropriate for our requirements. At June 30,
2002, we had one interest rate swap outstanding having a notional amount of $54
million extending through March 2010. Under this agreement, we exchanged a
fixed-rate of 8.70% for a market-based variable-rate. If it elects to do so, the
counterparty may terminate this swap in March 2003.

We recognized income of $0.8 million during the first six months of 2002
from our interest rate swaps that is treated as a reduction of interest expense
($0.7 million recorded in the second quarter of 2002). The fair value of the
interest rate swap at June 30, 2002 was a receivable of $3.1 million. We
recognized income of $5.5 million during the first six months of 2001 from
interest rate swaps. The benefit recorded in 2001 was primarily due to the
election of a counterparty to not terminate its interest rate swap in the first
quarter of 2001.

14. SEGMENT INFORMATION

We have five reportable operating segments: Pipelines, Fractionation,
Processing, Octane Enhancement and Other. The reportable segments are generally
organized according to the type of services rendered (or process employed) and
products produced and/or sold, as applicable. The segments are regularly
evaluated by the Chief Executive Officer of the General Partner. Pipelines
consists of both liquids and natural gas pipeline systems, storage and
import/export terminal services. Fractionation primarily includes NGL
fractionation, isomerization, and polymer grade propylene fractionation
services. Processing includes the natural gas processing business and its
related merchant activities. Octane Enhancement represents our equity interest
in BEF, a facility that produces motor gasoline additives to enhance octane
(currently producing MTBE). The Other operating segment consists of fee-based
marketing services and other plant support functions.

Gross operating margin by segment includes intersegment and intrasegment
revenues (offset by corresponding intersegment and intrasegment expenses within
the segments), which are generally based on
F-70

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

transactions made at market-related rates. Our intersegment and intrasegment
activities include, but are not limited to, the following types of transactions:

- NGL fractionation revenues from separating our NGL raw-make inventories
into distinct NGL products using our fractionation plants for our
merchant activities group (an intersegment revenue of Fractionation
offset by an intersegment expense of Processing);

- liquids pipeline revenues from transporting our merchant volumes from the
gas processing plants on our pipelines to our NGL fractionation
facilities (an intersegment revenue of Pipelines offset by an
intersegment expense of Processing); and,

- the sale of our NGL equity production extracted by our gas processing
plants to our merchant activities group (an intrasegment revenue of
Processing offset by an intrasegment expense of Processing).

Our consolidated financial statements include our accounts and those of our
majority-owned subsidiaries, after elimination of all material intercompany
(both intersegment and intrasegment) accounts and transactions.

Our revenues are derived from a wide customer base. All consolidated
revenues were earned in the United States. Our operations are centered along the
Texas, Louisiana and Mississippi Gulf Coast areas. See Note 15 regarding an
expansion of our business activities into certain regions of the central and
western United States.

F-71

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

A reconciliation of segment gross operating margin to consolidated income
before minority interest follows:

THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------- -------------------
2002 2001 2002 2001
-------- -------- -------- --------

Total segment gross operating margin....... $ 66,938 $131,255 $ 93,351 $204,148
Depreciation and amortization............ (16,962) (11,793) (34,199) (21,822)
Retained lease expense, net.............. (2,273) (2,660) (4,578) (5,320)
(Gain) loss on sale of assets............ 1 6 (12) 387
Selling, general and administrative...... (7,740) (7,737) (15,702) (13,905)
-------- -------- -------- --------
Consolidated operating income.............. 39,964 109,071 38,860 163,488
Interest expense......................... (19,032) (16,331) (37,545) (23,318)
Interest income from unconsolidated
affiliates............................ 62 7 92 31
Dividend income from unconsolidated
affiliates............................ 1,242 -- 2,196 1,632
Interest income -- other................. 241 1,479 1,575 5,477
Other, net............................... 46 (251) (31) (531)
-------- -------- -------- --------
Consolidated income before minority
interest................................. $ 22,523 $ 93,975 $ 5,147 $146,779
======== ======== ======== ========

F-72

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Information by operating segment, together with reconciliations to the
consolidated totals, is presented in the following table:

OPERATING SEGMENTS
-------------------------------------------------------------- ADJS.
OCTANE AND CONSOL.
FRACTIONATION PIPELINES PROCESSING ENHANCEMENT OTHER ELIMS. TOTALS
------------- --------- ---------- ----------- ------- --------- ----------

Revenues from external customers:
Three months ended June 30,
2002........................... $169,345 $138,589 $ 477,941 $ 382 $ 786,257
Three months ended June 30,
2001........................... 86,566 178,958 693,242 631 959,397
Six months ended June 30, 2002... 278,767 237,670 930,975 899 1,448,311
Six months ended June 30, 2001... 176,245 186,145 1,432,011 1,311 1,795,712
Intersegment and intrasegment
revenues:
Three months ended June 30,
2002........................... 56,103 25,578 140,969 102 $(222,752)
Three months ended June 30,
2001........................... 44,133 24,631 131,657 96 (200,517)
Six months ended June 30, 2002... 89,500 50,088 267,229 202 (407,019)
Six months ended June 30, 2001... 85,785 45,410 241,966 191 (373,352)
Equity income in unconsolidated
affiliates:
Three months ended June 30,
2002........................... 1,973 2,219 $ 2,876 7,068
Three months ended June 30,
2001........................... 1,692 2,125 5,233 9,050
Six months ended June 30, 2002... 3,612 6,801 5,882 16,295
Six months ended June 30, 2001... 2,253 3,406 5,402 11,061
Total revenues:
Three months ended June 30,
2002........................... 227,421 166,386 618,910 2,876 484 (222,752) 793,325
Three months ended June 30,
2001........................... 132,391 205,714 824,899 5,233 727 (200,517) 968,447
Six months ended June 30, 2002... 371,879 294,559 1,198,204 5,882 1,101 (407,019) 1,464,606
Six months ended June 30, 2001... 264,283 234,961 1,673,977 5,402 1,502 (373,352) 1,806,773
Total gross operating margin by
segment:
Three months ended June 30,
2002........................... 33,853 32,190 (1,182) 2,876 (799) 66,938
Three months ended June 30,
2001........................... 32,803 24,696 68,112 5,233 411 131,255
Six months ended June 30, 2002... 58,230 64,858 (34,558) 5,882 (1,061) 93,351
Six months ended June 30, 2001... 58,471 42,819 96,510 5,402 946 204,148
Segment assets:
At June 30, 2002................. 470,249 918,052 129,028 9,239 44,003 1,570,571
At December 31, 2001............. 357,122 717,348 124,555 8,921 98,844 1,306,790
Investments in and advances to
unconsolidated affiliates:
At June 30, 2002................. 98,029 213,852 33,000 58,189 403,070
At December 31, 2001............. 93,329 216,029 33,000 55,843 398,201
Intangible Assets:
At June 30, 2002................. 52,369 8,011 188,842 249,222
At December 31, 2001............. 7,857 194,369 202,226
Goodwill:
At June 30, 2002................. 81,543 81,543

Total revenues for the second quarter of 2002 were lower than those of the
second quarter of 2001 primarily due to a decline in NGL product prices between
the two periods. The same can be said for the difference between the first six
months of 2002 compared to the same period in 2001. Total gross operating margin
for the second quarter of 2002 decreased $64.3 million from the second quarter
of 2001 primarily due to the 2001 period including $64.7 million of commodity
hedging income in the Processing segment that was not repeated in the 2002
period. For the first six months of 2002, gross operating margin decreased
$110.8 million compared to the first six months of 2001. The year-to-date
decline in gross operating margin is
F-73

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

primarily due to the 2002 period including $50.9 million in commodity hedging
losses versus the 2001 period including $70.3 million in commodity hedging
income (together accounting for $121.2 million of the year-to-date difference in
gross operating margin). The $121.2 million difference in commodity hedging
results is primarily reflected in the Processing segment.

Since January 1, 2002, segment assets have increased $263.8 million. The
increase is primarily due to the Diamond-Koch acquisitions completed during the
first quarter of 2002 and the Toca-Western acquisition in June 2002 (see Note
2). Intangible assets increased $47.0 million since January 1, 2002 primarily
the result of the contract-based intangible assets we acquired from Diamond-Koch
(see Note 7). Goodwill was $81.5 million at June 30, 2002 due to the goodwill we
added as a result of the Diamond-Koch acquisition and the reclassification of
the goodwill associated with the 1999 MBA acquisition (see Note 7).

15. SUBSEQUENT EVENTS

PURCHASE OF INTERESTS IN MAPLETREE AND E-OAKTREE

On August 1, 2002, we announced the purchase of equity interests in
affiliates of Williams, which in turn, own controlling interests in Mid-America
Pipeline Company, LLC (formerly Mid-America Pipeline Company) and Seminole
Pipeline Company. The purchase price of the acquisition was approximately $1.2
billion (subject to certain post-closing purchase price adjustments). The
effective date of the acquisition was July 31, 2002.

The acquisitions include a 98% ownership interest in Mapletree, LLC
("Mapletree"), owner of a 100% interest in Mid-America Pipeline Company, LLC and
certain propane terminals. The Mid-America pipeline is a major NGL pipeline
system consisting of three NGL pipelines, with 7,226 miles of pipeline, and
average transportation volumes of approximately 850 MBPD. Mid-America's
2,548-mile Rocky Mountain system transports mixed NGLs from the Rocky Mountain
Overthrust and San Juan Basin areas to Hobbs, Texas. Its 2,740-mile Conway North
segment links the large NGL hub at Conway, Kansas to the upper Midwest; its
1,938 mile Conway South system connects the Conway hub with Kansas refineries
and transports mixed NGLs from Conway, Kansas to Hobbs, Texas.

We also acquired a 98% ownership interest in E-Oaktree, LLC, owner of an
80% equity interest in Seminole Pipeline Company. The Seminole pipeline consists
of a 1,281-mile NGL pipeline, with an average transportation volume of
approximately 260 MBPD. This pipeline transports mixed NGLs and NGL products
from Hobbs, Texas and the Permian Basin to Mont Belvieu, Texas.

The post-closing purchase price adjustments of the Mapletree and E-Oaktree
acquisitions are expected to be completed during the fourth quarter of 2002.
These acquisitions do not require any material governmental approvals.

These acquisitions were funded by a $1.2 billion senior unsecured 364-day
term loan entered into by the Operating Partnership on July 31, 2002. The
lenders under this facility are Wachovia Bank, National Association; Lehman
Brothers Bank, FSB; Lehman Commercial Paper Inc. and Royal Bank of Canada. As
defined within the credit agreement, the loan will generally bear interest at
either (i) the greater of (a) the Prime Rate or (b) the Federal Funds Effective
Rate plus one-half percent or (ii) a Eurodollar rate, with any rate in effect
being increased by an appropriate applicable margin. The credit agreement
contains various affirmative and negative covenants applicable to the Operating
Partnership similar to those required under our Multi-Year and 364-Day Credit
Facility agreements. The $1.2 billion term loan is guaranteed by Enterprise
Products Partners L.P. through an unsecured guarantee. The loan will be repaid
as follows: $150 million due on December 31, 2002, $450 million on March 31,
2003 and $600 million on July 30, 2003.

On August 1, 2002, Seminole Pipeline Company had $60 million in senior
unsecured notes due in December 2005. The principal amount of these notes
amortize by $15 million each December 1 through

F-74

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

2005. In accordance with GAAP, this debt will be consolidated on our balance
sheet because of our 98% controlling interest in E-Oaktree, LLC, which owns 80%
of Seminole Pipeline Company.

THIRD AMENDMENT TO OUR MULTI-YEAR AND 364-DAY CREDIT FACILITIES

On July 31, 2002, certain covenants of our Multi-Year and 364-Day Credit
Facilities were further amended to allow for increased financial flexibility in
light of the Mapletree and E-Oaktree acquisitions. As defined within the third
amendment to each of these loan agreements, the maximum ratio of Consolidated
Indebtedness to Consolidated EBITDA allowed by our lenders was increased as
follows from that noted in the second amendment issued in April 2002:

CHANGES MADE TO THE
CONSOLIDATED INDEBTEDNESS TO CONSOLIDATED EBITDA RATIO
-------------------------------------------------------------------------------------------
MAXIMUM RATIO ALLOWED
--------------------------------
CALCULATION MADE FOR OLD PROVISIONS NEW PROVISIONS
THE ROLLING FOUR-QUARTER UNDER 2ND UNDER 3RD
PERIOD ENDING AMENDMENT AMENDMENT
------------------------ -------------- --------------

September 30, 2002....................................... 4.50 to 1.0 6.00 to 1.0
December 31, 2002........................................ 4.00 to 1.0 5.25 to 1.0
March 31, 2003........................................... 4.00 to 1.0 5.25 to 1.0
June 30, 2003............................................ 4.00 to 1.0 4.50 to 1.0
September 30, 2003 and for each rolling-four quarter
period thereafter...................................... 4.00 to 1.0 4.00 to 1.0

In addition, the negative covenant on Indebtedness (as defined within the
Multi-Year and 364-Day credit agreements) was amended to permit the Seminole
Pipeline Company indebtedness assumed in connection with the acquisition of
E-Oaktree.

F-75

REPORT OF INDEPENDENT AUDITORS

The Board of Directors of
The Williams Companies, Inc.:

We have audited the accompanying combined balance sheets of Mid-America
Pipeline System (A Division of The Williams Companies, Inc.) (See Note 1) as of
December 31, 2000 and 2001 and the related combined statements of operations and
owner equity and cash flows for each of the three years in the period ended
December 31, 2001. These financial statements are the responsibility of The
Williams Companies, Inc.'s management. Our responsibility is to express an
opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.

In our opinion, the combined financial statements referred to above present
fairly, in all material respects, the combined financial position of Mid-America
Pipeline System (A Division of The Williams Companies, Inc.) (See Note 1) at
December 31, 2000 and 2001 and the combined results of their operations and
their cash flows for each of the three years in the period ended December 31,
2001, in conformity with accounting principles generally accepted in the United
States.

ERNST & YOUNG LLP

Tulsa, Oklahoma
September 6, 2002

F-76

MID-AMERICA PIPELINE SYSTEM
(A DIVISION OF THE WILLIAMS COMPANIES, INC.)

COMBINED STATEMENTS OF OPERATIONS AND OWNER EQUITY

SIX MONTHS ENDED
FOR YEARS ENDED DECEMBER 31, JUNE 30,
------------------------------ -------------------
1999 2000 2001 2001 2002
-------- -------- -------- -------- --------
(UNAUDITED)
(DOLLARS IN THOUSANDS)

REVENUES................................ $190,686 $209,895 $214,518 $102,244 $109,865
COSTS AND EXPENSES
Operating costs and expenses............ 87,623 105,591 125,349 67,870 45,111
Selling, general and administrative..... 28,718 29,307 28,364 13,807 15,130
-------- -------- -------- -------- --------
Total......................... 116,341 134,898 153,713 81,677 60,241
-------- -------- -------- -------- --------
OPERATING INCOME........................ 74,345 74,997 60,805 20,567 49,624
OTHER INCOME (EXPENSE)
Interest expense........................ (7,673) (13,500) (12,700) (6,947) (4,432)
Other, net.............................. 822 880 (1,035) 89 (748)
-------- -------- -------- -------- --------
Total......................... (6,851) (12,620) (13,735) (6,858) (5,180)
-------- -------- -------- -------- --------
INCOME BEFORE INCOME TAXES.............. 67,494 62,377 47,070 13,709 44,444
PROVISION FOR INCOME TAXES.............. (23,651) (22,826) (17,445) (4,894) (16,604)
-------- -------- -------- -------- --------
NET INCOME.............................. $ 43,843 $ 39,551 $ 29,625 $ 8,815 $ 27,840
DIVIDEND OF ASSETS...................... -- (4,127) -- -- (23,571)
OWNER CONTRIBUTION...................... -- -- -- -- 34,381
OWNER EQUITY AT BEGINNING OF PERIOD..... 278,917 322,760 358,184 358,184 387,809
-------- -------- -------- -------- --------
OWNER EQUITY AT END OF PERIOD........... $322,760 $358,184 $387,809 $366,999 $426,459
======== ======== ======== ======== ========

See Notes to Financial Statements
F-77

MID-AMERICA PIPELINE SYSTEM
(A DIVISION OF THE WILLIAMS COMPANIES, INC.)

COMBINED BALANCE SHEETS

DECEMBER 31,
------------------- JUNE 30,
2000 2001 2002
-------- -------- -----------
(UNAUDITED)
(DOLLARS IN THOUSANDS)

ASSETS
CURRENT ASSETS
Accounts receivable -- affiliates......................... $ 9,396 $ 16,181 $ 20,506
Accounts receivable -- other.............................. 743 540 1,383
Income taxes due from affiliates.......................... 8,213 -- 11,855
Product inventory......................................... 30,562 15,416 10,210
Prepaid and other current assets.......................... 4,283 2,017 868
-------- -------- --------
Total current assets.............................. 53,197 34,154 44,822
PROPERTY, PLANT AND EQUIPMENT, NET.......................... 680,735 673,627 633,937
OTHER ASSETS................................................ 2,851 3,054 2,844
-------- -------- --------
TOTAL............................................. $736,783 $710,835 $681,603
======== ======== ========

LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable -- trade................................. $ 7,263 $ 6,518 $ 5,178
Accounts payable -- affiliates........................... 163,552 93,292 26,726
Income taxes due to affiliates............................ -- 381 --
Accrued taxes, other than income taxes.................... 4,616 5,400 7,777
Other current liabilities................................. 475 1,951 2,468
-------- -------- --------
Total current liabilities......................... 175,906 107,542 42,149
LONG-TERM DEBT.............................................. 90,000 90,000 90,000
DEFERRED INCOME TAXES....................................... 112,351 119,259 122,611
OTHER LONG-TERM LIABILITIES................................. 342 6,225 384
COMMITMENTS
OWNER EQUITY................................................ 358,184 387,809 426,459
-------- -------- --------
TOTAL............................................. $736,783 $710,835 $681,603
======== ======== ========

See Notes to Financial Statements
F-78

MID-AMERICA PIPELINE SYSTEM
(A DIVISION OF THE WILLIAMS COMPANIES, INC.)

COMBINED STATEMENTS OF CASH FLOWS

SIX MONTHS ENDED
FOR YEARS ENDED DECEMBER 31, JUNE 30,
------------------------------- -------------------
1999 2000 2001 2001 2002
--------- -------- -------- -------- --------
(UNAUDITED)
(DOLLARS IN THOUSANDS)

OPERATING ACTIVITIES
Net income............................... $ 43,843 $ 39,551 $ 29,625 $ 8,815 $ 27,840
Adjustments to reconcile net income to
cash flows provided by (used for)
operating activities:
Depreciation........................... 19,020 25,000 25,001 12,392 12,291
Lower of cost or market adjustment..... -- -- 18,833 12,903 --
Deferred income taxes.................. 13,048 7,175 7,060 1,892 3,196
Net effect of changes in operating
accounts............................ 48,456 (51,002) (62,626) (32,600) (41,237)
--------- -------- -------- -------- --------
Operating activities cash flows..... 124,367 20,724 17,893 3,402 2,090
--------- -------- -------- -------- --------
INVESTING ACTIVITIES
Capital expenditures..................... (137,427) (20,844) (18,573) (3,534) (2,192)
Proceeds from sale of assets............. 13,060 120 680 132 102
--------- -------- -------- -------- --------
Investing activities cash flows..... (124,367) (20,724) (17,893) (3,402) (2,090)
--------- -------- -------- -------- --------
CHANGE IN CASH AND CASH EQUIVALENTS...... -- -- -- -- --
CASH AND CASH EQUIVALENTS AT BEGINNING OF
PERIOD................................. -- -- -- -- --
--------- -------- -------- -------- --------
CASH AND CASH EQUIVALENTS AT END OF
PERIOD................................. $ -- $ -- $ -- $ -- $ --
========= ======== ======== ======== ========

See Notes to Financial Statements

F-79

MID-AMERICA PIPELINE SYSTEM
(A DIVISION OF THE WILLIAMS COMPANIES, INC.)

NOTES TO COMBINED FINANCIAL STATEMENTS
(INFORMATION PERTAINING TO JUNE 30, 2002 AND TO THE
SIX MONTHS ENDED JUNE 30, 2001 AND 2002 IS UNAUDITED)

1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

These financial statements and accompanying notes represent the combined
historical financial information of (i) Mid-America Pipeline Company ("MAPL")
and (ii) certain terminals and storage facilities ("Terminals and Storage"), all
of which is owned by The Williams Companies, Inc. Unless the context requires
otherwise, references to "we", "us", "our", or the "Company" are intended to
mean MAPL and the Terminals and Storage facilities. In addition, references to
"Williams" in these footnotes are intended to mean The Williams Companies, Inc.
and its affiliates.

MAPL, a Delaware corporation, was organized in May 1968 for the purpose of
owning and operating a natural gas liquids ("NGLs") pipeline. Since its
formation, MAPL's operations have expanded to include the transportation,
pumping, metering and underground storage of a variety of NGLs, including
demethanized mix, ethane-propane mix and specification liquid products. Our
primary asset is the pipeline system located in the Rocky Mountains, the Midwest
and a portion of the Southwest United States. Approximately 20 natural gas
processing plants in Wyoming, Utah and Colorado feed NGLs into the MAPL system
for delivery to several destinations.

The Terminals and Storage facilities, were contributed by Williams to
Sapling LLC ("Sapling"), a Delaware corporation, organized in July 2002 by
Williams. The MAPL system serves the Midwestern U.S. heating market via
Sapling's 16 propane truck-loading terminals located on the MAPL system. Sapling
also owns underground NGL storage capacity that provides operating flexibility
along the MAPL system.

Also in July 2002, Williams converted MAPL from a corporation to a limited
liability company, Mid-America Pipeline Company, LLC ("MAPL, LLC"). Williams
then contributed Sapling to MAPL, LLC. On July 31, 2002, Williams contributed
its 100% equity interest in MAPL, LLC to a newly formed affiliate of Williams,
Mapletree, LLC. This contribution was done as part of a subsequent transaction
that took place between Williams and Enterprise Products Operating L.P ("EPOLP")
on the same date, whereby EPOLP purchased a 98% equity interest in Mapletree,
LLC for $940.2 million.

Immediately prior to the sale of 98% of Williams' membership interest in
MAPL, LLC to EPOLP, all long-term debt of MAPL, LLC was repaid.

The interim financial data is unaudited; however, in the opinion of
management, the interim financial data includes all adjustments, consisting of
normal recurring adjustments, necessary for a fair presentation of the financial
position as of June 30, 2002 and the results of operations for the six-month
periods ended June 30, 2001 and 2002. The results of operations for the six
months ended June 30, 2001 and 2002 are not necessarily indicative of the
results to be expected for the full year.

DOLLAR AMOUNTS presented in the tabulations within the notes to our
financial statements are stated in thousands of dollars, unless otherwise
indicated.

ENVIRONMENTAL expenditures that relate to current or future revenues are
expensed or capitalized based upon the nature of the expenditures. Expenditures
resulting from an existing condition caused by past operations that do not
contribute to current or future revenue generation are expensed. Environmental
liabilities are recorded independently of any potential claim for recovery.
Receivables are recognized in cases where the realization of reimbursements of
remediation costs are considered probable. Accruals related to environmental
matters are generally determined based on site-specific plans for remediation,
taking into account the prior remediation experience of the Company.

INCOME TAXES are computed using the liability method and are provided on
all temporary differences between the financial basis and the tax basis of the
Company's assets and liabilities. For federal

F-80

MID-AMERICA PIPELINE SYSTEM
(A DIVISION OF THE WILLIAMS COMPANIES, INC.)

NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

income tax reporting, the Company is included in Williams' consolidated tax
return. The provision for income taxes has been charged to the Company as if
separate income tax returns were filed.

LONG-LIVED ASSETS are reviewed for impairment whenever events or changes in
circumstances indicate that the carrying amount of an asset may not be
recoverable. Long-lived assets that are held for disposal are valued at the
lower of carrying amount or fair value less cost to sell.

PRODUCT INVENTORY consists of various NGL products we utilize in the
operation of our pipeline. Product inventory is valued at the lower of average
cost or market. For the year ended December 31, 2001, operating costs and
expenses include a lower of average cost or market adjustment of $18.8 million.

PROPERTY, PLANT AND EQUIPMENT is recorded at cost and is depreciated using
the straight-line method over the asset's estimated useful life at annual rates
ranging from 1.40% to 11.30%. Expenditures for maintenance and repairs are
charged to operations in the period incurred.

REVENUE is based on tariffs charged to customers for pipeline volumes
transported. Shippers are invoiced and the related revenue is recorded as
deliveries are made.

USE OF ESTIMATES AND ASSUMPTIONS by management that affect the reported
amounts of assets and liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period are required for the
preparation of financial statements in conformity with accounting principles
generally accepted in the United States. Our actual results could differ from
these estimates.

2. RECENTLY ISSUED ACCOUNTING STANDARDS

The Financial Accounting Standards Board ("FASB") issued Statement of
Financial Accounting Standards ("SFAS") No. 143, "Accounting for Asset
Retirement Obligations" in June 2001. This statement establishes accounting
standards for the recognition and measurement of a liability for an asset
retirement obligation and the associated asset retirement cost. This statement
is effective for our fiscal year beginning January 1, 2003. We are evaluating
the provisions of this statement.

In April 2002, the FASB issued SFAS No. 145, "Rescission of SFAS Statements
No. 4, 44, and 64, Amendment of SFAS No. 13, and Technical Corrections." The
purpose of this statement is to update, clarify and simplify existing accounting
standards. We adopted this statement effective April 30, 2002 and determined
that it did not have any significant impact on our financial statements as of
that date. In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities." This standard requires companies
to recognize costs associated with exit or disposal activities when they are
incurred. Examples of costs covered by the standard include lease termination
costs and certain employee severance costs that are associated with a
restructuring, discontinued operation, plant closing, or other exit or disposal
activity. Previous accounting guidance was provided by EITF Issue No. 94-3,
"Liability Recognition for Certain Employee Termination Benefits and Other Costs
to Exit an Activity (including Certain Costs Incurred in a Restructuring)." SFAS
No. 146 replaces Issue 94-3. SFAS No. 146 is to be applied prospectively to exit
or disposal activities initiated after December 31, 2002. This statement is
effective for our fiscal year beginning January 1, 2003. We are evaluating the
provisions of this statement.

F-81

MID-AMERICA PIPELINE SYSTEM
(A DIVISION OF THE WILLIAMS COMPANIES, INC.)

NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

3. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consists of the following at the periods
indicated:

DECEMBER 31,
-------------------- JUNE 30,
2000 2001 2002
--------- -------- ------------
(UNAUDITED)

Pipelines and related equipment.................... $ 970,393 $981,733 $ 943,115
Land............................................... 1,303 1,445 1,445
--------- -------- ---------
Total............................................ 971,696 983,178 944,560
Less accumulated depreciation...................... (290,961) (309,551) (310,623)
--------- -------- ---------
Property, plant and equipment, net............... $ 680,735 $673,627 $ 633,937
========= ======== =========

During 1999, we capitalized $7.0 million of interest related to a pipeline
expansion project.

During 2002, we contributed fixed assets with a net book value of $23.6
million to an affiliate of Williams. The transaction was accounted for as a
non-cash dividend.

4. LONG-TERM DEBT

During 1992, we issued five different series of Senior Unsecured Notes in
the private placement market. The notes have a combined principal balance of $90
million with interest rates between 8.20% to 8.95%. The notes have principal
payments beginning in July 2007. Interest is paid semi-annually either January 1
and July 1 or April 30 and October 30. The note agreements contain restrictive
covenants, which limit the payment of advances or dividends to stockholders and
restrict additional borrowing of funds. Such provisions restricted $100 million
of combined net worth related to MAPL at December 31, 2001. We were in
compliance with these covenants at December 31, 2001.

5. INCOME TAXES

The provision for income taxes are as follows for the periods indicated:

FOR YEARS ENDED DECEMBER 31,
------------------------------
1999 2000 2001
-------- -------- --------

Current:
Federal............................................... $ 9,327 $15,342 $ 9,718
State................................................. 1,276 309 667
------- ------- -------
10,603 15,651 10,385
Deferred:
Federal............................................... 11,702 6,088 6,105
State................................................. 1,346 1,087 955
------- ------- -------
Provision for income taxes.............................. $23,651 $22,826 $17,445
======= ======= =======

F-82

MID-AMERICA PIPELINE SYSTEM
(A DIVISION OF THE WILLIAMS COMPANIES, INC.)

NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

Reconciliations from the provision for income taxes at the U.S. federal
statutory rate to the effective tax rate for the provision for income taxes are
as follows:

FOR YEARS ENDED DECEMBER 31,
------------------------------
1999 2000 2001
-------- -------- --------

Provision at statutory rate............................. $23,623 $21,832 $16,474
Increases (reductions) in taxes resulting from:
State income taxes (net of federal benefit)........... 1,704 907 1,054
Other................................................. (1,676) 87 (83)
------- ------- -------
Provision for income taxes.............................. $23,651 $22,826 $17,445
======= ======= =======

Significant components of deferred tax liabilities and assets as of
December 31, 2000 and 2001 are as follows:

DECEMBER 31,
-------------------
2000 2001
-------- --------

Deferred tax liabilities:
Property, plant and equipment............................. $115,474 $122,138
Other..................................................... -- 338
-------- --------
Total deferred tax liabilities......................... 115,474 122,476
-------- --------
Deferred tax assets:
Accrued liabilities....................................... 167 140
Other..................................................... 2,956 3,077
-------- --------
Total deferred tax assets.............................. 3,123 3,217
-------- --------
Net deferred tax liabilities................................ $112,351 $119,259
======== ========

6. RELATED PARTY TRANSACTIONS

Williams' affiliated companies transport product in our pipelines.
Operating revenues from affiliates were as follows:

FOR YEARS ENDED DECEMBER 31,
------------------------------
1999 2000 2001
-------- -------- --------

Revenues from affiliates................................ $30,328 $40,531 $46,954
Revenues from affiliates as a percentage of total
revenues.............................................. 16% 19% 22%

At December 31, 2000 and 2001, we held affiliate receivable balances of
$8.5 million and $14.3 million respectively, from Seminole Pipeline Company
("Seminole"), an 80%-owned subsidiary of Williams, primarily for MAPL's share of
the joint tariff on movements generated in MAPL's pipeline system. MAPL is paid
for its share of the joint tariff following delivery of NGLs to destinations on
Seminole's pipeline system.

Williams charges their affiliates for certain general and administrative
expenses that are directly identifiable or allocable to the affiliates. The
majority of these expenses are reflected within general and administrative
expenses. Allocated general and administrative expenses are based on a
three-factor formula,

F-83

MID-AMERICA PIPELINE SYSTEM
(A DIVISION OF THE WILLIAMS COMPANIES, INC.)

NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

which is accepted by the Federal Energy Regulatory Commission and considers
operating margins, property, plant and equipment and payroll. These allocated
costs from various Williams subsidiaries were as follows:

FOR YEARS ENDED DECEMBER 31,
------------------------------
1999 2000 2001
-------- -------- --------

Allocated G&A expenses.................................. $23,321 $26,783 $19,067

In addition to the above allocations, Williams allocates interest based on
intercompany account balances. Allocated interest expense from Williams was as
follows:

FOR YEARS ENDED DECEMBER 31,
------------------------------
1999 2000 2001
-------- -------- --------

Allocated Interest Expense................................. $6,931 $5,620 $4,300

Due to MAPL holding no cash, Williams pays all MAPL payables, causing us to
hold payables to affiliates. Collections on our receivables are netted against
the affiliate payable account.

7. MAJOR CUSTOMERS

Two non-affiliated shippers accounted for 18% and 12% of operating revenues
for the year ended December 31, 1999. One non-affiliated shipper accounted for
21% and 17% of operating revenues for the years ended December 31, 2000 and
2001.

8. COMMITMENTS

During 2001, we leased certain fixed asset equipment under a 15-year
capital lease. At December 31, 2001, the lease had a balance of $5.8 million and
an implied interest rate of approximately 14%. The balance of the lease along
with the associated fixed assets were transferred to an affiliate in April 2002.

9. SUPPLEMENTAL CASH FLOWS DISCLOSURE

SIX MONTHS ENDED
FOR YEARS ENDED DECEMBER 31, JUNE 30,
----------------------------- -------------------
1999 2000 2001 2001 2002
------- -------- -------- -------- --------
(UNAUDITED)

(Increase) decrease in:
Accounts receivable...................... $(2,124) $ (544) $ (6,582) $ (5,358) $ (5,168)
Income taxes due from affiliates......... -- (8,213) 8,213 3,076 (11,855)
Product inventory........................ -- (41,455) (3,687) (1,162) 5,206
Prepaid and other current assets......... (346) (3,392) 2,266 1,633 1,149
Other assets............................. 1,948 183 (203) (68) 210
Increase (decrease) in:
Accounts payable......................... 54,124 23,646 (71,005) (33,906) (33,530)
Accrued taxes............................ (2,579) (14,516) 1,160 2,863 2,001
Other current liabilities................ (1,762) (6,370) 1,329 322 809
Other liabilities........................ (805) (341) 5,883 -- (59)
------- -------- -------- -------- --------
Net effect of changes in operating
accounts................................. $48,456 $(51,002) $(62,626) $(32,600) $(41,237)
======= ======== ======== ======== ========

Income taxes paid were $12.8 million, $39.4 million and $2.0 million for
the year ended December 31, 1999, 2000 and 2001, respectively, and $25.6 million
for the six months ended June 30, 2002. No income

F-84

MID-AMERICA PIPELINE SYSTEM
(A DIVISION OF THE WILLIAMS COMPANIES, INC.)

NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

taxes were paid during the six months ended June 30, 2001. Interest paid was
$7.8 million, $8.4 million and $13.0 million for 1999, 2000 and 2001,
respectively, and $6.3 million and $3.6 million for the six months ended June
30, 2001 and 2002, respectively.

During 2002, Williams made an equity contribution to us in the amount of
$34.4 million. The non-cash transaction was accounted for as a reduction to
accounts payable -- affiliate and an increase to owner equity.

10. FAIR VALUE OF FINANCIAL INSTRUMENTS

The following disclosure of estimated fair value was determined by us,
using available market information and appropriate valuation methodologies.
Considerable judgment, however, is necessary to interpret market data and
develop the related estimates of fair value. Accordingly, the estimates
presented herein are not necessarily indicative of the amounts that we could
realize upon disposition of the financial instruments. The use of different
market assumptions and/or estimation methodologies may have a material effect on
the estimated fair value amounts.

Long-term debt. Debt consists of private placement senior notes. The fair
value of private debt is valued based on the prices of similar securities with
similar terms and credit ratings.

The carrying amounts and fair values for our financial instruments at
December 31, 2000 and 2001 are as follows:

2000 2001
------------------ ------------------
CARRYING FAIR CARRYING FAIR
VALUE VALUE VALUE VALUE
-------- ------- -------- -------

Long-term debt................................. $90,000 $99,479 $90,000 $98,737

11. SIGNIFICANT CONCENTRATIONS OF RISK

All of our revenues are derived from the transportation of NGLs to various
companies in the NGL industry, primarily located in the United States. Although
this concentration could affect our overall exposure to credit risk since these
customers might be affected by similar economic or other conditions, management
believes that the Company is exposed to minimal credit risk, since the majority
of our business is conducted with major companies within the industry. We
perform periodic credit evaluations of our customers' financial condition and
generally do not require collateral for receivables.

F-85

REPORT OF INDEPENDENT AUDITORS

The Board of Directors of
Seminole Pipeline Company:

We have audited the accompanying balance sheets of Seminole Pipeline
Company as of December 31, 2000 and 2001 and the related accompanying statements
of operations, statements of stockholders' equity, and cash flows for each of
the three years in the period ended December 31, 2001. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.

In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Seminole Pipeline Company at
December 31, 2000 and 2001 and the results of its operations and its cash flows
for each of the three years in the period ended December 31, 2001, in conformity
with accounting principles generally accepted in the United States.

ERNST & YOUNG LLP

Tulsa, Oklahoma
March 6, 2002,
except for the matter described in Note 14,
as to which the date is September 6, 2002

F-86

SEMINOLE PIPELINE COMPANY

STATEMENTS OF OPERATIONS

SIX MONTHS ENDED
FOR YEARS ENDED DECEMBER 31, JUNE 30,
----------------------------- -----------------
1999 2000 2001 2001 2002
-------- ------- -------- ------- -------
(RESTATED) (UNAUDITED)
(DOLLARS IN THOUSANDS)

REVENUES..................................... $ 64,210 $66,609 $65,800 $30,880 $34,856
COSTS AND EXPENSES
Operating costs and expenses................. 27,278 37,293 33,539 16,430 17,315
Selling, general and administrative.......... 1,035 1,700 1,535 750 796
-------- ------- ------- ------- -------
Total................................... 28,313 38,993 35,074 17,180 18,111
-------- ------- ------- ------- -------
OPERATING INCOME............................. 35,897 27,616 30,726 13,700 16,745
OTHER INCOME (EXPENSE)
Interest expense............................. (5,002) (5,003) (5,160) (2,450) (2,006)
Other, net................................... 670 (1,542) 662 (9) (7)
-------- ------- ------- ------- -------
Total................................... (4,332) (6,545) (4,498) (2,459) (2,013)
-------- ------- ------- ------- -------
INCOME BEFORE INCOME TAXES................... 31,565 21,071 26,228 11,241 14,732
PROVISION FOR INCOME TAXES................... (11,611) (7,590) (9,470) (3,837) (5,347)
-------- ------- ------- ------- -------
NET INCOME................................... $ 19,954 $13,481 $16,758 $ 7,404 $ 9,385
======== ======= ======= ======= =======

See Notes to Financial Statements

F-87

SEMINOLE PIPELINE COMPANY

BALANCE SHEETS

DECEMBER 31,
------------------- JUNE 30,
2000 2001 2002
-------- -------- -----------
(RESTATED) (UNAUDITED)
(DOLLARS IN THOUSANDS)

ASSETS
CURRENT ASSETS
Cash and cash equivalents................................. $ 11,535 $ 16,513 $ 11,160
Accounts receivable -- trade.............................. 6,066 10,995 8,791
Accounts receivable -- affiliates......................... 1,582 2,783 7,791
Accounts receivable -- other.............................. 117 152 408
Income taxes due from affiliates.......................... -- -- 1,637
Prepaid and other current assets.......................... 87 35 122
-------- -------- --------
Total current assets.............................. 19,388 30,479 29,909
PROPERTY, PLANT AND EQUIPMENT, NET.......................... 261,358 251,751 249,390
OTHER ASSETS................................................ 194 170 440
-------- -------- --------
TOTAL............................................. $280,940 $282,399 $279,739
======== ======== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Current portion of long-term debt......................... $ 15,000 $ 15,000 $ 15,000
Accounts payable -- trade................................. 4,644 2,646 2,389
Accounts payable -- affiliates........................... 15,437 15,460 17,948
Accrued income taxes due affiliates....................... 54 8,471 --
Accrued taxes, other than income taxes.................... 2,557 2,717 2,665
Other current liabilities................................. 3,265 796 1,853
-------- -------- --------
Total current liabilities......................... 40,957 45,090 39,855
LONG-TERM DEBT.............................................. 60,000 45,000 45,000
DEFERRED INCOME TAXES....................................... 58,858 59,226 59,116
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY
Capital stock:
Preferred stock, Series A, without par value, $100
stated value; 100 shares authorized and issued;
involuntary liquidation preference aggregated
$79,170.............................................. 10 10 10
Common stock, $100 par value; 1,000 shares authorized
and issued........................................... 100 100 100
Paid-in capital........................................ 114,357 114,357 114,357
Retained earnings...................................... 6,658 18,616 21,301
-------- -------- --------
Total stockholders' equity........................ 121,125 133,083 135,768
-------- -------- --------
Total............................................. $280,940 $282,399 $279,739
======== ======== ========

See Notes to Financial Statements

F-88

SEMINOLE PIPELINE COMPANY

STATEMENTS OF STOCKHOLDERS' EQUITY

PREFERRED COMMON PAID-IN RETAINED
STOCK STOCK CAPITAL EARNINGS TOTAL
--------- ------ -------- -------- --------
(DOLLARS IN THOUSANDS)

Balance, December 31, 1998................. $10 $100 $114,357 $ 28,813 $143,280
Net income................................. -- -- -- 19,954 19,954
Cash dividends paid to stockholders........ -- -- -- (24,000) (24,000)
--- ---- -------- -------- --------
Balance, December 31, 1999................. 10 100 114,357 24,767 139,234
Net income (restated)...................... -- -- -- 13,481 13,481
Cash dividends paid to stockholders........ -- -- -- (31,590) (31,590)
--- ---- -------- -------- --------
Balance, December 31, 2000 (restated)...... 10 100 114,357 6,658 121,125
Net income (restated)...................... -- -- -- 16,758 16,758
Cash dividends paid to stockholders........ -- -- -- (4,800) (4,800)
--- ---- -------- -------- --------
Balance, December 31, 2001 (restated)...... 10 100 114,357 18,616 133,083
Net income (unaudited)..................... -- -- -- 9,385 9,385
Cash dividends paid to stockholders
(unaudited).............................. -- -- -- (6,700) (6,700)
--- ---- -------- -------- --------
Balance, June 30, 2002 (unaudited)......... $10 $100 $114,357 $ 21,301 $135,768
=== ==== ======== ======== ========

See Notes to Financial Statements

F-89

SEMINOLE PIPELINE COMPANY

STATEMENTS OF CASH FLOWS

SIX MONTHS ENDED
FOR YEARS ENDED DECEMBER 31, JUNE 30,
------------------------------ ------------------
1999 2000 2001 2001 2002
-------- -------- -------- ------- --------
(RESTATED) (UNAUDITED)
(DOLLARS IN THOUSANDS)

OPERATING ACTIVITIES
Net income................................. $ 19,954 $ 13,481 $ 16,758 $ 7,404 $ 9,385
Adjustments to reconcile net income to cash
flows provided by (used for) operating
activities:
Depreciation and amortization............ 10,125 10,183 10,199 5,095 5,123
Deferred income taxes.................... 1,199 759 368 374 (110)
Net effect of changes in operating
accounts.............................. (12,030) 10,623 (1,982) (4,504) (10,302)
-------- -------- -------- ------- --------
Operating activities cash flows....... 19,248 35,046 25,343 8,369 4,096
-------- -------- -------- ------- --------
INVESTING ACTIVITIES
Capital expenditures....................... (1,964) (810) (576) (297) (2,763)
Proceeds from sale of assets............... 18 15 11 11 14
-------- -------- -------- ------- --------
Investing activities cash flows....... (1,946) (795) (565) (286) (2,749)
-------- -------- -------- ------- --------
FINANCING ACTIVITIES
Long-term debt repayments.................. -- -- (15,000) -- --
Cash dividends paid to stockholders........ (24,000) (31,590) (4,800) (2,000) (6,700)
-------- -------- -------- ------- --------
Financing activities cash flows....... (24,000) (31,590) (19,800) (2,000) (6,700)
-------- -------- -------- ------- --------
CHANGE IN CASH AND CASH EQUIVALENTS........ (6,698) 2,661 4,978 6,083 (5,353)
CASH AND CASH EQUIVALENTS AT BEGINNING OF
PERIOD................................... 15,572 8,874 11,535 11,535 16,513
-------- -------- -------- ------- --------
CASH AND CASH EQUIVALENTS AT END OF
PERIOD................................... $ 8,874 $ 11,535 $ 16,513 $17,618 $ 11,160
======== ======== ======== ======= ========

See Notes to Financial Statements

F-90

SEMINOLE PIPELINE COMPANY

NOTES TO FINANCIAL STATEMENTS
(INFORMATION PERTAINING TO JUNE 30, 2002 AND TO THE
SIX MONTHS ENDED JUNE 30, 2001 AND 2002 IS UNAUDITED)

1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Seminole Pipeline Company ("Seminole"), a Delaware corporation, was
organized in 1981 for the purpose of constructing and operating a common carrier
liquified petroleum products pipeline. Unless the context requires otherwise,
references to "we", "us", "our", or the "Company" are intended to mean Seminole
Pipeline Company. Seminole's 100 shares of non-voting and non-participating
preferred stock and 1,000 shares of common stock are held by Williams Natural
Gas Liquids Inc. ("WNGL") (80%), AMOCO Pipeline Seminole Investment Company
("AMOCO") (10%) and Texaco Natural Gas Liquids Inc. ("Texaco") (10%).

Our operations include the transportation, pumping, metering and
underground storage of natural gas liquids ("NGLs"), including demethanized mix,
ethane-propane mix and specification liquid products. Our primary asset, the
Seminole pipeline primarily transports natural gas liquids ("NGLs") from Hobbs,
Texas and the Permian Basin to Mont Belvieu, Texas. We have only one operating
segment, pipeline transportation.

These financial statements are prepared in accordance with generally
accepted accounting principles in the United States. The information contained
in these financial statements may differ in some respects from the information
filed with the Federal Energy Regulatory Commission ("FERC").

The interim financial data are unaudited; however, in the opinion of
management, the interim financial data includes all adjustments, consisting of
normal recurring adjustments, necessary for a fair presentation of the results
as of June 30, 2002 and for the six-month periods ended June 30, 2001 and 2002.
The results of operations for the six months ended June 30, 2002 and 2001 are
not necessarily indicative of the results to be expected for the full year.

CASH AND CASH EQUIVALENTS consist of short-term, highly liquid investments
that are readily convertible into cash. All investments classified as cash
equivalents have maturities at the date of purchase of three months or less.
Cash flows are computed using the indirect method.

DOLLAR AMOUNTS (except per share amounts) presented in the tabulations
within the notes to our financial statements are stated in thousands of dollars,
unless otherwise indicated.

EARNINGS PER SHARE is generally computed by dividing net income by either
common stock outstanding (for basic earnings per share) or common and preferred
stock outstanding (for diluted earnings per share). We have 1,000 shares of
common stock outstanding and 100 shares of preferred stock outstanding during
all periods presented within these financial statements. Earnings per share is
not presented since the Company is a nonpublic entity that has a simple capital
structure and few stockholders. As a result, we believe an earnings per share
computation would not be meaningful to users of our financial statements.

INCOME TAXES are computed using the liability method and are provided on
all temporary differences between the financial basis and the tax basis of the
Company's assets and liabilities. For federal income tax reporting, the Company
is included in The Williams Companies, Inc. ("Williams") consolidated tax
return. The provision for income taxes has been charged to Seminole as if
separate income tax returns were filed.

F-91

SEMINOLE PIPELINE COMPANY

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

PROPERTY, PLANT AND EQUIPMENT is recorded at cost and is depreciated using
the straight-line method over the asset's estimated useful life at annual rates
ranging from 2.25% to 25%. Expenditures for maintenance and repairs are charged
to operations in the period incurred. The cost of assets retired or sold,
together with the related accumulated depreciation, is removed from the
accounts, and any gain or loss on disposition is included in income.

REVENUE is based on tariffs charged to customers for pipeline volumes
transported. Shippers are invoiced and the related revenue is recorded as
deliveries are made.

USE OF ESTIMATES AND ASSUMPTIONS by management that affect the reported
amounts of assets and liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period are required for the
preparation of financial statements in conformity with accounting principles
generally accepted in the United States. Our actual results could differ from
these estimates.

2. RECENTLY ISSUED ACCOUNTING STANDARDS

In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities." This standard requires companies
to recognize costs associated with exit or disposal activities when they are
incurred. Examples of costs covered by the standard include lease termination
costs and certain employee severance costs that are associated with a
restructuring, discontinued operation, plant closing, or other exit or disposal
activity. Previous accounting guidance was provided by EITF Issue No. 94-3,
"Liability Recognition for Certain Employee Termination Benefits and Other Costs
to Exit an Activity (including Certain Costs Incurred in a Restructuring)." SFAS
No. 146 replaces Issue 94-3. SFAS No. 146 is to be applied prospectively to exit
or disposal activities initiated after December 31, 2002. This statement is
effective for our fiscal year beginning January 1, 2003. We are evaluating the
provisions of this statement.

F-92

SEMINOLE PIPELINE COMPANY

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

3. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consists of the following at the periods
indicated:

DECEMBER 31,
--------------------- JUNE 30,
2000 2001 2002
--------- --------- ------------
(UNAUDITED)

Pipelines and related equipment.................... $ 381,010 $ 381,381 $ 384,065
Land............................................... 964 964 964
--------- --------- ---------
Total............................................ 381,974 382,345 385,029
Less accumulated depreciation...................... (120,616) (130,594) (135,639)
--------- --------- ---------
Property, plant and equipment, net............... $ 261,358 $ 251,751 $ 249,390
========= ========= =========

Depreciation expense for the years ended December 31, 1999, 2000 and 2001
was $10.1 million, $10.2 million and $10.2 million, respectively. Depreciation
expense for each of the six month periods ended June 30, 2001 and 2002 was $5.1
million.

4. LONG-TERM DEBT

In December 1993, we issued $75 million of 6.67% Senior Unsecured Notes in
the private placement market. These notes are payable at $15 million annually on
December 1 from 2001 through 2005. Interest is paid semi-annually on June 1 and
December 1. The Senior Notes agreement contains restrictive covenants, which
limit the payment of advances or dividends to stockholders and restrict
additional borrowing of funds. Such provisions restricted $90 million of
consolidated net worth at December 31, 2001. We were in compliance with these
covenants at December 31, 2001.

5. CAPITAL STRUCTURE

In the event of involuntary liquidation or dissolution the Company, the
holders of the preferred stock are entitled to be paid an amount equal to the
subscription price (stated value of $100 per share) and paid-in capital
(contributions less distributions of paid-in capital) before any holders of
common stock or any other class of stock receive distributions.

Cash dividends paid to stockholders are calculated each quarter based on
the amount of cash flow available. The stockholders receive an amount
proportionate to their ownership percentage.

6. INCOME TAXES

The provision for income taxes are as follows for the periods indicated:

FOR YEARS ENDED DECEMBER 31,
----------------------------
1999 2000 2001
-------- ------- -------

Current:
Federal................................................. $10,139 $6,473 $8,718
State................................................... 273 358 384
------- ------ ------
10,412 6,831 9,102
------- ------ ------
Deferred:
Federal................................................. 1,012 797 334
State................................................... 187 (38) 34
------- ------ ------
Provision for income taxes................................ $11,611 $7,590 $9,470
======= ====== ======

F-93

SEMINOLE PIPELINE COMPANY

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

Reconciliation from the provision for income taxes at the U.S. federal
statutory rate to the effective tax rate for the provision for income taxes are
as follows:

FOR YEARS ENDED DECEMBER 31,
----------------------------
1999 2000 2001
-------- ------- -------

Provision at statutory rate.............................. $11,048 $7,375 $9,180
Increases (reductions) in taxes resulting from:
State income taxes (net of federal benefit)............ 299 208 272
Other.................................................. 264 7 18
------- ------ ------
Provision for income taxes............................... $11,611 $7,590 $9,470
======= ====== ======

Significant components of deferred tax liabilities and assets as of
December 31, 2000 and 2001 are as follows:

DECEMBER 31,
-----------------
2000 2001
------- -------

Deferred tax liabilities:
Property, plant and equipment............................. $61,184 $61,729
------- -------
Total deferred tax liabilities......................... 61,184 61,729
------- -------
Deferred tax assets:
Accrued liabilities....................................... 2,184 2,361
Other..................................................... 142 142
------- -------
Total deferred tax assets.............................. 2,326 2,503
------- -------
Net deferred tax liabilities................................ $58,858 $59,226
======= =======

7. RELATED PARTY TRANSACTIONS

Our stockholders or their affiliated companies transport product in our
pipeline system. Operating revenues from affiliates for the last three years
were as follows:

FOR YEARS ENDED DECEMBER 31,
------------------------------
1999 2000 2001
-------- -------- --------

Revenues from affiliates................................ $30,477 $32,784 $33,006
Revenues from affiliates as a percentage of total
revenues.............................................. 47% 49% 50%

At December 31, 2000 and 2001, we owed $8.5 million and $14.3 million
respectively, to Mid-America Pipeline Company ("MAPL"), a wholly-owned
subsidiary of WNGL, primarily for its share of the joint tariff on movements
originating in MAPL's pipeline system. MAPL is paid for its share of the joint
tariff following delivery of the NGLs to destinations on our system.

In addition, MAPL employees provide pipeline management services to us
pursuant to a service agreement. MAPL charged us $1.0 million, $1.2 million and
$1.2 million for such services during 1999, 2000 and 2001, respectively. We
lease land under an operating lease from an affiliate of AMOCO. Operating lease
expense related to this arrangement was approximately $0.1 million for each of
the years 1999, 2000 and 2001. The fee is adjusted annually in accordance with
the Gross National Product price deflator. The original term of the lease was
fifteen years, beginning August 1, 1981, with a renewal option for three
consecutive

F-94

SEMINOLE PIPELINE COMPANY

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

five-year periods. The lease was renewed on August 1, 1996 and August 1, 2001.
Future minimum payments for this lease are as follows:

2002........................................................ $140
2003........................................................ 143
2004........................................................ 148
2005........................................................ 151
2006........................................................ 106
----
Total minimum obligations................................... $688
====

8. MAJOR CUSTOMERS

One non-affiliated shipper accounted for 17%, 15% and 15% of operating
revenues for the years ended 1999, 2000 and 2001, respectively.

9. COMMITMENTS AND CONTINGENCIES

LEASE COMMITMENTS

We lease land from an affiliate of AMOCO under an operating lease
agreement. See Note 7 for a description of this arrangement.

LITIGATION

On August 10, 1999, a subcontractor installing utility poles for a local
electric utility struck our pipeline. The accident resulted in the death of one
of the subcontractor's employees, destroyed the subcontractor's equipment and
burned the vegetation on nearby lots. During January 2000, the decedent's family
filed suit against us, the subcontractor and the local electric utility. We
recorded an estimate for the settlement in 2000. Settlement was reached with the
decedent's family during February 2001 for $2.3 million. The payment was made
March 9, 2001. The remaining liability of $79,000 is included in other current
liabilities at December 31, 2001, which is to cover remaining legal expenses.

In addition to the foregoing, various proceedings are pending against the
Company incidental to our operations. Management believes the ultimate
resolution of these matters will not have a material adverse effect upon our
future financial position, results of operations or cash flow requirements.

10. SUPPLEMENTAL CASH FLOWS DISCLOSURE

SIX MONTHS ENDED
FOR YEARS ENDED DECEMBER 31, JUNE 30,
----------------------------- ------------------
1999 2000 2001 2001 2002
-------- -------- ------- ------- --------
(UNAUDITED)

(Increase) decrease in:
Accounts receivable....................... $ (6,760) $ 8,222 $(6,165) $(2,526) $ (3,060)
Income taxes due from affiliates.......... -- -- -- -- (1,637)
Prepaid and other current assets.......... 115 (22) 52 (175) (87)
Other assets.............................. 32 1 (2) 26 (283)
Increase (decrease) in:
Accounts payable.......................... (351) 10,678 (1,975) (4,500) 2,231
Accrued taxes............................. 2,317 (10,324) 8,577 4,783 (8,523)
Other current liabilities................. (7,350) 2,068 (2,469) (2,112) 1,057
Other liabilities......................... (33) -- -- -- --
-------- -------- ------- ------- --------
Net effect of changes in operating
accounts.................................. $(12,030) $ 10,623 $(1,982) $(4,504) $(10,302)
======== ======== ======= ======= ========

F-95

SEMINOLE PIPELINE COMPANY

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

Income taxes paid were $9.3 million, $7.5 million and $10.3 million for the
year ended December 31, 1999, 2000 and 2001, respectively, and $5.2 million for
the six months ended June 30, 2002. No income taxes were paid during the six
months ended June 30, 2001. Interest paid was $5.0 million, $5.1 million and
$4.8 million for 1999, 2000 and 2001, respectively, and $2.5 million and $2.1
million for the six months ended June 30, 2001 and 2002, respectively.

11. FAIR VALUE OF FINANCIAL INSTRUMENTS

Cash and cash equivalents. The carrying values reported in the balance
sheets for cash and cash equivalents approximate their fair value.

Long-term debt. Debt consists of a private placement of 6.67% Senior
Notes. The fair value of private debt is valued based on the prices of similar
securities with similar terms and credit ratings.

The carrying amounts and fair values for our financial instruments at
December 31, 2000 and 2001 are as follows:

2000 2001
------------------ ------------------
CARRYING FAIR CARRYING FAIR
VALUE VALUE VALUE VALUE
-------- ------- -------- -------

Long-term debt................................. $75,000 $74,634 $60,000 $60,300

12. SIGNIFICANT CONCENTRATIONS OF RISK

13. SUBSEQUENT EVENTS (UNAUDITED)

On July 31, 2002, WNGL contributed its 80% equity interest in the Company
to a newly-formed affiliate of Williams, E-Oaktree, LLC. This contribution was
done as part of a subsequent transaction which took place between Williams and
Enterprise Products Operating L.P. ("EPOLP") on the same date, whereby EPOLP
purchased a 98% equity interest in E-Oaktree, LLC.

14. RESTATEMENT OF FINANCIAL STATEMENTS

In June 2002, the Company discovered an error in the way their revenue
system was calculating joint tariff revenue. The impact of this error to
revenues and net income was a decrease of $2.9 million and $1.8 million for the
year ended December 31, 2000, respectively, and a decrease of $4.3 million and
$2.8 million for the year ended December 31, 2001, respectively. The correction
of these errors has been reflected in the accompanying restated financial
statements.

F-96

PROSPECTUS

[ENTERPRISE PRODUCTS PARTNERS L.P. LOGO]
ENTERPRISE PRODUCTS PARTNERS L.P.

$500,000,000

ENTERPRISE PRODUCTS PARTNERS L.P.
ENTERPRISE PRODUCTS OPERATING L.P.

COMMON UNITS

DEBT SECURITIES

We may offer the following securities under this Prospectus:

- Common Units representing limited partner interests in Enterprise
Products Partners L.P., and

- Debt Securities of Enterprise Products Operating L.P., which will be
guaranteed by its parent company, Enterprise Products Partners L.P.

This Prospectus provides you with a general description of the securities
we may offer. Each time we sell securities we will provide a Prospectus
Supplement that will contain specific information about the terms of that
offering. The Prospectus Supplement may also add, update or change information
contained in this prospectus. You should read this Prospectus and any Prospectus
Supplement carefully before you invest.

In addition, Common Units may be offered from time to time by other holders
thereof. Any selling unitholders will be identified, and the number of Common
Units to be offered by them will be specified, in a Prospectus Supplement to
this Prospectus. We will not receive proceeds of any sale of shares by any such
selling unitholders.

The Common Units are listed on the New York Stock Exchange under the
trading symbol "EPD." Any Common Units sold pursuant to a Prospectus Supplement
will be listed on that exchange, subject to official notice of issuance. On
March 20, 2001, the closing price of a Common Unit on that exchange was $34.98.

Unless otherwise specified in a Prospectus Supplement, the senior debt
securities, when issued, will be unsecured and will rank equally with our other
unsecured and unsubordinated indebtedness. The subordinated debt securities,
when issued, will be subordinated in right of payment to our senior debt.

YOU SHOULD CAREFULLY REVIEW "RISK FACTORS" BEGINNING ON PAGE 3 FOR A
DISCUSSION OF THINGS YOU SHOULD CONSIDER WHEN INVESTING IN OUR SECURITIES.

NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY STATE SECURITIES
COMMISSION HAS APPROVED OR DISAPPROVED OF THESE SECURITIES OR PASSED UPON THE
ADEQUACY OR ACCURACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A
CRIMINAL OFFENSE.

This Prospectus may not be used to consummate sales of securities unless
accompanied by a Prospectus Supplement.

The date of this Prospectus is March 27, 2001.

TABLE OF CONTENTS

PAGE
----

Forward-Looking Statements.................................. 1
Where You Can Find More Information......................... 2
Incorporation of Certain Documents by Reference............. 2
The Company................................................. 2
Risk Factors................................................ 3
Use of Proceeds............................................. 6
Ratio of Earnings to Fixed Charges.......................... 6
Description of Debt Securities.............................. 6
Description of Common Units................................. 17
Tax Considerations.......................................... 23
Selling Unitholders......................................... 34
Plan of Distribution........................................ 34
Legal Matters............................................... 36
Experts..................................................... 36

FORWARD-LOOKING STATEMENTS

The statements in this Prospectus and the documents incorporated by
reference that are not historical facts are forward-looking statements. We have
based these forward-looking statements on our current expectations and
projections about future events based upon our knowledge of facts as of the date
of this Prospectus and our assumptions about future events. Although we believe
that the expectations reflected in these forward-looking statements are
reasonable, we can give no assurance that these expectations will prove to be
correct. These statements are subject to certain risks, uncertainties, and
assumptions. If one or more of these risks or uncertainties materialize, or if
underlying assumptions provide incorrect, actual results may vary materially
from those anticipated, estimated, projected, or expected. Among the key risk
factors that may have a direct bearing on our results of operations and
financial condition are:

- competitive practices in the industries in which we compete,

- fluctuations in oil, natural gas, and NGL product prices and production,

- operational and systems risks,

- environmental liabilities that are not covered by indemnity or insurance,

- the impact of current and future laws and governmental regulations
(including environmental regulations) affecting the NGL industry in
general, and our operations in particular,

- loss of a significant customer, and

- failure to complete one or more new projects on time or within budget.

We use words like "anticipate," "estimate," "project," "expect," "plan,"
"forecast," "intend," "could," and "may," and similar expressions and statements
regarding our business strategy, plans and objectives for future operations to
help identify forward-looking statements. We have no obligation to publicly
update or revise any forward-looking statement, whether as a result of new
information, future events or otherwise.

WHERE YOU CAN FIND MORE INFORMATION

Enterprise Products Partners L.P. and Enterprise Products Operating L.P.
file annual, quarterly and current reports, proxy statements and other
information with the Securities and Exchange Commission. You may read and copy
any document we file at the Commission's public reference rooms in Washington,
D.C., New York, New York and Chicago, Illinois. Please call the Commission at
(800) SEC-0330 for further information on the public reference rooms. Our
filings are also available to the public at the Commission's web site at
http://www.sec.gov. In addition, documents filed by us can be inspected at the
offices of the New York Stock Exchange, Inc. 20 Broad Street, New York, New York
10002.

INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE

The Commission allows us to "incorporate by reference" into this Prospectus
the information we file with it, which means that we can disclose important
information to you by referring you to those documents. The information
incorporated by reference is considered to be part of this Prospectus, and later
information that we file with the Commission will automatically update and
supersede this information. We incorporate by reference the documents listed
below filed by Enterprise Products Partners L.P. or Enterprise Products
Operating L.P. and any future filings made by either company with the Commission
under section 13(a), 13(c), 14 or 15(d) of the Securities Exchange Act of 1934
until our offering is completed:

(1) Annual Report on Form 10-K for the fiscal year ended December 31,
2000;

(2) Current Reports on Form 8-K filed with the Commission on January
25, 2001 and February 2, 2001; and

(3) The description of the common units contained in the Registration
Statement on Form 8-A, initially filed with the Commission on July 21,
1998, and any subsequent amendment thereto filed for the purposes of
updating such description.

We will provide without charge to each person, including any beneficial
owner, to whom this Prospectus is delivered, upon written or oral request, a
copy of any document incorporated by reference in this Prospectus, other than
exhibits to any such document not specifically described above. Requests for
such documents should be directed to Investor Relations, Enterprise Products
Partners L.P., 2727 North Loop West, Suite 700, Houston, Texas 77008-1038;
telephone number: (713) 880-2724.

THE COMPANY

Enterprise Products Partners L.P. (the "Company") is a publicly traded
master limited partnership that was formed in April 1998 to acquire, own, and
operate all of the NGL processing and distribution assets of Enterprise Products
Company. We conduct all of our business through our 99% owned subsidiary,
Enterprise Products Operating L.P. (the "Operating Partnership") and its
subsidiaries and joint ventures. Enterprise Products GP, LLC (the "General
Partner") is the general partner of the Company and the Operating Partnership,
owning 1.0% and 1.0101% equity interests, respectively, in those partnerships.

We are a leading integrated North American provider of processing and
transportation services to domestic producers of natural gas, domestic and
foreign producers of natural gas liquids ("NGLs") and other liquid hydrocarbons
and domestic and foreign consumers of NGL and liquid hydrocarbon products. We
manage a fully integrated and diversified portfolio of midstream energy assets.
We own and operate:

- natural gas processing plants;

- NGL fractionation facilities;

- storage facilities;

- pipelines;

- propylene production facilities;

- rail transportation facilities; and

- a methyl tertiary butyl ether ("MTBE") production facility.

Certain of these facilities are owned jointly by us and other industry
partners, either through co-ownership arrangements or joint ventures. Some of
these jointly owned facilities are operated by other owners.

Our principal executive office is located at 2727 North Loop West, Houston,
Texas 77008-1038, and our telephone number is (713) 880-6500.

RECENT SIGNIFICANT DEVELOPMENTS

Manta Ray, Nautilus and Nemo Pipeline Systems. On January 29, 2001, we
acquired ownership interests in three natural gas pipeline systems and related
equipment located offshore Louisiana in the Gulf of Mexico from affiliates of El
Paso Energy Corp. for approximately $88 million in cash. These systems total
approximately 360 miles of pipeline. We acquired a 25.67% interest in each of
the Manta Ray and Nautilus pipeline systems and a 33.92% interest in the Nemo
pipeline system. Affiliates of Shell Oil Company own an interest in all three
systems, and an affiliate of Marathon Oil Company owns an interest in the Manta
Ray and Nautilus systems. The Manta Ray system comprises approximately 237 miles
of pipeline with a capacity of 750 million cubic fee ("MMcf") per day and
related equipment, the Nautilus system comprises approximately 101 miles of
pipeline with a capacity of 600 MMcf per day, and the Nemo system, when
completed in the fourth quarter of 2001, will comprise approximately 24 miles of
pipeline with a capacity of 300 MMcf per day.

Stingray Pipeline System and Related Facilities. On January 29, 2001, we
and an affiliate of Shell acquired, through a 50/50 owned entity, the Stingray
natural gas pipeline system and related facilities from an affiliate of El Paso
for approximately $50 million in cash. The Stingray system comprises
approximately 375 miles of pipeline with a capacity of 1.2 billion cubic feet
("Bcf") per day offshore Louisiana in the Gulf of Mexico. Shell will be
responsible for the commercial and physical operations of the Stingray system.

Acadian Gas LLC. On September 25, 2000, we announced that we had executed
a definitive agreement to acquire Acadian Gas, LLC ("Acadian Gas") from an
affiliate of Shell for $226 million in cash, inclusive of working capital.
Acadian Gas' assets are comprised of the 438-mile Acadian, 577-mile Cypress and
27-mile Evangeline natural gas pipeline systems, which together have over one
Bcf per day of capacity. The system includes a leased natural gas storage
facility at Napoleonville, Louisiana. The Acadian Gas system, located in South
Louisiana, will integrate with our Gulf Coast natural gas processing and NGL
fractionation, pipeline and storage system. We expect to close the acquisition
in the first quarter of 2001.

Lou-Tex NGL Pipeline. In November 2000, we completed construction of a
wholly-owned, 206-mile, 12" NGL pipeline from Breaux Bridge, Louisiana to Mont
Belvieu, Texas. The Lou-Tex NGL pipeline transports mixed NGLs, NGL products and
mixed propane/propylene streams between major markets in Louisiana and Texas.

RISK FACTORS

An investment in the securities involves a significant degree of risk,
including the risks described below. You should carefully consider the following
risk factors and the other information in this Prospectus before deciding to
invest in the securities. The risks described below are not the only ones facing
us. This Prospectus also contains forward-looking statements that involve risks
and uncertainties. See "Forward-Looking Statements." Our actual results could
differ materially from those anticipated in the forward-looking statements as a
result of certain factors, including the risks described below and elsewhere in
this Prospectus.

RISKS INHERENT IN OUR BUSINESS

THE PROFITABILITY OF OUR OPERATIONS DEPENDS UPON THE SPREAD BETWEEN NATURAL GAS
PRICES AND NGL.

Prices for natural gas and NGLs are subject to fluctuations in response to
changes in supply, market uncertainty and a variety of additional factors that
are beyond our control. These factors include:

- the level of domestic production;

- the availability of imported oil and gas;

- actions taken by foreign oil and gas producing nations;

- the availability of transportation systems with adequate capacity;

- the availability of competitive fuels;

- fluctuating and seasonal demand for oil, gas and NGLs;

- conservation and the extent of governmental regulation of production and
the overall economic environment.

A decrease in the difference between natural gas and NGL prices results in
lower margins on volumes processed.

THE PROFITABILITY OF OUR OPERATIONS DEPENDS UPON THE DEMAND AND PRICES FOR OUR
PRODUCTS AND SERVICES.

The products that we process are principally used as feedstocks in
petrochemical manufacturing and in the production of motor gasoline and as fuel
for residential and commercial heating. A reduction in demand for our products
by the petrochemical, refining or heating industries, whether because of general
economic conditions, reduced demand by consumers for the end products made with
NGL products, increased competition from petroleum-based products due to

pricing differences, adverse weather conditions, government regulations
affecting prices and production levels of natural gas or the content of motor
gasoline or other reasons, could adversely affect our results of operations.

Ethane. Ethane is primarily used in the petrochemical industry as
feedstock for ethylene, one of the basic building blocks for a wide range of
plastics and other chemical products. Although ethane is typically separated
from the natural gas stream at gas processing plants, if natural gas prices
increase significantly in relation to NGL product prices or if the demand for
ethylene falls, it may be more profitable for natural gas producers to leave the
ethane in the natural gas stream to be burned as fuel than to extract the ethane
from the mixed NGL stream for sale as an ethylene feedstock thereby reducing the
volume of NGLs for fractionation.

Propane. Propane is used both as a petrochemical feedstock in the
production of ethylene and propylene and as a heating, engine and industrial
fuel. The demand for propane as a heating fuel is significantly affected by
weather conditions. The volume of propane sold is at its highest during the
six-month peak heating season of October through March.

Isobutane. Isobutane is predominantly used in refineries to produce
alkylates to enhance octane levels and in the production of MTBE, which is used
in motor gasoline. Accordingly, any action that reduces demand for motor
gasoline in general or MTBE in particular would similarly reduce demand for
isobutane. Further, we purchase a portion of the normal butane feedstock that we
convert into isobutane for our merchant customers in the spot and import
markets. On those occasions where the pricing differential between isobutane and
normal butane (i.e., the "isobutane spread") is narrow, we may find it more
economical to purchase isobutane on the spot market for delivery to customers
than to process the normal butane in our inventory. We frequently retain the
normal butane in our inventory until pricing differentials improve or until
product prices increase. However, if the price of normal butane declines, our
inventory may decline in value. During periods in which isobutane spreads are
narrow or inventory values are high relative to current prices for normal butane
or isobutane, our operating margin from selling isobutane will be reduced.

MTBE. The production of MTBE is driven by oxygenated fuels programs
enacted under the federal Clean Air Amendments of 1990 and other legislation.
Any changes to these programs that enable localities to elect to not participate
in these programs, lessen the requirements for oxygenates or favor the use of
non-isobutane based oxygenated fuels would reduce the demand for MTBE. On March
25, 1999, the Governor of California ordered the phase-out of MTBE in California
by the end of 2002 due to allegations by several public advocacy and protest
groups that MTBE contaminates water supplies, causes health problems and has not
been as beneficial in reducing air pollution as originally contemplated. In
addition, legislation to amend the federal Clean Air Act has been introduced in
the U.S. House of Representatives to ban the use of MTBE as a fuel additive
within three years. Legislation introduced in the U.S. Senate would eliminate
the Clean Air Act's oxygenate requirement in order to foster the elimination of
MTBE in fuel. No assurance can be given as to whether this or similar
legislation ultimately will be adopted or whether the U.S. Congress or the EPA
might take steps to override the MTBE ban in California.

Propylene. Propylene is sold to petrochemical companies for a variety of
uses, principally for the production of polypropylene. Propylene is subject to
rapid and material price fluctuations. Any downturn in the domestic or
international economy could cause reduced demand for, and result in an
oversupply of, propylene, which could cause a reduction in the volumes of
propylene that we produce and expose our investment in inventories of
propane/propylene mix to pricing risk due to requirements for short-term price
discounts in the spot or short-term propylene markets.

THE PROFITABILITY OF OUR OPERATIONS DEPENDS UPON THE AVAILABILITY OF A SUPPLY
OF NGL FEEDSTOCK.

Our profitability is materially impacted by the volume of NGLs processed at
our facilities. A material decrease in natural gas production or crude oil
refining, as a result of depressed commodity prices or otherwise, or a decrease
in imports of mixed butanes, could result in a decline in the volume of NGLs
delivered to our facilities for processing, thereby reducing revenue and
operating income.

WE DEPEND ON CERTAIN KEY CUSTOMERS AND CONTRACTS.

We currently derive a significant portion of our revenues from contracts
with certain key customers. The loss of these or other significant customers
could adversely affect our results of operations. Lyondell Worldwide accounted
for approximately 43.2% of our isomerization volumes in 2000. Our current
contract with Lyondell has a ten-year term which expires in December 2009. Our
unconsolidated affiliate, Belvieu Environmental Fuels ("BEF"), has an agreement
with Sunoco pursuant to which Sunoco is required to purchase all of BEF's MTBE
production through September 2004. Our contract for sales of high purity
propylene to Basell accounted for approximately 36.4% of 2000 production. We are
a party to a natural gas processing contract with Shell and certain of its
affiliates which provides us with the right to process substantially all natural
gas produced from the Shell entities' Gulf of Mexico properties for the next 20
years.

WE EXPERIENCE SIGNIFICANT COMPETITION.

We face competition from oil, natural gas, natural gas processing and
petrochemical companies. The principal areas of competition include obtaining
gas supplies for processing operations, obtaining supplies of raw product for
fractionation and the marketing and transportation of natural gas liquids.
Competition typically arises as a result of the location and operating
efficiency of facilities, the reliability of services and price and delivery
capabilities. Our NGL fractionation facilities at Mont Belvieu compete for
volumes of mixed NGLs with three other fractionators at Mont Belvieu. In
addition, certain major producers fractionate NGLs for their own account in
captive facilities. The Mont Belvieu fractionation facilities also compete on a
more limited basis with two fractionators in Conway, Kansas. We also compete
with large, integrated energy and petrochemical companies in our isomerization,
MTBE, propylene and natural gas processing businesses. Our customers who are
significant producers or consumers of NGLs or natural gas may develop their own
processing facilities in lieu of using our services or co-investing with us in
new projects. In addition, certain of our competitors may have advantages in
competing for acquisitions or other new business opportunities because of their
financial resources and access to NGL supplies.

WE ARE SUBJECT TO OPERATING AND LITIGATION RISKS WHICH MAY NOT BE COVERED BY
INSURANCE.

Our operations are subject to all operating hazards and risks normally
incidental to processing, storing and transporting, and otherwise providing for
use by third parties, natural gas, NGLs, propane/propylene mix and MTBE. As a
result, we may be a defendant in various legal proceedings and litigation
arising in the ordinary course of business. We cannot assure you that the
insurance we maintain will be adequate to protect us from all material expenses
related to potential future claims for personal and property damage.

OUR BUSINESSES ARE SUBJECT TO GOVERNMENTAL REGULATION WITH RESPECT TO
ENVIRONMENTAL, SAFETY AND OTHER REGULATORY MATTERS.

Our business is subject to the jurisdiction of governmental agencies with
respect to a wide range of environmental, safety and other regulatory matters.
We could be adversely affected by increased costs due to more strict pollution
control requirements or liabilities resulting from non-compliance with required
operating or other regulatory permits. New environmental regulations might
adversely impact our products and activities, including processing, storage and
transportation. Federal and state agencies also could impose additional safety
requirements, any of which could affect profitability. In addition, there are
risks of accidental releases or spills associated with our operations, and we
cannot assure you that material costs and liabilities will not be incurred,
including those relating to claims for damages to property and persons.

Our operations are subject to the Clean Air Act and comparable state
statutes. Amendments to the Clean Air Act were adopted in 1990 and contain
provisions that may result in the imposition of certain pollution control
requirements with respect to air emissions from the operations of our pipelines
and processing and storage facilities. For example, our Mont Belvieu processing
and storage facility is located in the Houston-Galveston ozone non-attainment
area, which is categorized as a "severe" area and, therefore, is subject to more
restrictive regulations for the issuance of air permits for new or modified
facilities. The Houston-Galveston area is among nine areas in the country in
this "severe" category. Another consequence of this non-attainment status and
efforts to eliminate it is the potential imposition of lower limits on the
emissions of certain pollutants, particularly oxides of nitrogen which are
produced through combustion, as in the gas turbines at the Mont Belvieu
processing facility. Regulations to achieve attainment status and imposing new
requirements on existing facilities in the Houston-Galveston area were issued by
the Texas Natural Resource Conservation Commission in December, 2000. These
regulations mandate 90% reductions in oxides of nitrogen emissions from point
sources, such as the gas turbines at our Mont Belvieu processing facility. The
technical practicality and economic reasonableness of requiring existing gas
turbines to achieve such reductions, as well as the substantive basis for
setting the 90% reduction requirements, have been challenged under state law in
a suit we filed as part of a coalition of major Houston-Galveston area
industries. If these regulations stand as issued, they would require substantial
redesign and modification of these facilities to achieve the mandated
reductions; however, the precise impact of these requirements on our operations
cannot be determined until this litigation is resolved.

WE DEPEND UPON OUR KEY PERSONNEL.

We believe that our success has been dependent to a significant extent upon
the efforts and abilities of our senior management team and in particular Dan
Duncan, Chairman of the Board (age 68) and O. S. Andras, President and Chief
Executive Officer (age 65). The simultaneous deaths or retirement of Mr. Duncan
and Mr. Andras could have an adverse impact on our operations. However, in
recent years we have added to the key members of our senior management team,

thereby reducing the potential consequences that could result from losing the
services of both Mr. Duncan and Mr. Andras within a short time. We do not
maintain any life insurance for these persons.

RISKS INHERENT IN AN INVESTMENT IN THE SECURITIES

The prospectus supplement accompanying this prospectus will describe any
additional risk factors inherent in an investment in the particular securities
being offering.

USE OF PROCEEDS

Except as may be set forth in a prospectus supplement, we will use the net
proceeds from any sale of securities described in this prospectus for future
business acquisitions and other general corporate purposes, such as working
capital, investments in subsidiaries, the retirement of existing debt and/or the
repurchase of common units or other securities. The exact amounts to be used and
when the net proceeds will be applied to corporate purposes will depend on a
number of factors, including our funding requirements and the availability of
alternative funding sources. We routinely review acquisition opportunities. A
prospectus supplement will disclose any future proposal to use net proceeds from
an offering of our securities to finance any specific acquisition, if
applicable.

We will not receive any proceeds from any sale of common units by any
selling unitholders.

RATIO OF EARNINGS TO FIXED CHARGES

The ratios of earnings to fixed charges for each of the periods indicated
are as follows:

YEAR ENDED DECEMBER 31,
--------------------------------
COMPANY 1996 1997 1998 1999 2000
------- ---- ---- ---- ---- ----

Enterprise Products Partners L.P. .......................... 2.38 2.11 1.16 5.84 6.41
Enterprise Products Operating L.P. ......................... 2.40 2.17 1.16 5.90 6.47

These computations include us and our subsidiaries, and 50% or less equity
companies. For these ratios, "earnings" is the amount resulting from adding and
subtracting the following items.

Add the following:

- pre-tax income from continuing operations before adjustment for minority
interests in consolidated subsidiaries or income or loss from equity
investees;

- fixed charges;

- amortization of capitalized interest;

- distributed income of equity investees; and

- our share of pre-tax losses of equity investees for which charges arising
from guarantees are included in fixed charges.

From the total of the added items, subtract the following:

- interest capitalized;

- preference security dividend requirements of consolidated subsidiaries;
and

- minority interest in pre-tax income of subsidiaries that have not
incurred fixed charges.

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

- interest expensed and capitalized;

- amortized premiums, discounts and capitalized expenses related to
indebtedness;

- an estimate of the interest within rental expenses (equal to one-third of
rental expense); and

- preference security dividend requirements of consolidated subsidiaries.

DESCRIPTION OF DEBT SECURITIES

The debt securities will be issued under an Indenture dated as of March 15,
2000 (the "Indenture"), among the Operating Partnership, as issuer, the Company,
as guarantor, and First Union National Bank, as trustee (the "Trustee").

The terms of the debt securities will include those expressly set forth in the
Indenture and those made part of the Indenture by reference to the Trust
Indenture Act of 1939, as amended (the "Trust Indenture Act"). Capitalized terms
used in this Description of Debt Securities have the meanings specified in the
Indenture.

This Description of Debt Securities is intended to be a useful overview of
the material provisions of the debt securities and the Indenture. Since this
Description of Debt Securities is only a summary, you should refer to the
Indenture for a complete description of our obligations and your rights.

References to the "Issuer" mean only Enterprise Products Operating L.P. and
not its subsidiaries. References to the "Guarantor" mean only Enterprise
Products Partners L.P. and not its subsidiaries. References to "we" and "us"
mean the Issuer and the Guarantor collectively.

GENERAL

The Indenture does not limit the amount of debt securities that may be
issued thereunder. Debt securities may be issued under the Indenture from time
to time in separate series, each up to the aggregate amount authorized for such
series. The debt securities will be general obligations of the Issuer and the
Guarantor and may be subordinated to Senior Indebtedness of the Issuer and the
Guarantor. See "Description of Debt Securities -- Subordination."

A prospectus supplement and a supplemental indenture (or a resolution of
our Board of Directors and accompanying officers' certificate) relating to any
series of debt securities being offered will include specific terms relating to
the offering. These terms will include some or all of the following:

- the form and title of the debt securities;

- the total principal amount of the debt securities;

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

- the currency or currency unit in which the debt securities will be paid,
if not U.S. dollars;

- any right we may have to defer payments of interest by extending the
dates payments are due whether interest on those deferred amounts will be
payable as well;

- the dates on which the principal of the debt securities will be payable;

- the interest rate which the debt securities will bear and the interest
payment dates for the debt securities;

- any optional redemption provisions;

- any sinking fund or other provisions that would obligate us to repurchase
or otherwise redeem the debt securities;

- any changes to or additional Events of Default or covenants;

- whether the debt securities are to be issued as Registered Securities or
Bearer Securities or both; and any special provisions for Bearer
Securities;

- the subordination, if any, of the debt securities and any changes to the
subordination provisions of the Indenture; and

- any other terms of the debt securities.

The prospectus supplement will also describe any material United States
federal income tax consequences or other special considerations applicable to
the applicable series of debt securities, including those applicable to:

- Bearer Securities,

- debt securities with respect to which payments of principal, premium or
interest are determined with reference to an index or formula, including
changes in prices of particular securities, currencies or commodities,

- debt securities with respect to which principal, premium or interest is
payable in a foreign or composite currency,

- debt securities that are issued at a discount below their stated
principal amount, bearing no interest or interest at a rate that at the
time of issuance is below market rates, and

- variable rate debt securities that are exchangeable for fixed rate debt
securities.

At our option, we may make interest payments, by check mailed to the
registered holders thereof or, if so stated in the applicable prospectus
supplement, at the option of a holder by wire transfer to an account designated
by the holder. Except as otherwise provided in the applicable prospectus
supplement, no payment on a Bearer Security will be made by mail to an address
in the United States or by wire transfer to an account in the United States.

Unless otherwise provided in the applicable prospectus supplement,
Registered Securities may be transferred or exchanged at the office of the
Trustee at which its corporate trust business is principally administered in the
United States or at the office of the Trustee or the Trustee's agent in New York
City, subject to the limitations provided in the Indenture, without the payment
of any service charge, other than any applicable tax or governmental charge.
Bearer Securities will be transferable only by delivery. Provisions with respect
to the exchange of Bearer Securities will be described in the applicable
prospectus supplement.

Any funds we pay to a paying agent for the payment of amounts due on any
debt securities that remain unclaimed for two years will be returned to us, and
the holders of the debt securities must thereafter look only to us for payment
thereof.

GUARANTEE

The Guarantor will unconditionally guarantee to each holder and the Trustee
the full and prompt payment of principal of, premium, if any, and interest on
the debt securities, when and as the same become due and payable, whether at
maturity, upon redemption or repurchase, by declaration of acceleration or
otherwise.

CERTAIN COVENANTS

Except as set forth below or as may be provided in a prospectus supplement
and supplemental indenture, neither the Issuer nor the Guarantor will be
restricted by the Indenture from incurring any type of indebtedness or other
obligation, from paying dividends or making distributions on its partnership
interests or capital stock or purchasing or redeeming its partnership interests
or capital stock. The Indenture will not require the maintenance of any
financial ratios or specified levels of net worth or liquidity. In addition, the
Indenture will not contain any provisions that would require the Issuer to
repurchase or redeem or otherwise modify the terms of any of the debt securities
upon a change in control or other events involving the Issuer which may
adversely affect the creditworthiness of the debt securities.

Limitations on Liens. The Indenture will provide that the Guarantor will
not, nor will it permit any Subsidiary to, create, assume, incur or suffer to
exist any mortgage, lien, security interest, pledge, charge or other encumbrance
("liens") other than Permitted Liens (as defined below) upon any Principal
Property (as defined below) or upon any shares of capital stock of any
Subsidiary owning or leasing any Principal Property, whether owned or leased on
the date of the Indenture or thereafter acquired, to secure any indebtedness for
borrowed money ("debt") of the Guarantor or the Issuer or any other person
(other than the debt securities), without in any such case making effective
provision whereby all of the debt securities outstanding shall be secured
equally and ratably with, or prior to, such debt so long as such debt shall be
so secured. "Principal Property" means, whether owned or leased on the date of
the Indenture or thereafter acquired:

(1) any pipeline assets of the Guarantor or any Subsidiary, including
any related facilities employed in the transportation, distribution,
storage or marketing of refined petroleum products, natural gas liquids,
and petrochemicals, that are located in the United States of America or any
territory or political subdivision thereof; and

(2) any processing or manufacturing plant or terminal owned or leased
by the Guarantor or any Subsidiary that is located in the United States or
any territory or political subdivision thereof,

except, in the case of either of the foregoing clauses (1) or (2):

(a) any such assets consisting of inventories, furniture, office
fixtures and equipment (including data processing equipment), vehicles
and equipment used on, or useful with, vehicles; and

(b) any such assets, plant or terminal which, in the opinion of the
board of directors of the General Partner, is not material in relation
to the activities of the Issuer or of the Guarantor and its Subsidiaries
taken as a whole.

Notwithstanding the foregoing, under the Indenture, the Guarantor may, and
may permit any Subsidiary to, create, assume, incur, or suffer to exist any lien
upon any Principal Property to secure debt of the Guarantor or any other person
(other than the debt securities) other than a Permitted Lien without securing
the debt securities, provided that the aggregate principal amount of all debt
then outstanding secured by such lien and all similar liens, together with all
Attributable Indebtedness from Sale-Leaseback Transactions (excluding
Sale-Leaseback Transactions permitted by clauses (1) through (4), inclusive, of
the first paragraph of the restriction on sale-leasebacks covenant described
below) does not exceed 10% of Consolidated Net Tangible Assets.

"Permitted Liens" means:

(1) liens upon rights-of-way for pipeline purposes;

(2) any statutory or governmental lien or lien arising by operation of
law, or any mechanics', repairmen's, materialmen's, suppliers', carriers',
landlords', warehousemen's or similar lien incurred in the ordinary course
of business which is not yet due or which is being contested in good faith
by appropriate proceedings and any undetermined lien which is incidental to
construction, development, improvement or repair; or any right reserved to,
or vested in, any municipality or public authority by the terms of any
right, power, franchise, grant, license, permit or by any provision of law,
to purchase or recapture or to designate a purchaser of, any property;

(3) liens for taxes and assessments which are (a) for the then current
year, (b) not at the time delinquent, or (c) delinquent but the validity or
amount of which is being contested at the time by the Guarantor or any
Subsidiary in good faith by appropriate proceedings;

(4) liens of, or to secure performance of, leases, other than capital
leases; or any lien securing industrial development, pollution control or
similar revenue bonds;

(5) any lien upon property or assets acquired or sold by the Guarantor
or any Subsidiary resulting from the exercise of any rights arising out of
defaults on receivables;

(6) any lien in favor of the Guarantor or any Subsidiary; or any lien
upon any property or assets of the Guarantor or any Subsidiary in existence
on the date of the execution and delivery of the Indenture;

(7) any lien in favor of the United States of America or any state
thereof, or any department, agency or instrumentality or political
subdivision of the United States of America or any state thereof, to secure
partial, progress, advance, or other payments pursuant to any contract or
statute, or any debt incurred by the Issuer or any Subsidiary for the
purpose of financing all or any part of the purchase price of, or the cost
of constructing, developing, repairing or improving, the property or assets
subject to such lien;

(8) any lien incurred in the ordinary course of business in connection
with workmen's compensation, unemployment insurance, temporary disability,
social security, retiree health or similar laws or regulations or to secure
obligations imposed by statute or governmental regulations;

(9) liens in favor of any person to secure obligations under
provisions of any letters of credit, bank guarantees, bonds or surety
obligations required or requested by any governmental authority in
connection with any contract or statute; or any lien upon or deposits of
any assets to secure performance of bids, trade contracts, leases or
statutory obligations;

(10) any lien upon any property or assets created at the time of
acquisition of such property or assets by the Guarantor or any Subsidiary
or within one year after such time to secure all or a portion of the
purchase price for such property or assets or debt incurred to finance such
purchase price, whether such debt was incurred prior to, at the time of or
within one year after the date of such acquisition; or any lien upon any
property or assets to secure all or part of the cost of construction,
development, repair or improvements thereon or to secure debt incurred
prior to, at the time of, or within one year after completion of such
construction, development, repair or improvements or the commencement of
full operations thereof (whichever is later), to provide funds for any such
purpose;

(11) any lien upon any property or assets existing thereon at the time
of the acquisition thereof by the Guarantor or any Subsidiary and any lien
upon any property or assets of a person existing thereon at the time such
person becomes a Subsidiary by acquisition, merger or otherwise; provided
that, in each case, such lien only encumbers the property or assets so
acquired or owned by such person at the time such person becomes a
Subsidiary;

(12) liens imposed by law or order as a result of any proceeding
before any court or regulatory body that is being contested in good faith,
and liens which secure a judgment or other court-ordered award or
settlement as to which the Guarantor or the applicable Subsidiary has not
exhausted its appellate rights;

(13) any extension, renewal, refinancing, refunding or replacement (or
successive extensions, renewals, refinancing, refunding or replacements) of
liens, in whole or in part, referred to in clauses (1) through (12) above;
provided, however, that any such extension, renewal, refinancing, refunding
or replacement lien shall be limited to the property or assets covered by
the lien extended, renewed, refinanced, refunded or replaced and that the
obligations secured by any such extension, renewal, refinancing, refunding
or replacement lien shall be in an amount not greater than the amount of
the obligations secured by the lien extended, renewed, refinanced, refunded
or replaced and any expenses of the Guarantor and its Subsidiaries
(including any premium) incurred in connection with such extension,
renewal, refinancing, refunding or replacement; or

(14) any lien resulting from the deposit of moneys or evidence of
indebtedness in trust for the purpose of defeasing debt of the Guarantor or
any Subsidiary.

"Consolidated Net Tangible Assets" means, at any date of determination, the
total amount of assets after deducting therefrom:

(1) all current liabilities (excluding (A) any current liabilities
that by their terms are extendable or renewable at the option of the
obligor thereon to a time more than 12 months after the time as of which
the amount thereof is being computed, and (B) current maturities of
long-term debt); and

(2) the value (net of any applicable reserves) of all goodwill, trade
names, trademarks, patents and other like intangible assets, all as set
forth, or on a pro forma basis would be set forth, on the consolidated
balance sheet of the Guarantor and its consolidated subsidiaries for the
Guarantor's most recently completed fiscal quarter, prepared in accordance
with generally accepted accounting principles.

Restriction on Sale-Leasebacks. The Indenture will provide that the
Guarantor will not, and will not permit any Subsidiary to, engage in the sale or
transfer by the Guarantor or any Subsidiary of any Principal Property to a
person (other than the Issuer or a Subsidiary) and the taking back by the
Guarantor or any Subsidiary, as the case may be, of a lease of such Principal
Property (a "Sale-Leaseback Transaction"), unless:

(1) such Sale-Leaseback Transaction occurs within one year from the
date of completion of the acquisition of the Principal Property subject
thereto or the date of the completion of construction, development or
substantial repair or improvement, or commencement of full operations on
such Principal Property, whichever is later;

(2) the Sale-Leaseback Transaction involves a lease for a period,
including renewals, of not more than three years;

(3) the Guarantor or such Subsidiary would be entitled to incur debt
secured by a lien on the Principal Property subject thereto in a principal
amount equal to or exceeding the Attributable Indebtedness from such Sale-
Leaseback Transaction without equally and ratably securing the debt
securities; or

(4) the Guarantor or such Subsidiary, within a one-year period after
such Sale-Leaseback Transaction, applies or causes to be applied an amount
not less than the Attributable Indebtedness from such Sale-Leaseback
Transaction to (a) the prepayment, repayment, redemption, reduction or
retirement of any debt of the Guarantor or any Subsidiary that is not
subordinated to the debt securities, or (b) the expenditure or expenditures
for Principal Property used or to be used in the ordinary course of
business of the Guarantor or its Subsidiaries. "Attributable Indebtedness,"
when used with respect to any Sale-Leaseback Transaction, means, as at the
time of determination, the present value (discounted at the rate set forth
or implicit in the terms of the lease included in such transaction) of the
total obligations of the lessee for rental payments (other than amounts
required to be paid on account of property taxes, maintenance, repairs,
insurance, assessments, utilities, operating and labor costs and other
items that do not constitute payments for property rights) during the
remaining term of the lease included in such Sale-

Leaseback Transaction (including any period for which such lease has been
extended). In the case of any lease that is terminable by the lessee upon
the payment of a penalty or other termination payment, such amount shall be
the lesser of the amount determined assuming termination upon the first
date such lease may be terminated (in which case the amount shall also
include the amount of the penalty or termination payment, but no rent shall
be considered as required to be paid under such lease subsequent to the
first date upon which it may be so terminated) or the amount determined
assuming no such termination.

Notwithstanding the foregoing, under the Indenture the Guarantor may, and
may permit any Subsidiary to, effect any Sale-Leaseback Transaction that is not
excepted by clauses (1) through (4), inclusive, of the first paragraph under
"-- Restrictions On Sale-Leasebacks," provided that the Attributable
Indebtedness from such Sale-Leaseback Transaction, together with the aggregate
principal amount of outstanding debt (other than the debt securities) secured by
liens other than Permitted Liens upon Principal Property, do not exceed 10% of
Consolidated Net Tangible Assets.

In the Indenture, the term "Subsidiary" means:

(1) the Issuer; or

(2) any corporation, association or other business entity of which
more than 50% of the total voting power of the equity interests entitled
(without regard to the occurrence of any contingency) to vote in the
election of directors, managers or trustees thereof or any partnership of
which more than 50% of the partners' equity interests (considering all
partners' equity interests as a single class) is, in each case, at the time
owned or controlled, directly or indirectly, by the Guarantor, the Issuer
or one or more of the other Subsidiaries of the Guarantor or the Issuer or
combination thereof.

Merger, Consolidation or Sale of Assets. The Indenture will provide that
each of the Guarantor and the Issuer may, without the consent of the holders of
any of the debt securities, consolidate with or sell, lease, convey all or
substantially all of its assets to, or merge with or into, any partnership,
limited liability company or corporation if:

(1) the partnership, limited liability company or corporation formed
by or resulting from any such consolidation or merger or to which such
assets shall have been transferred (the "successor") is either the
Guarantor or the Issuer, as applicable, or assumes all the Guarantor's or
the Issuer's, as the case may be, obligations and liabilities under the
Indenture and the debt securities (in the case of the Issuer) and the
Guarantee (in the case of the Guarantor).

(2) the successor is organized under the laws of the United States,
any state or the District of Columbia; and

(3) immediately after giving effect to the transaction no Default or
Event of Default shall have occurred and be continuing.

The successor will be substituted for the Guarantor or the Issuer, as the
case may be, in the Indenture with the same effect as if it had been an original
party to the Indenture. Thereafter, the successor may exercise the rights and
powers of the Guarantor or the Issuer, as the case may be, under the Indenture,
in its name or in its own name. If the Guarantor or the Issuer sells or
transfers all or substantially all of its assets, it will be released from all
liabilities and obligations under the Indenture and under the debt securities
(in the case of the Issuer) and the Guarantee (in the case of the Guarantor)
except that no such release will occur in the case of a lease of all or
substantially all of its assets.

EVENTS OF DEFAULT

Each of the following will be an Event of Default under the Indenture with
respect to a series of debt securities:

(1) default in any payment of interest on any debt securities of that
series when due, continued for 30 days;

(2) default in the payment of principal of or premium, if any, on any
debt securities of that series when due at its stated maturity, upon
optional redemption, upon declaration or otherwise;

(3) failure by the Guarantor or the Issuer to comply for 60 days after
notice with its other agreements contained in the Indenture;

(4) certain events of bankruptcy, insolvency or reorganization of the
Issuer or the Guarantor (the "bankruptcy provisions"); or

(5) the Guarantee ceases to be in full force and effect or is declared
null and void in a judicial proceeding or the Guarantor denies or
disaffirms its obligations under the Indenture or the Guarantee.

However, a default under clause (3) of this paragraph will not constitute an
Event of Default until the Trustee or the holders of 25% in principal amount of
the outstanding debt securities of that series notify the Issuer and the
Guarantor of the default such default is not cured within the time specified in
clause (3) of this paragraph after receipt of such notice.

If an Event of Default (other than an Event of Default described in clause
(4) above) occurs and is continuing, the Trustee by notice to the Issuer, or the
holders of at least 25% in principal amount of the outstanding debt securities
of that series by notice to the Issuer and the Trustee, may, and the Trustee at
the request of such holders shall, declare the principal of, premium, if any,
and accrued and unpaid interest, if any, on all the debt securities of that
series to be due and payable. Upon such a declaration, such principal, premium
and accrued and unpaid interest will be due and payable immediately. If an Event
of Default described in clause (4) above occurs and is continuing, the principal
of, premium, if any, and accrued and unpaid interest on all the debt securities
will become and be immediately due and payable without any declaration or other
act on the part of the Trustee or any holders. The holders of a majority in
principal amount of the outstanding debt securities of a series may waive all
past defaults (except with respect to nonpayment of principal, premium or
interest) and rescind any such acceleration with respect to the debt securities
of that series and its consequences if rescission would not conflict with any
judgment or decree of a court of competent jurisdiction and all existing Events
of Default, other than the nonpayment of the principal of, premium, if any, and
interest on the debt securities of that series that have become due solely by
such declaration of acceleration, have been cured or waived.

Subject to the provisions of the Indenture relating to the duties of the
Trustee, if an Event of Default occurs and is continuing, the Trustee will be
under no obligation to exercise any of the rights or powers under the Indenture
at the request or direction of any of the holders unless such holders have
offered to the Trustee reasonable indemnity or security against any loss,
liability or expense. Except to enforce the right to receive payment of
principal, premium, if any, or interest when due, no holder may pursue any
remedy with respect to the Indenture or the debt securities unless:

(1) such holder has previously given the Trustee notice that an Event
of Default is continuing;

(2) holders of at least 25% in principal amount of the outstanding
debt securities of that series have requested the Trustee to pursue the
remedy;

(3) such holders have offered the Trustee reasonable security or
indemnity against any loss, liability or expense;

(4) the Trustee has not complied with such request within 60 days
after the receipt of the request and the offer of security or indemnity;
and

(5) the holders of a majority in principal amount of the outstanding
debt securities of that series have not given the Trustee a direction that,
in the opinion of the Trustee, is inconsistent with such request within
such 60-day period.

Subject to certain restrictions, the holders of a majority in principal
amount of the outstanding debt securities of a series are given the right to
direct the time, method and place of conducting any proceeding for any remedy
available to the Trustee or of exercising any trust or power conferred on the
Trustee with respect to that series of debt securities. The Trustee, however,
may refuse to follow any direction that conflicts with law or the Indenture or
that the Trustee determines is unduly prejudicial to the rights of any other
holder or that would involve the Trustee in personal liability. Prior to taking
any action under the Indenture, the Trustee will be entitled to indemnification
satisfactory to it in its sole discretion against all losses and expenses caused
by taking or not taking such action.

The Indenture provides that if a Default occurs and is continuing and is
known to the Trustee, the Trustee must mail to each holder notice of the Default
within 90 days after it occurs. Except in the case of a Default in the payment
of principal of, premium, if any, or interest on any debt securities, the
Trustee may withhold notice if and so long as a committee of trust officers of
the Trustee in good faith determines that withholding notice is in the interests
of the holders. In addition, the Issuer is required to deliver to the Trustee,
within 120 days after the end of each fiscal year, a certificate indicating
whether the signers thereof know of any Default that occurred during the
previous year. The Issuer also is required to deliver to the Trustee, within 30
days after the occurrence thereof, written notice of any events which would
constitute certain Defaults, their status and what action the Issuer is taking
or proposes to take in respect thereof.

AMENDMENTS AND WAIVERS

Modifications and amendments of the Indenture may be made by the Issuer,
the Guarantor and the Trustee with the consent of the holders of a majority in
principal amount of all debt securities then outstanding under the Indenture

(including consents obtained in connection with a tender offer or exchange offer
for the debt securities). However, without the consent of each holder of
outstanding debt securities of each series affected thereby, no amendment may,
among other things:

(1) reduce the amount of debt securities whose holders must consent to
an amendment;

(2) reduce the stated rate of or extend the stated time for payment of
interest on any debt securities;

(3) reduce the principal of or extend the stated maturity of any debt
securities;

(4) reduce the premium payable upon the redemption of any debt
securities or change the time at which any debt securities may be redeemed
as described above under "Optional Redemption" or any similar provision;

(5) make any debt securities payable in money other than that stated
in the debt securities;

(6) impair the right of any holder to receive payment of, premium, if
any, principal of and interest on such holder's debt securities on or after
the due dates therefor or to institute suit for the enforcement of any
payment on or with respect to such holder's debt securities;

(7) make any change in the amendment provisions which require each
holder's consent or in the waiver provisions; or

(8) release the Guarantor or modify the Guarantee in any manner
adverse to the holders.

The holders of a majority in aggregate principal amount of the outstanding
debt securities of each series affected thereby, on behalf of all such holders,
may waive compliance by the Issuer and the Guarantor with certain restrictive
provisions of the Indenture. Subject to certain rights of the Trustee as
provided in the Indenture, the holders of a majority in aggregate principal
amount of the debt securities of each series affected thereby, on behalf of all
such holders, may waive any past default under the Indenture (including any such
waiver obtained in connection with a tender offer or exchange offer for the debt
securities), except a default in the payment of principal, premium or interest
or a default in respect of a provision that under the Indenture that cannot be
modified or amended without the consent of all holders of the series of debt
securities that is affected.

Without the consent of any holder, the Issuer, the Guarantor and the
Trustee may amend the Indenture to:

(1) cure any ambiguity, omission, defect or inconsistency;

(2) provide for the assumption by a successor corporation,
partnership, trust or limited liability company of the obligations of the
Guarantor or the Issuer under the Indenture;

(3) provide for uncertificated debt securities in addition to or in
place of certificated debt securities (provided that the uncertificated
debt securities are issued in registered form for purposes of Section
163(f) of the Code, or in a manner such that the uncertificated debt
securities are described in Section 163(f)(2)(B) of the Code);

(4) add guarantees with respect to the debt securities;

(5) secure the debt securities;

(6) add to the covenants of the Guarantor or the Issuer for the
benefit of the holders or surrender any right or power conferred upon the
Guarantor or the Issuer;

(7) make any change that does not adversely affect the rights of any
holder; or

(8) comply with any requirement of the Commission in connection with
the qualification of the Indenture under the Trust Indenture Act.

The consent of the holders is not necessary under the Indenture to approve
the particular form of any proposed amendment. It is sufficient if such consent
approves the substance of the proposed amendment. After an amendment under the
Indenture becomes effective, the Issuer is required to mail to the holders a
notice briefly describing such amendment. However, the failure to give such
notice to all the holders, or any defect therein, will not impair or affect the
validity of the amendment.

DEFEASANCE

The Issuer at any time may terminate all its obligations under a series of
debt securities and the Indenture ("legal defeasance"), except for certain
obligations, including those respecting the defeasance trust and obligations to
register the transfer or exchange of the debt securities, to replace mutilated,
destroyed, lost or stolen debt securities and to maintain a

registrar and paying agent in respect of the debt securities. If the Issuer
exercises its legal defeasance option, the Guarantee will terminate with respect
to that series.

The Issuer at any time may terminate its obligations under covenants
described under "Certain Covenants" (other than "Merger and Consolidation"), the
bankruptcy provisions with respect to the Guarantor and the Guarantee provision
described under "Events of Default" above with respect to a series of debt
securities ("covenant defeasance").

The Issuer may exercise its legal defeasance option notwithstanding its
prior exercise of its covenant defeasance option. If the Issuer exercises its
legal defeasance option, payment of the affected series of debt securities may
not be accelerated because of an Event of Default with respect thereto. If the
Issuer exercises its covenant defeasance option, payment of the affected series
of debt securities may not be accelerated because of an Event of Default
specified in clause (3), (4), (with respect only to the Guarantor) or (5) under
"Events of Default" above.

In order to exercise either defeasance option, the Issuer must irrevocably
deposit in trust (the "defeasance trust") with the Trustee money or U.S.
Government Obligations for the payment of principal, premium, if any, and
interest on the series of debt securities to redemption or maturity, as the case
may be, and must comply with certain other conditions, including delivery to the
Trustee of an opinion of counsel (subject to customary exceptions and
exclusions) to the effect that holders of the series of debt securities will not
recognize income, gain or loss for Federal income tax purposes as a result of
such deposit and defeasance and will be subject to Federal income tax on the
same amount and in the same manner and at the same times as would have been the
case if such deposit and defeasance had not occurred. In the case of legal
defeasance only, such opinion of counsel must be based on a ruling of the
Internal Revenue Service or other change in applicable Federal income tax law.

NO PERSONAL LIABILITY OF GENERAL PARTNER

The General Partner and its directors, officers, employees, incorporators
and stockholders, as such, shall have no liability for any obligations of the
Guarantor or the Issuer under the debt securities, the Indenture or the
Guarantee or for any claim based on, in respect of, or by reason of, such
obligations or their creation. Each holder by accepting a debt security waives
and releases all such liability. The waiver and release are part of the
consideration for issuance of the debt securities. Such waiver may not be
effective to waive liabilities under the federal securities laws and it is the
view of the Commission that such a waiver is against public policy.

SUBORDINATION

Debt securities of a series may be subordinated to Senior Indebtedness (as
defined below) to the extent set forth in the Prospectus Supplement relating
thereto. Subordinated debt securities will be subordinate in right of payment,
to the extent and in the manner set forth in the Indenture and the Prospectus
Supplement relating thereto, to the prior payment of all indebtedness of the
Issuer and the Guarantor that is designated as "Senior Indebtedness" with
respect to the series. "Senior Indebtedness" is defined generally to include all
notes or other evidences of indebtedness for money borrowed by the Issuer,
including guarantees, not expressed to be subordinate or junior in right of
payment to any other indebtedness of the Issuer.

Upon any payment or distribution of assets of the Issuer to creditors or
upon a total or partial liquidation or dissolution of the Issuer or in a
bankruptcy, receivership or similar proceeding relating to the Issuer or its
property, holders of Senior Indebtedness shall be entitled to receive payment in
full in cash of the Senior Indebtedness before holders of subordinated debt
securities shall be entitled to receive any payment of principal, premium or
interest with respect to the subordinated debt securities, and until the Senior
Indebtedness is paid in full, any distribution to which holders of subordinated
debt securities would otherwise be entitled shall be made to the holders of
Senior Indebtedness (except that the holders may receive shares of stock and any
debt securities that are subordinated to Senior Indebtedness to at least the
same extent as the subordinated debt securities).

We may not make any payments of principal, premium or interest with respect
to subordinated debt securities, make any deposit for the purpose of defeasance
of the subordinated debt securities, or repurchase, redeem or otherwise retire
(except, in the case of subordinated debt securities that provide for a
mandatory sinking fund, by our delivery of subordinated debt securities to the
Trustee in satisfaction of our sinking fund obligation) any subordinated debt
securities if (a) any principal, premium or interest with respect to Senior
Indebtedness is not paid within any applicable grace period (including at
maturity), or (b) any other default on Senior Indebtedness occurs and the
maturity of the Senior

Indebtedness is accelerated in accordance with its terms, unless, in either
case, the default has been cured or waived and the acceleration has been
rescinded, the Senior Indebtedness has been paid in full in cash, or the Issuer
and the Trustee receive written notice approving the payment from the
representatives of each issue of "Designated Senior Indebtedness" (which will
include the Bank Indebtedness and any other specified issue of Senior
Indebtedness of at least $100 million). During the continuance of any default
(other than a default described in clause (a) or (b) above) with respect to any
Senior Indebtedness pursuant to which the maturity thereof may be accelerated
immediately without further notice (except such notice as may be required to
effect the acceleration) or the expiration of any applicable grace periods, the
Issuer may not pay the subordinated debt securities for a period (the "Payment
Blockage Period") commencing on the receipt by the Issuer and the Trustee of
written notice of the default from the representative of any Designated Senior
Indebtedness specifying an election to effect a Payment Blockage Period (a
"Blockage Notice"). The Payment Blockage Period may be terminated before its
expiration by written notice to the Trustee and us from the person who have the
Blockage Notice, by repayment in full in cash of the Senior Indebtedness with
respect to which the Blockage Notice was given, or because the default giving
rise to the Payment Blockage Period is no longer continuing. Unless the holders
of the Senior Indebtedness shall have accelerated the maturity thereof, the
Issuer may resume payments on the subordinated debt securities after the
expiration of the Payment Blockage Period. Not more than one Blockage Notice may
be given in any period of 360 consecutive days unless the first Blockage Notice
within the 360-day period is given by or on behalf of holders of Designated
Senior Indebtedness other than the Bank Indebtedness, in which case, the
representative of the Bank Indebtedness may give another Blockage Notice within
the period. In no event, however, may the total number of days during which any
Payment Blockage Period or Periods is in effect exceed 179 days in the aggregate
during any period of 360 consecutive days. After all Senior Indebtedness is paid
in full and until the subordinated debt securities are paid in full, holders of
the subordinated debt securities shall be subrogated to the rights of holders of
Senior Indebtedness to receive distributions applicable to Senior Indebtedness.

By reason of the subordination, in the event of insolvency, our creditors
who are holders of Senior Indebtedness, as well as certain of our general
creditors, may recover more, ratably, than the holders of the subordinated debt
securities.

BOOK ENTRY, DELIVERY AND FORM

The debt securities of a series may be issued in whole or in part in the
form of one or more global certificates that will be deposited with a depositary
identified in a prospectus supplement.

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 security that will
be deposited with DTC. This means that we will not issue certificates to each
holder. One global 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 certificated securities, a global security may not be transferred;
except that DTC, its nominees and their successors may transfer a global
security as a whole to one another.

Beneficial interests in global securities will be shown on, and transfers
of global 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"
with 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
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 certain 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 Commission.

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 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 securities to
owners of beneficial interests in the global 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 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 securities, and
voting by participants, will be governed 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 security will be exchangeable for
certificated 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 security and notify the Trustee of our decision.

LIMITATIONS ON ISSUANCE OF BEARER SECURITIES

The debt securities of a series may be issued as Registered Securities
(which will be registered as to principal and interest in the register
maintained by the registrar for the debt securities) or Bearer Securities (which
will be transferable only by delivery). If the debt securities are issuable as
Bearer Securities, certain special limitations and conditions will apply.

In compliance with United States federal income tax laws and regulations,
we and any underwriter, agent or dealer participating in an offering of Bearer
Securities will agree that, in connection with the original issuance of the
Bearer Securities and during the period ending 40 days after the issue date,
they will not offer, sell or deliver any such Bearer Securities, directly or
indirectly, to a United States Person (as defined below) or to any person within
the United States, except to the extent permitted under United States Treasury
regulations.

Bearer Securities will bear a legend to the following effect: "Any United
States person who holds this obligation will be subject to limitations under the
United States federal income tax laws, including the limitations provided in
Sections 165(j) and 1287(a) of the Internal Revenue Code." The sections referred
to in the legend provide that, with certain exceptions, a United States taxpayer
who holds Bearer Securities will not be allowed to deduct any loss with respect
to, and will not be eligible for capital gain treatment with respect to any gain
realized on the sale, exchange, redemption or other disposition of, the Bearer
Securities.

For this purpose, "United States" includes the United States of America and
its possessions, and "United States person" means a citizen or resident of the
United States, a corporation, partnership or other entity created or organized
in or under the laws of the United States, or an estate or trust the income of
which is subject to United States federal income taxation regardless of its
source.

Pending the availability of a definitive global security or individual
Bearer Securities, as the case may be, debt securities that are issuable as
Bearer Securities may initially be represented by a single temporary global
security, without interest coupons, to be deposited with a common depositary in
London for Morgan Guaranty Trust Company of New York, Brussels Office, as
operator of the Euroclear System ("Euroclear"), or Centrale de Livraison de
Valeurs Mobilieres S.A. ("CEDEL") for credit to the accounts designated by or on
behalf of the purchasers thereof. Following the availability of a definitive
global security in bearer form, without coupons attached, or individual Bearer
Securities and subject to any further limitations described in the applicable
Prospectus Supplement, the temporary global security will be exchangeable for
interests in the definitive global security or for the individual Bearer
Securities, respectively, only upon receipt of a "Certificate of Non-U.S.
Beneficial Ownership," which is a certificate to the effect that a beneficial
interest in a temporary global security is owned by a person that is not a
United States Person or is owned by or through a financial institution in
compliance with applicable United States Treasury regulations. No Bearer
Security

will be delivered in or to the United States. If so specified in the applicable
Prospectus Supplement, interest on a temporary global security will be paid to
each of Euroclear and CEDEL with respect to that portion of the temporary global
security held for its account, but only upon receipt as of the relevant interest
payment date of a Certificate of Non-U.S. Beneficial Ownership.

THE TRUSTEE

We may appoint a separate Trustee for any series of debt securities. As
used herein in the description of a series of debt securities, the term
"Trustee" refers to the Trustee appointed with respect to the series of debt
securities.

We may maintain banking and other commercial relationships with the Trustee
and its affiliates in the ordinary course of business, and the Trustee may own
debt securities.

GOVERNING LAW

The Indenture provides that it and the debt securities will be governed by,
and construed in accordance with, the laws of the State of New York.

DESCRIPTION OF COMMON UNITS

THE UNITS

As of December 31, 2000, we have outstanding 46,524,515 common units,
21,409,870 subordinated units and 16,500,000 convertible special units. The
common units, the subordinated units and the convertible special units represent
limited partner interests in the Company, which entitle the holders thereof to
participate in Company distributions and exercise the rights or privileges
available to limited partners under our Partnership Agreement. A summary of the
important provisions of our Partnership Agreement and a copy of our Partnership
Agreement are included in our reports filed with the Commission.

The outstanding common units are listed on the New York Stock Exchange
under the symbol "EPD." Any additional common units we issue will also be listed
on the NYSE.

CASH DISTRIBUTION POLICY

GENERAL

We distribute to our partners, on a quarterly basis, all of our available
cash. Available cash is defined in the Partnership Agreement and generally
means, with respect to any calendar quarter, all cash on hand at the end of such
quarter less the amount of cash reserves that is necessary or appropriate in the
reasonable discretion of the General Partner to (1) provide for the proper
conduct of the Company's business, (2) comply with applicable law or any Company
debt instrument or other agreement (including reserves for future capital
expenditures and for our future credit needs) or (3) provide funds for
distributions to unitholders and the General Partner in respect of any one or
more of the next four quarters.

Cash distributions are characterized as distributions from either operating
surplus or capital surplus. This distinction affects the amounts distributed to
unitholders relative to the General Partner, and under certain circumstances it
determines whether holders of subordinated units receive any distributions. See
"-- Quarterly Distributions of Available Cash."

Operating surplus is defined in the Partnership Agreement and refers
generally to (a) the sum of (1) the cash balance of the Company on July 31,
1998, the closing date of our initial public offering of common units (excluding
$46.5 million spent from the proceeds of that offering on new projects), (2) all
cash receipts of the Company from its operations since July 31, 1998 (excluding
certain cash receipts that the General Partner designates as operating surplus),
less (b) the sum of (1) all Company operating expenses, (2) debt service
payments (including reserves therefor but not including payments required in
connection with the sale of assets or any refinancing with the proceeds of new
indebtedness or an equity offering), (3) maintenance capital expenditures and
(4) reserves established for future Company operations, in each case since July
31, 1998. Capital surplus is generally generated only by borrowings (other than
borrowings for working capital purposes), sales of debt and equity securities
and sales or other dispositions of assets for cash (other than inventory,
accounts receivable and other assets disposed of in the ordinary course of
business).

To avoid the difficulty of trying to determine whether available cash
distributed by the Company is from operating surplus or from capital surplus,
all available cash distributed by the Company from any source will be treated as
distributed from operating surplus until the sum of all available cash
distributed since July 31, 1998 equals the operating

surplus as of the end of the quarter prior to such distribution. Any available
cash in excess of such amount (irrespective of its source) will be deemed to be
from capital surplus and distributed accordingly.

If available cash from capital surplus is distributed in respect of each
common unit in an aggregate amount per common unit equal to the $22.00 initial
public offering price of the common units, plus any common unit arrearages, the
distinction between operating surplus and capital surplus will cease, and all
distributions of available cash will be treated as if they were from operating
surplus. We do not anticipate that there will be significant distributions from
capital surplus.

The subordinated units are a separate class of interests in the Company,
and the rights of holders of such interests to participate in distributions to
partners differ from the rights of the holders of common units. For any given
quarter, any available cash will be distributed to the General Partner and to
the holders of common units, and may also be distributed to the holders of
subordinated units depending upon the amount of available cash for the quarter,
the amount of common unit arrearages, if any, and other factors discussed below.

A total of 14,500,000 convertible special units were issued as part of the
purchase price of Tejas Natural Gas Liquids LLC. These units do not accrue
distributions and are not entitled to cash distributions until their conversion
into an equal number of common units between August 1, 2000 and August 1, 2002.
On August 1, 2000, 1,000,000 of the convertible special units were converted
into an equal number of common units. As an additional part of the purchase
price of Tejas Natural Gas Liquids LLC, we agreed to issue up to 6,000,000 more
convertible special units to the seller if the volumes of natural gas that we
process for Shell Oil Company and its affiliates reach certain agreed upon
levels in 2000 and 2001. These additional contingent units would convert into an
equal number of common units between August 1, 2002 and August 1, 2003. On
August 1, 2000, 3,000,000 of these contingent convertible special units were
issued to the seller under our foregoing agreement.

The incentive distributions represent the right of the General Partner to
receive an increasing percentage of quarterly distributions of available cash
from operating surplus after the target distribution levels have been achieved.
The target distribution levels are based on the amounts of available cash from
operating surplus distributed in excess of the payments made with respect to the
minimum quarterly distribution of $0.45 per unit and common unit arrearages, if
any, and the related 2% distribution to the General Partner.

Subject to certain limitations contained in the Partnership Agreement, the
Company has the authority to issue additional common units or other equity
securities of the Company for such consideration and on such terms and
conditions as are established by the General Partner in its sole discretion and
without the approval of the unitholders. It is possible that the Company will
fund acquisitions of assets or other capital projects through the issuance of
additional common units or other equity securities of the Company. Holders of
any additional common units issued by the Company will be entitled to share
equally with the then-existing holders of common units in distributions of
available cash by the Company. In addition, the issuance of additional common
units may dilute the value of the interests of the then-existing holders of
common units in the net assets of the Company. The General Partner will be
required to make an additional capital contribution to the Company or the
Operating Partnership in connection with the issuance of additional common
units.

The discussion in the sections below indicates the percentages of cash
distributions required to be made to the General Partner and the holders of
common units and the circumstances under which holders of subordinated units are
entitled to receive cash distributions and the amounts thereof.

QUARTERLY DISTRIBUTIONS OF AVAILABLE CASH

The Company will make distributions to its partners with respect to each
calendar quarter of the Company prior to its liquidation in an amount equal to
100% of its available cash for such quarter. The Company expects to make
distributions of all available cash within approximately 45 days after the end
of each quarter to holders of record on the applicable record date. The minimum
quarterly distribution and the target distribution levels are also subject to
certain other adjustments as described below under "-- Distributions from
Capital Surplus" and "-- Adjustment of Minimum Quarterly Distribution and Target
Distribution Levels."

With respect to each quarter during the Subordination Period, to the extent
there is sufficient available cash, the holders of common units will have the
right to receive the minimum quarterly distribution of $0.45 per unit, plus any
common unit arrearages, prior to any distribution of available cash to the
holders of subordinated units. Upon expiration of the Subordination Period, all
subordinated units will be converted on a one-for-one basis into common units
and will participate pro rata with all other common units in future
distributions of available cash. Under certain circumstances, up to 50% of the
subordinated units may convert into common units prior to the expiration of the
Subordination Period.

Common units will not accrue arrearages with respect to distributions for any
quarter after the Subordination Period, and subordinated units will not accrue
any arrearages with respect to distributions for any quarter.

DISTRIBUTIONS FROM OPERATING SURPLUS DURING SUBORDINATED PERIOD

The Subordination Period will generally extend until the first day of any
quarter beginning after June 30, 2003 in respect of which (1) distributions of
available cash from operating surplus on the common units and the subordinated
units with respect to each of the three consecutive, non-overlapping,
four-quarter periods immediately preceding such date equaled or exceeded the sum
of the minimum quarterly distribution on all of the outstanding common units and
subordinated units during such periods, (2) the adjusted operating surplus
generated during each of the three consecutive, non-overlapping, four-quarter
periods immediately preceding such date equaled or exceeded the sum of the
minimum quarterly distribution on all of the common units and subordinated units
that were outstanding during such period on a fully diluted basis and the
related distribution on the general partner interests in the Company and the
Operating Partnership and (3) there are no outstanding common unit arrearages.

Prior to the end of the Subordination Period, a portion of the subordinated
units will convert into common units on a one-for-one basis on the first day
after the record date established for the distribution in respect of any quarter
ending on or after (a) June 30, 2001 with respect to 5,352,468 subordinated
units, and (b) June 30, 2002 with respect to 5,352,468 subordinated units in
respect of which (1) distributions of available cash from operating surplus on
the common units and the subordinated units with respect to each of the three
consecutive, non-overlapping, four-quarter periods immediately preceding such
date equaled or exceeded the sum of the minimum quarterly distribution on all of
the outstanding common units and subordinated units during such periods, (2) the
adjusted operating surplus generated during each of the three consecutive,
non-overlapping, four-quarter periods immediately preceding such date equaled or
exceeded the sum of $0.45 per unit on all of the common units and subordinated
units that were outstanding during such period on a fully diluted basis and the
related distribution on the general partner interests in the Company and the
Operating Partnership and (3) there are no outstanding common unit arrearages;
provided, however, that the early conversion of the second 5,352,468
subordinated units may not occur until at least one year following the early
conversion of the first 5,352,468 subordinated units.

Upon expiration of the Subordination Period, all remaining subordinated
units will convert into common units on a one-for-one basis and will thereafter
participate, pro rata, with the other common units in distribution on available
cash. In addition, if the General Partner is removed as the general partner of
the Company under circumstances where cause does not exist and units held by the
General Partner and its affiliates are not voted in favor of such removal, (1)
the Subordination Period will end and all outstanding subordinated units will
immediately convert into common units on a one-for-one basis, (2) any existing
common unit arrearages will be extinguished and (3) the General Partner will
have the right to convert its general partner interest into common units or to
receive cash in exchange for such interests.

Adjusted operating surplus for any period generally means operating surplus
generated during such period, less (a) any net increase in working capital
borrowings during such period and (b) any net reduction in cash reserves for
operating expenditures during such period not relating to an operating
expenditure made during such period, and plus (x) any net decrease in working
capital borrowings during such period and (y) any net increase in cash reserves
for operating expenditures during such period required by any debt instrument
for the repayment of principal, interest or premium. Operating surplus generated
during a period is equal to the difference between (1) the operating surplus
determined at the end of such period and (2) the operating surplus determined at
the beginning of such period.

Distributions by the Company of available cash from operating surplus with
respect to any quarter during the Subordination Period will be made in the
following manner:

first, 98% to the common unitholders, pro rata, and 2% to the General
Partner, until there has been distributed in respect of each outstanding
common unit an amount equal to $0.45 per unit for such quarter.

second, 98% to the common unitholders, pro rata, and 2% to the General
Partner, until there has been distributed in respect of each outstanding
common unit an amount equal to any common unit arrearages accrued and
unpaid with respect to any prior quarters during the Subordination Period;

third, 98% to the subordinated unitholders, pro rata and 2% to the
General Partner, until there has been distributed in respect of each
outstanding common unit an amount equal to $0.45 per unit; and

thereafter, in the manner described in "-- Incentive
Distributions -- Hypothetical Annualized Yield" below.

The above references to the 2% of available cash from operating surplus
distributed to the General Partner are references to the amount of the
percentage interest in distributions from the Company and the Operating
Partnership of the General Partner (exclusive of its or any of its affiliates'
interests as holders of common units or subordinated units).

The General Partner owns a 1% general partner interests in the Company and a
1.0101% general partner interests in the Operating Partnership. With respect to
any common unit, the term "common unit arrearages" refers to the amount by which
the minimum quarterly distribution of $0.45 per unit in any quarter during the
Subordination Period exceeds the distribution of available cash from operating
surplus actually made for such quarter on a common unit issued in our initial
public offering, cumulative for such quarter and all prior quarters during the
Subordination Period. Common unit arrearages will not accrue interest.

DISTRIBUTIONS FROM OPERATING SURPLUS AFTER SUBORDINATION PERIOD

Distributions by the Company of available cash from the operating surplus
with respect to any quarter after the Subordination Period will be made in the
following manner:

first, 98% to all unitholders, pro rata and 2% to the General Partner,
until there has been distributed in respect of each unit an amount equal to
$0.45; and

thereafter, in the manner described in "-- Incentive Distributions"
below.

INCENTIVE DISTRIBUTIONS

For any quarter for which available cash from operating surplus is
distributed to the Common and subordinated unitholders in an amount equal to
$0.45 per unit on all units and to the common unitholders in an amount equal to
any unpaid common unit arrearages, then any additional available cash from
operating surplus in respect of such quarter will be distributed among the
unitholders and the General Partner in the following manner:

first, 98% to all unitholders, pro rata, and 2% to the General
Partner, until the unitholders have received (in addition to any
distributions to common unitholders to eliminate common unit arrearages) a
total of $0.506 for such quarter in respect of each outstanding unit (the
"First Target Distribution");

second, 85% to all unitholders, pro rata, and 15% to the General
Partner, until the unitholders have received (in addition to any
distribution to common unitholders to eliminate common unit arrearages) a
total of $0.617 for such quarter in respect of each outstanding unit (the
"Second Target Distribution");

third, 75% to all unitholders, pro rata, and 25% to the General
Partner, until the unitholders have received (in addition to any
distributions to common unitholders to eliminate common unit arrearages) a
total of $0.784 for such quarter in respect of each outstanding unit (the
"Third Target Distribution"); and

thereafter, 50% to all unitholders, pro rata, and 50% to the General
Partner.

The distributions to the General Partner set forth above that are in excess
of its aggregate 2% general partner interest represent the Incentive
Distributions.

DISTRIBUTIONS FROM CAPITAL SURPLUS

Distributions by the Company of available cash from capital surplus will be
made in the following manner:

first, 98% to all unitholders, pro rata, and 2% to the General
Partner, until the Company has distributed, in respect of each outstanding
common unit issued in our initial public offering, available cash from
capital surplus in an aggregate amount per common unit equal to the initial
unit price of $22.00;

second, 98% to the holders of common units, pro rata, and 2% to the
General Partner, until the Company has distributed, in respect of each
outstanding common unit, available cash from capital surplus in an
aggregate amount equal to any unpaid common unit arrearages with respect to
such common unit; and

thereafter, all distributions of available cash from capital surplus
will be distributed as if they were from operating surplus.

As a distribution of available cash from capital surplus is made, it is
treated as if it were a repayment of the initial unit price of $22.00 per unit.
To reflect such repayment, the minimum quarterly distribution of $0.45 per unit
and the target distribution levels will be adjusted downward by multiplying each
such amount by a fraction, the numerator of which is the unrecovered capital of
the common units immediately after giving effect to such repayment and the
denominator of which is the unrecovered capital of the common units immediately
prior to such repayment. This adjustment to the minimum quarterly distribution
may make it more likely that subordinated units will be converted into common
units (whether pursuant to the termination of the Subordination Period or to the
provisions permitting early conversion of some subordinated units) and may
accelerate the dates at which such conversions occur.

When "payback" of the initial unit price has occurred, i.e., when the
unrecovered capital of the common units is zero (and any accrued common unit
arrearages have been paid), the minimum quarterly distribution and each of the

target distribution levels will have been reduced to zero for subsequent
quarters. Thereafter, all distributions of available cash from all sources will
be treated as if they were from operating surplus. Because the minimum quarterly
distribution and the target distribution levels will have been reduced to zero,
the General Partner will be entitled thereafter to receive 50% of all
distributions of available cash in its capacity as General Partner (in addition
to any distributions to which it or its affiliates may be entitled as holders of
units).

Distributions of available cash from capital surplus will not reduce the
minimum quarterly distribution or target distribution levels for the quarter
with respect to which they are distributed.

ADJUSTMENT OF MINIMUM QUARTERLY DISTRIBUTION AND TARGET DISTRIBUTION LEVELS

In addition to reductions of the minimum quarterly distribution and target
distribution levels made upon a distribution of available cash from capital
surplus, the minimum quarterly distribution, the target distribution levels, the
unrecovered capital, the number of additional common units issuable during the
Subordination Period without a unitholder vote, the number of common units
issuable upon conversion of the subordinated units and other amounts calculated
on a per unit basis will be proportionately adjusted upward or downward, as
appropriate, in the event of any combination or subdivision of common units
(whether effected by a distribution payable in common units or otherwise), but
not by reason of the issuance of additional common units for cash or property.
For example, in the event of a two-for-one split of the common units (assuming
no prior adjustments), the minimum quarterly distribution, each of the target
distribution levels and the unrecovered capital of the common units would each
be reduced to 50% of its initial level.

The minimum quarterly distribution and the target distribution levels may
also be adjusted if legislation is enacted or if existing law is modified or
interpreted by the relevant governmental authority in a manner that causes the
Company to become taxable as a corporation or otherwise subjects the Company to
taxation as an entity for federal, state or local income tax purposes. In such
event, the minimum quarterly distribution and the target distribution levels
would be reduced to an amount equal to the product of (1) the minimum quarterly
distribution and each of the target distribution levels, respectively,
multiplied by (2) one minus the sum of (x) the maximum effective federal income
tax rate to which the Company is then subject as an entity plus (y) any increase
that results from such legislation in the effective overall state and local
income tax rate to which the Company is subject as an entity for the taxable
year in which such event occurs (after taking into account the benefit of any
deduction allowable for federal income tax purposes with respect to the payment
of state and local income taxes). For example, assuming the Company was not
previously subject to state and local income tax, if the Company were to become
taxable as an entity for federal income tax purposes and the Company became
subject to a maximum marginal federal, and effective state and local, income tax
rate of 38%, then the minimum quarterly distribution and the target distribution
levels would each be reduced to 62% of the amount thereof immediately prior to
such adjustment.

DISTRIBUTIONS OF CASH UPON LIQUIDATION

Following the commencement of the dissolution and liquidation of the
Company, assets will be sold or otherwise disposed of from time to time and the
partners' capital account balances will be adjusted to reflect any resulting
gain or loss in the manner provided in the Partnership Agreement. The proceeds
of such liquidation will first be applied to the payment of creditors of the
Company in the order of priority provided in the Partnership Agreement and by
law and, thereafter, be distributed to the unitholders and the General Partner
in accordance with their respective capital account balances as so adjusted.

Partners are entitled to liquidating distributions in accordance with
capital account balances. The allocations of gains and losses upon liquidation
are intended, to the extent possible, to entitle the holders of outstanding
common units to a preference over the holders of outstanding subordinated units
upon the liquidation of the Company, to the extent required to permit common
unitholders to receive their unrecovered capital plus any unpaid common unit
arrearages. Thus, net losses recognized upon liquidation of the Company will be
allocated to the holders of the subordinated units to the extent of their
capital account balances before any loss is allocated to the holders of the
common units, and net gains recognized upon liquidation will be allocated first
to restore negative balances in the capital account of the General Partner and
any unitholders and then to the common unitholders until their capital account
balances equal their unrecovered capital plus unpaid common unit arrearages.
However, no assurance can be given that there will be sufficient gain upon
liquidation of the Company to enable the holders of common units to fully
recover all of such amounts, even though there may be cash available after such
allocation for distribution to the holders of subordinated units.

If the liquidation of the Company occurs before the end of the
Subordination Period, any net gain (or unrealized gain attributable to assets
distributed in kind) will be allocated to the partners as follows:

first, to the General Partner and the holders of units having negative
balances in their capital accounts to the extent of and in proportion to
such negative balances:

second, 98% to the holders of common units, pro rata, and 2% to the
General Partner, until the capital account for each common unit is equal to
the sum of (1) the unrecovered capital in respect of such common unit, (2)
the amount of the minimum quarterly distribution for the quarter during
which liquidation of the Company occurs and (3) any unpaid common unit
arrearages in respect of such common unit;

third, 98% to the holders of subordinated units, pro rata, and 2% to
the General Partner, until the capital account for each common unit is
equal to the sum of (1) the unrecovered capital in respect of such common
unit, (2) the amount of the minimum quarterly distribution for the quarter
during which liquidation of the Company occurs and (3) any unpaid common
unit arrearages in respect of such common unit;

fourth, 98% to all unitholders, pro rata, and 2% to the General
Partner, until there has been allocated under this paragraph fourth an
amount per unit equal to (a) the sum of the excess of the First Target
Distribution per unit over the minimum quarterly distribution per unit for
each quarter of the Company's existence, less (b) the cumulative amount per
unit of any distributions of available cash from operating surplus in
excess of the minimum quarterly distribution per unit that were distributed
98% to the unitholders, pro rata, and 2% to the General Partner for each
quarter of the Company's existence;

fifth, 85% to all unitholders, pro rata, and 15% to the General
Partner, until there has been allocated under this paragraph fifth an
amount per unit equal to (a) the sum of the excess of the Second Target
Distribution per unit over the First Target Distribution per unit for each
quarter of the Company's existence, less (b) the cumulative amount per unit
of any distributions of available cash from operating surplus in excess of
the First Target Distribution per unit that were distributed 85% to the
unitholders, pro rata, and 15% to the General Partner for each quarter of
the Company's existence;

sixth, 75% to all unitholders, pro rata, and 25% to the General
Partner, until there has been allocated under this paragraph sixth an
amount per unit equal to (a) the sum of the excess of the Third Target
Distribution per unit over the Second Target Distribution per unit for each
quarter of the Company's existence, less (b) the cumulative amount per unit
of any distributions of available cash from operating surplus in excess of
the Second Target Distribution per unit that were distributed 75% to the
unitholders, pro rata, and 25% to the General Partner for each quarter of
the Company's existence; and

thereafter, 50% to all unitholders, pro rata, and 50% to the General
Partner.

If the liquidation occurs after the Subordination Period, the distinction
between common units and subordinated units will disappear, so that clauses (ii)
and (iii) of paragraph second above and all of paragraph third above will no
longer be applicable.

Upon liquidation of the Company, any loss will generally be allocated to
the General Partner and the unitholders as follows:

first, 98% to holders of subordinated units in proportion to the
positive balances in their respective capital accounts and 2% to the
General Partner, until the capital accounts of the holders of the
subordinated units have been reduced to zero;

second, 98% to the holders of common units in proportion to the
positive balances in their respective capital accounts and 2% to the
General Partner, until the capital accounts of the common unitholders have
been reduced to zero; and

thereafter, 100% to the General Partner.

If the liquidation occurs after the Subordination Period, the distinction
between common units and subordinated units will disappear, so that all of
paragraph first above will no longer be applicable.

In addition, interim adjustments to capital accounts will be made at the
time the Company issues additional partnership interests in the Company or makes
distributions of property. Such adjustments will be based on the fair market
value of the partnership interests or the property distributed and any gain or
loss resulting therefrom will be allocated to the unitholders and the General
Partner in the same manner as gain or loss is allocated upon liquidation. In the
event that positive interim adjustments are made to the capital accounts, any
subsequent negative adjustments to the capital accounts resulting from the
issuance of additional partnership interests in the Company, distributions of
property

by the Company, or upon liquidation of the Company, will be allocated in a
manner which results, to the extent possible, in the capital account balances of
the General Partner equaling the amount which would have been the General
Partner's capital account balances if no prior positive adjustments to the
capital accounts had been made.

TRANSFER AGENT AND REGISTRAR

ChaseMellon Shareholder Services, LLC is our registrar and transfer agent
for the common units. You may contact them at the following address:

Mellon Investor Services LLC
Overpeck Center
85 Challenger Road
Ridgefield Park, NJ 07760

All fees charged by the transfer agent for transfers of common units will
be borne by us and not by the holders of common units, except that fees similar
to those customarily paid by stockholders for surety bond premiums to replace
lost or stolen certificates, taxes and other governmental charges, special
charges for services requested by a holder of a common unit and other similar
fees or charges will be borne by the affected holder.

TRANSFER OF COMMON UNITS

Until a common unit has been transferred on the books of the Company, the
Company and the transfer agent, notwithstanding any notice to the contrary, may
treat the record holder thereof as the absolute owner for all purposes, except
as otherwise required by law or stock exchange regulations. Any transfers of a
common unit will not be recorded by the transfer agent or recognized by the
Company unless the transferee executes and delivers a transfer application. By
executing and delivering a transfer application (the form of which is set forth
on the reverse side of the certificates representing the common units), the
transferee of common units (i) becomes the record holder of such common units
and shall constitute an assignee until admitted into the Company as a substitute
limited partner, (ii) automatically requests admission as a substituted limited
partner in the Company, (iii) agrees to be bound by the terms and conditions of,
and executes, the Partnership Agreement, (iv) represents that such transferee
has the capacity, power and authority to enter into the Partnership Agreement,
(v) grants powers of attorney to officers of the General Partner and any
liquidator of the Company as specified in the Partnership Agreement and (vi)
makes the consents and waivers contained in the Partnership Agreement. An
assignee will become a substituted limited partner of the Company in the respect
of the transferred common units upon the consent of the General Partner and the
recordation of the name of the assignee on the books and records of the company.
Such consent may be withheld in the sole discretion of the General Partner.

Common units are securities and are transferable according to the laws
governing transfer of securities. In addition to other rights acquired upon
transfer, the transferor gives the transferee the right to request admission as
a substituted limited partner in the Company in the respect of transferred
common units. A purchaser or transferee of common units who does not execute and
deliver a transfer application obtains only (a) the right to assign the common
units to a purchaser or other transferee and (b) the right to transfer the right
to seek admission as a substituted limited partner in the Company with respect
to the transferred common units. Thus, a purchaser or transferee of common units
who does not execute and deliver a transfer application will not receive cash
distributions or federal income tax allocations 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 such common units, and may not
receive certain federal income tax information or reports furnished to record
holders of common units. The transferor of common units will have a duty to
provide such transferee with all information that may be necessary to obtain
registration of the transfer of common units, that the transferor will not have
a duty to insure the execution of the transfer application by the transferee and
will have no liability or responsibility if such transferee neglects to or
chooses not to execute and forward the transfer application to the transfer
agent.

TAX CONSIDERATIONS

This section is a summary of all the material tax considerations that may
be relevant to prospective unitholders who are individual citizens or residents
of the United States and, unless otherwise noted in the following discussion,
expresses the opinion of Vinson & Elkins L.L.P., special counsel to the General
Partner and us, insofar as it relates to matters of United States federal income
tax law and legal conclusions with respect to those matters. This section is
based upon current provisions of the Internal Revenue Code, existing and
proposed regulations and current administrative rulings and court decisions, all
of which are subject to change. Later changes in these authorities may cause the
tax consequences to

vary substantially from the consequences described below. Unless the context
otherwise requires, references in this section to "us" or "we" are references to
Company and the Operating Partnership.

No attempt has been made in the following discussion to comment on all
federal income tax matters affecting us or the unitholders. Moreover, the
discussion focuses on unitholders who are individual citizens or residents of
the United States and has only limited application to corporations, estates,
trusts, nonresident aliens or other unitholders subject to specialized tax
treatment, such as tax-exempt institutions, foreign persons, individual
retirement accounts (IRAs), real estate investment trusts (REITs)or mutual
funds. Accordingly, we recommend that each prospective unitholder consult, and
depend on, his own tax advisor in analyzing the federal, state, local and
foreign tax consequences particular to him of the ownership or disposition of
common units.

All statements as to matters of law and legal conclusions, but not as to
factual matters, contained in this section, unless otherwise noted, are the
opinion of counsel and are based on the accuracy of the representations made by
us.

No ruling has been or will be requested from the IRS regarding any matter
affecting us or prospective unitholders. An opinion of counsel represents only
that counsel's best legal judgment and does not bind the IRS or the courts.
Accordingly, the opinions and statements made here may not be sustained by a
court if contested by the IRS. Any contest of this sort with the IRS may
materially and adversely impact the market for the common units and the prices
at which common units trade. In addition, the costs of any contest with the IRS
will be borne directly or indirectly by the unitholders and the General Partner.
Furthermore, the tax treatment of us, or of an investment in us, may be
significantly modified by future legislative or administrative changes or court
decisions. Any modifications may or may not be retroactively applied.

For the reasons described below, counsel has not rendered an opinion with
respect to the following specific federal income tax issues:

(1) the treatment of a unitholder whose common units are loaned to a
short seller to cover a short sale of common units (please read "-- Tax
Consequences of Unit Ownership -- Treatment of Short Sales");

(2) whether our monthly convention for allocating taxable income and
losses is permitted by existing Treasury Regulations (please read
"-- Disposition of Common Units -- Allocations Between Transferors and
Transferees"); and

(3) whether our method for depreciating Section 743 adjustments is
sustainable (please read "-- Tax Consequences of Unit Ownership -- Section
754 Election").

PARTNERSHIP STATUS

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

No ruling has been or will be sought from the IRS and the IRS has made no
determination as to our status or the status of the Operating Partnership as
partnerships for federal income tax purposes or whether our operations generate
"qualifying income" under Section 7704 of the Code. Instead, we will rely on the
opinion of counsel that, based upon the Internal Revenue Code, its regulations,
published revenue rulings and court decisions and the representations described
below, we and the Operating Partnership will be classified as a partnership for
federal income tax purposes.

In rendering its opinion, counsel has relied on factual representations
made by us and the General Partner. The representations made by us and our
General Partner upon which counsel has relied are:

(a) Neither we nor the Operating Partnership will elect to be treated
as a corporation; and

(b) For each taxable year, more than 90% of our gross income will be
income from sources that our counsel has opined or will opine is
"qualifying income" within the meaning of Section 7704(d) of the Internal
Revenue Code.

Section 7704 of the Internal Revenue Code provides that publicly-traded
partnerships will, as a general rule, be taxed as corporations. However, an
exception, referred to as the "Qualifying Income Exception," exists with respect
to publicly-traded partnerships of which 90% or more of the gross income for
every taxable year consists of "qualifying income." Qualifying income includes
income and gains derived from the exploration, development, mining or
production, processing, refining, transportation and marketing of any mineral or
natural resource. Other types of qualifying income include interest other than
from a financial business, dividends, gains from the sale of real property and
gains from the sale or other disposition of assets held for the production of
income that otherwise constitutes qualifying income. We estimate that less than
2% of our current gross income is not qualifying income; however, this estimate
could change

from time to time. Based upon and subject to this 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 90% of our
current gross income constitutes qualifying income.

If we fail to meet the Qualifying Income Exception, other than a failure
which is determined by the IRS to be inadvertent and which 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 of the year in which we fail to meet the Qualifying Income Exception,
in return for stock in that corporation, and then distributed that stock to the
unitholders in liquidation of their interests in us. This contribution and
liquidation should be tax-free to unitholders and us so long as we, at that
time, do not have liabilities in excess of the tax basis of our assets.
Thereafter, we would be treated as a corporation for federal income tax
purposes.

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

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

LIMITED PARTNER STATUS

Unitholders who have become limited partners of the Company will be treated
as partners of the Company for federal income tax purposes. Also:

(a) assignees who have executed and delivered transfer applications,
and are awaiting admission as limited partners, and

(b) 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 of the Company for federal income tax purposes.
As there is no direct authority addressing assignees of common units who are
entitled to execute and deliver transfer applications and 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.
Furthermore, a purchaser or other transferee of common units who does not
execute and deliver a transfer application may not receive some 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 for those common units.

A beneficial owner of common units whose units have been transferred to a
short seller to complete a short sale would appear to lose his status as a
partner with respect to those units for federal income tax purposes. Please read
"-- Tax Consequences of Unit Ownership -- Treatment of Short Sales."

Income, gain, deductions or losses would not appear to be reportable by a
unitholder who is not a partner for federal income tax purposes, and any cash
distributions received by a unitholder who is not a partner for federal income
tax purposes would therefore be fully taxable as ordinary income. These holders
should consult their own tax advisors with respect to their status as partners
in the Company for federal income tax purposes.

TAX CONSEQUENCES OF UNIT OWNERSHIP

Flow-through of Taxable Income. We will not pay any federal income tax.
Instead, each unitholder will be required to report on his income tax return his
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 a unitholder even if he has not received a cash distribution.
Each unitholder will be required to include in income his allocable share of our
income, gains, losses and deductions for our taxable year ending with or within
his taxable year.

Treatment of Distributions. Distributions by us to a unitholder generally
will not be taxable to the unitholder for federal income tax purposes to the
extent of his tax basis in his common units immediately before the distribution.
Our cash distributions in excess of a unitholder's tax 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 "-- Disposition of Common Units"
below. Any reduction in a unitholder's share of our liabilities for which no
partner, including the General Partner, bears the economic risk of loss, known
as "nonrecourse liabilities," will be treated as a distribution of cash to that
unitholder. To

the extent our distributions cause a unitholder's "at risk" amount to be less
than zero at the end of any taxable year, he must recapture any losses deducted
in previous years. Please read "-- Limitations on Deductibility of Losses."

A decrease in a unitholder's percentage interest in us because of our
issuance of additional common units will decrease his share of our nonrecourse
liabilities, and thus will result in a corresponding deemed distribution of
cash. A non-pro rata distribution of money or property may result in ordinary
income to a unitholder, regardless of his tax basis in his common units, if the
distribution reduces the unitholder's share of our "unrealized receivables,"
including depreciation recapture, and/or substantially appreciated "inventory
items," both as defined in the Internal Revenue Code, and collectively, "Section
751 Assets." To that extent, he will be treated as having been distributed his
proportionate share of the Section 751 Assets and having exchanged those assets
with us in return for the non-pro rata portion of the actual distribution made
to him. This latter deemed exchange will generally result in the unitholder's
realization of ordinary income. That income will equal the excess of (1) the
non-pro rata portion of that distribution over (2) the unitholder's tax basis
for the share of Section 751 Assets deemed relinquished in the exchange.

Basis of Common Units. A unitholder's initial tax basis for his common
units will be the amount he paid for the common units plus his share of our
nonrecourse liabilities. That basis will be increased by his share of our income
and by any increases in his share of our nonrecourse liabilities. That basis
will be decreased, but not below zero, by distributions from us, by the
unitholder's share of our losses, by any decreases in his share of our
nonrecourse liabilities and by his share of our expenditures that are not
deductible in computing taxable income and are not required to be capitalized. A
limited partner will have no share of our debt which is recourse to the General
Partner, but will have a share, generally based on his share of profits, of our
nonrecourse liabilities. Please read "-- Disposition of Common
Units -- Recognition of Gain or Loss."

Limitations on Deductibility of Losses. The deduction by a unitholder of
his share of our losses will be limited to the tax basis in his units and, in
the case of an individual unitholder or a corporate unitholder, if more than 50%
of the value of the corporate unitholder's stock is owned directly or indirectly
by five or fewer individuals or some tax-exempt organizations, to the amount for
which the unitholder is considered to be "at risk" with respect to our
activities, if that is less than his tax basis. A unitholder must recapture
losses deducted in previous years to the extent that distributions cause his 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 his tax basis or at risk
amount, whichever is the limiting factor, is subsequently increased. Upon the
taxable disposition of a unit, any gain recognized by a unitholder can be offset
by losses that were previously suspended by the at risk limitation but may not
be offset by losses suspended by the basis limitation. Any excess loss above
that gain previously suspended by the at risk or basis limitations is no longer
utilizable.

In general, a unitholder will be at risk to the extent of the tax basis of
his units, excluding any portion of that basis attributable to his share of our
nonrecourse liabilities, reduced by any amount of money he borrows to acquire or
hold his units, if the lender of those borrowed funds owns an interest in us, is
related to the unitholder or can look only to the units for repayment. A
unitholder's at risk amount will increase or decrease as the tax basis of the
unitholder's units increases or decreases, other than tax basis increases or
decreases attributable to increases or decreases in his share of our nonrecourse
liabilities.

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

A unitholder's share of our net income may be offset by any 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.

Limitations on Interest Deductions. The deductibility of a non-corporate
taxpayer's "investment interest expense" is generally limited to the amount of
that taxpayer's "net investment income." 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. 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 unit. Net investment income includes gross income from
property held for investment and amounts treated as portfolio income under the
passive loss rules, less deductible expenses, other than interest, directly
connected with the production of investment income, but generally does not
include gains attributable to the disposition of property held for investment.

Entity-Level Collections. If we are required or elect under applicable law
to pay any federal, state or local income tax on behalf of any unitholder or the
General Partner or any former unitholder, we are authorized to pay those taxes
from our funds. That payment, if made, will be treated as a distribution of cash
to the partner on whose behalf the payment was made. If the payment is made on
behalf of a person whose identity cannot be determined, we are authorized to
treat the payment as a distribution to all current unitholders. We are
authorized to amend the partnership agreement in the manner necessary to
maintain uniformity of intrinsic tax characteristics of units and to adjust
later distributions, so that after giving effect to these distributions, the
priority and characterization of distributions otherwise applicable under the
partnership agreement is maintained as nearly as is practicable. Payments by us
as described above could give rise to an overpayment of tax on behalf of an
individual partner in which event the partner would be required to file a claim
in order to obtain a credit or refund.

Allocation of Income, Gain, Loss and Deduction. In general, if we have a
net profit, our items of income, gain, loss and deduction will be allocated
among the General Partner and the unitholders in accordance with their
percentage interests in us. At any time that distributions are made to the
common units in excess of distributions to the subordinated units, or incentive
distributions are made to the General Partner, gross income will be allocated to
the recipients to the extent of these distributions. If we have a net loss for
the entire year, that loss will be allocated first to the General Partner and
the unitholders in accordance with their percentage interests in us to the
extent of their positive capital accounts and, second, to the General Partner.

Specified items of our income, gain, loss and deduction will be allocated
to account for the difference between the tax basis and fair market value of
property contributed to us by the General Partner and its affiliates, referred
to in this discussion as "Contributed Property." The effect of these allocations
to a unitholder purchasing common units in this offering will be essentially the
same as if the tax basis of our assets were equal to their fair market value at
the time of this offering. In addition, items of recapture income will be
allocated to the extent possible to the partner who was allocated the deduction
giving rise to the treatment of that gain as recapture income in order to
minimize the recognition of ordinary income by some unitholders. 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 to
eliminate the negative balance as quickly as possible.

An allocation of items of our income, gain, loss or deduction, other than
an allocation required by the Internal Revenue Code to eliminate the difference
between a partner's "book" capital account, credited with the fair market value
of Contributed Property, and "tax" capital account, credited with the tax basis
of Contributed Property, referred to in this discussion as the "Book-Tax
Disparity", will generally be given effect for federal income tax purposes in
determining a partner's 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 share of an item will be determined on the basis of his interest in
us, which will be determined by taking into account all the facts and
circumstances, including his relative contributions to us, the interests of all
the partners in profits and losses, the interest of all the partners in cash
flow and other nonliquidating distributions and rights of all the partners to
distributions of capital upon liquidation.

Counsel is of the opinion that, with the exception of the issues described
in "-- Tax Consequences of Unit Ownership -- Section 754 Election" and
"-- Disposition of Common Units -- Allocations Between Transferors and
Transferees," allocations under our partnership agreement will be given effect
for federal income tax purposes in determining a partner's share of an item of
income, gain, loss or deduction.

Treatment of Short Sales. A unitholder whose units are loaned to a "short
seller" to cover a short sale of units may be considered as having disposed of
those units. If so, he would no longer be a partner for those units during the
period of the loan and may recognize gain or loss from the disposition. As a
result, during this period:

- any of our income, gain, loss or deduction with respect to those units
would not be reportable by the unitholder;

- any cash distributions received by the unitholder as to those units would
be fully taxable; and

- all of these distributions would appear to be ordinary income.

Counsel has not rendered an opinion regarding the treatment of a unitholder
where common units are loaned to a short seller to cover a short sale of common
units; therefore, unitholders desiring to assure their status as partners and
avoid the risk of gain recognition from a loan to a short seller should modify
any applicable brokerage account agreements to prohibit their brokers from
borrowing their units. The IRS has announced that it is actively studying issues
relating to the tax treatment of short sales of partnership interests. Please
also read "-- Disposition of Common Units -- Recognition of Gain or Loss."

Alternative Minimum Tax. Each unitholder will be required to take into
account his distributive share of any items of our income, gain, loss or
deduction for purposes of the alternative minimum tax. The current minimum tax
rate for noncorporate taxpayers is 26% on the first $175,000 of alternative
minimum taxable income in excess of the exemption amount and 28% on any
additional alternative minimum taxable income. Prospective unitholders should
consult with their tax advisors as to the impact of an investment in units on
their liability for the alternative minimum tax.

Tax Rates. In general the highest effective United States federal income
tax rate for individuals for 2001 is 39.6% and the maximum United States federal
income tax rate for net capital gains of an individual for 2001 is 20% if the
asset disposed of was held for more than 12 months at the time of disposition.

Section 754 Election. We have made the election permitted by Section 754
of the Internal Revenue Code. That election is irrevocable without the consent
of the IRS. The election generally permits us to adjust a common unit
purchaser's tax basis in our assets ("inside basis") under Section 743(b) of the
Internal Revenue Code to reflect his purchase price. This election does not
apply to a person who purchases common units directly from us. The Section
743(b) adjustment belongs to the purchaser and not to other partners. 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 tax basis in our assets
("common basis") and (2) his Section 743(b) adjustment to that basis.

Treasury regulations under Section 743 of the Internal Revenue Code require
that, if the remedial allocation method is adopted (which we have adopted), a
portion of the Section 743(b) adjustment attributable to recovery property be
depreciated over the remaining cost recovery period for the Section 704(c)
built-in gain. Under Treasury Regulation Section 1.167(c)-l(a)(6), a Section
743(b) adjustment attributable to property subject to depreciation under Section
167 of the Internal Revenue 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. Under our partnership
agreement, the General Partner is authorized to take a position to preserve the
uniformity of units even if that position is not consistent with these Treasury
Regulations. Please read "-- Tax Treatment of Operations -- Uniformity of
Units."

Although counsel is unable to opine as to the validity of this approach
because there is no clear authority on this issue, we intend to depreciate the
portion of a Section 743(b) adjustment attributable to unrealized appreciation
in the value of Contributed 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 the property, or treat that portion as non-amortizable to the extent
attributable to property the common basis of which is not amortizable. This
method is consistent with the regulations under Section 743 but is arguably
inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6). To the extent
this 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 take a depreciation or amortization
position under which all purchasers acquiring units in the same month would
receive depreciation or amortization, whether attributable to common basis or a
Section 743(b) adjustment, based upon the same applicable rate as if they had
purchased a direct interest in our assets. This kind of aggregate approach may
result in lower annual depreciation or amortization deductions than would
otherwise be allowable to some unitholders. Please read "-- Tax Treatment of
Operations -- Uniformity of Units."

A Section 754 election is advantageous if the transferee's tax basis in his
units is higher than the units' share of the aggregate tax basis of our assets
immediately prior to the transfer. In that case, as a result of the election,
the transferee would have, among other items, a greater amount of depreciation
and depletion deductions and his share of any gain or loss on a sale of our
assets would be less. Conversely, a Section 754 election is disadvantageous if
the transferee's tax basis in his units is lower than those units' share of the
aggregate tax basis of our assets immediately prior to the transfer. Thus, the
fair market value of the units may be affected either favorably or unfavorably
by the election.

The calculations involved in the Section 754 election are complex and will
be made on the basis of assumptions as to the value of our assets and other
matters. For example, the allocation of the Section 743(b) adjustment among our
assets must be made in accordance with the Internal Revenue Code. The IRS could
seek to reallocate some or all of any Section 743(b) adjustment allocated by us
to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is
generally amortizable over a longer period of time or under a less accelerated
method than our tangible assets. We cannot assure you that the determinations we
make will not be successfully challenged by the IRS and that the deductions
resulting

from them will not be reduced or disallowed altogether. Should the IRS require a
different basis adjustment to be made, and should, in our opinion, the expense
of compliance exceed the benefit of the election, we may seek permission from
the IRS to revoke our Section 754 election. If permission is granted, a
subsequent purchaser of units may be allocated more income than he would have
been allocated had the election not been revoked.

TAX TREATMENT OF OPERATIONS

Accounting Method and Taxable Year. We use the year ending December 31 as
our taxable year and the accrual method of accounting for federal income tax
purposes. Each unitholder will be required to include in income his share of our
income, gain, loss and deduction for our taxable year ending within or with his
taxable year. In addition, a unitholder who has a taxable year ending on a date
other than December 31 and who disposes of all of his units following the close
of our taxable year but before the close of his taxable year must include his
share of our income, gain, loss and deduction in income for his taxable year,
with the result that he will be required to include in income for his taxable
year his share of more than one year of our income, gain, loss and deduction.
Please read "-- Disposition of Common Units -- Allocations Between Transferors
and Transferees."

Initial Tax Basis, Depreciation and Amortization. The tax basis of our
assets will be used for purposes of computing depreciation and cost recovery
deductions and, ultimately, gain or loss on the disposition of these assets. The
federal income tax burden associated with the difference between the fair market
value of our assets and their tax basis immediately prior to this offering will
be borne by the General Partner and its affiliates. Please read "-- Allocation
of Income, Gain, Loss and Deduction."

To the extent allowable, we may elect to use the depreciation and cost
recovery methods that will result in the largest deductions being taken in the
early years after assets are placed in service. We are not entitled to any
amortization deductions with respect to any goodwill conveyed to us on
formation. Property we subsequently acquire or construct may be depreciated
using accelerated methods permitted by the Internal Revenue 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 we own will likely be required to recapture some or all, of
those deductions as ordinary income upon a sale of his interest in us. Please
read "-- Tax Consequences of Unit Ownership -- Allocation of Income, Gain, Loss
and Deduction" and "-- Disposition of Common Units -- Recognition of Gain or
Loss."

The costs incurred in selling our units (called "syndication expenses")
must be capitalized and cannot be deducted currently, ratably or upon our
termination. There are uncertainties regarding the classification of costs as
organization expenses, which may be amortized by us, and as syndication
expenses, which may not be amortized by us. The underwriting discounts and
commissions we incur will be treated as a syndication cost.

Valuation and Tax Basis of Our Properties. The federal income tax
consequences of the ownership and disposition of units will depend in part on
our estimates of the relative fair market values, and the initial tax bases, of
our assets. Although we may from time to time consult with professional
appraisers regarding valuation matters, we will make many of the relative fair
market value estimates ourselves. These estimates of basis are subject to
challenge and will not be binding on the IRS or the courts. If the estimates of
fair market value or basis are later found to be incorrect, the character and
amount of items of income, gain, loss or deductions previously reported by
unitholders might change, and unitholders might be required to adjust their tax
liability for prior years and incur interest and penalties with respect to those
adjustments.

DISPOSITION OF COMMON UNITS

Recognition of Gain or Loss. Gain or loss will be recognized on a sale of
units equal to the difference between the amount realized and the unitholder's
tax basis for the 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 by him
plus his share of our nonrecourse liabilities. Because the amount realized
includes a unitholder's share of our nonrecourse liabilities, the gain
recognized on the sale of units could result in a tax liability in excess of any
cash received from the sale.

Prior distributions from us in excess of cumulative net taxable income for
a common unit that decreased a unitholder's tax basis in that common unit will,
in effect, become taxable income if the common unit is sold at a price greater
than the unitholder's tax basis in that common unit, even if the price received
is less than his original cost.

Except as noted below, gain or loss recognized by a unitholder, other than
a "dealer" in units, on the sale or exchange of a unit held for more than one
year will generally be taxable as capital gain or loss. Capital gain recognized
by an individual on the sale of units held more than 12 months will generally be
taxed at a maximum rate of 20%. A

portion of this gain or loss, which will likely be substantial, however, will be
separately computed and taxed as ordinary income or loss under Section 751 of
the Internal Revenue Code to the extent attributable to assets giving rise to
depreciation recapture or other "unrealized receivables" or to "inventory items"
we own. The term "unrealized receivables" includes potential recapture items,
including depreciation recapture. Ordinary income attributable to unrealized
receivables, inventory items and depreciation recapture may exceed net taxable
gain realized upon the sale of a unit and may be recognized even if there is a
net taxable loss realized on the sale of a unit. Thus, a unitholder may
recognize both ordinary income and a capital loss upon a sale of units. Net
capital loss may offset capital gains and 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 corporations.

The IRS has ruled that a partner who acquires interests in a partnership in
separate transactions must combine those interests and maintain a single
adjusted tax basis for all those interests. Upon a sale or other disposition of
less than all of those interests, a portion of that tax basis must be allocated
to the interests sold using an "equitable apportionment" method. Although the
ruling is unclear as to how the holding period of these interests is determined
once they are combined, recently finalized regulations allow a selling
unitholder who can identify common units transferred with an ascertainable
holding period to elect to use the actual holding period of the common units
transferred. Thus, according to the ruling, a common unitholder will be unable
to select high or low basis common units to sell as would be the case with
corporate stock, but, according to the regulations, may designate specific
common units sold for purposes of determining the holding period of units
transferred. A unitholder electing to use the actual holding period of common
units transferred must consistently use that identification method for all
subsequent sales or exchanges of common units. A unitholder considering the
purchase of additional units or a sale of common units purchased in separate
transactions should consult his tax advisor as to the possible consequences of
this ruling and application of the final regulations.

Specific provisions of the Internal Revenue Code affect the taxation of
some financial products and securities, including partnership interests, by
treating a taxpayer as having sold an "appreciated" partnership interest, one in
which gain would be recognized if it were sold, assigned or terminated at its
fair market value, if the taxpayer or related persons enter(s) into:

- a short sale;

- an offsetting notional principal contract; or

- a futures or forward contract with respect to the partnership interest or
substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an
offsetting notional principal contract or a futures or forward contract with
respect to the partnership interest, the taxpayer will be treated as having sold
that position if the taxpayer or a related person then acquires the partnership
interest or substantially identical property. The Secretary of Treasury is also
authorized to issue regulations that treat a taxpayer that enters into
transactions or positions that have substantially the same effect as the
preceding transactions as having constructively sold the financial position.

Allocations Between Transferors and Transferees. In general, our taxable
income and losses will be determined annually, will be prorated on a monthly
basis and will be subsequently apportioned among the unitholders in proportion
to the number of units owned by each of them as of the opening of the applicable
exchange on the first business day of the month (the "Allocation Date").
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 the
unitholders on the Allocation Date in the month in which that gain or loss is
recognized. As a result, a unitholder transferring units may be allocated
income, gain, loss and deduction realized after the date of transfer.

The use of this method may not be permitted under existing Treasury
Regulations. Accordingly, counsel is unable to opine on the validity of this
method of allocating income and deductions between unitholders. If this method
is not allowed under the Treasury Regulations, or only applies to transfers of
less than all of the unitholder's interest, our taxable income or losses might
be reallocated among the unitholders. We are authorized to revise our method of
allocation between unitholders to conform to a method permitted under future
Treasury Regulations.

A unitholder who owns units at any time during a quarter and who disposes
of them prior to the record date set for a cash distribution for that quarter
will be allocated items of our income, gain, loss and deductions attributable to
that quarter but will not be entitled to receive that cash distribution.

Notification Requirements. A unitholder who sells or exchanges units is
required to notify us in writing of that sale or exchange within 30 days after
the sale or exchange. We are required to notify the IRS of that transaction and
to furnish specified information to the transferor and transferee. However,
these reporting requirements do not apply to a sale by an individual who is a
citizen of the United States and who effects the sale or exchange through a
broker. Additionally, a transferor and a transferee of a 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 describe the amount of
the

consideration received for the 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 have been terminated
for tax purposes if there is a sale or exchange of 50% or more of the total
interests in our capital and profits within a 12-month period. A constructive
termination results in the closing of our taxable year for all unitholders. In
the case of a unitholder reporting on a taxable year other than a fiscal year
ending December 31, the closing of our taxable year may result in more than 12
months of our taxable income or loss being includable in his taxable income for
the year of termination. We would be required to make new tax elections after a
termination, including a new election under Section 754 of the Internal Revenue
Code, and a termination would result in a deferral of our deductions for
depreciation. A termination could also result in penalties if we were unable to
determine that the termination had occurred. Moreover, a termination might
either accelerate the application of, or subject us to, any tax legislation
enacted before the termination.

UNIFORMITY OF UNITS

Because we cannot match transferors and transferees of units, we must
maintain uniformity of the economic and tax characteristics of the units to a
purchaser of these units. In the absence of uniformity, we may be unable to
completely comply with a number of federal income tax requirements, both
statutory and regulatory. A lack of uniformity can result from a literal
application of Treasury Regulation Section 1.167(c)-1(a)(6). Any non-uniformity
could have a negative impact on the value of the units. Please read "-- Tax
Consequences of Unit Ownership -- Section 754 Election."

We intend to depreciate the portion of a Section 743(b) adjustment
attributable to unrealized appreciation in the value of Contributed 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 that property, or treat that portion as
nonamortizable, to the extent attributable to property the common basis of which
is not amortizable, consistent with the regulations under Section 743, even
though that position may be inconsistent with Treasury Regulation Section
1.167(c)-1(a)(6). Please read "-- Tax Consequences of Unit Ownership -- 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 Regulations and legislative
history. If we determine that this position cannot reasonably be taken, we may
adopt a depreciation and amortization position under which all purchasers
acquiring units in the same month would receive depreciation and amortization
deductions, whether attributable to a common basis or Section 743(b) adjustment,
based upon the same applicable rate as if they had purchased a direct interest
in our property. If this position is adopted, it may result in lower annual
depreciation and amortization deductions than would otherwise be allowable to
some unitholders and risk the loss of depreciation and amortization deductions
not taken in the year that these deductions are otherwise allowable. This
position will not be adopted if we determine that the loss of depreciation and
amortization deductions will have a material adverse effect on the unitholders.
If we choose not to utilize this aggregate method, we may use any other
reasonable depreciation and amortization method to preserve the uniformity of
the intrinsic tax characteristics of any units that would not have a material
adverse effect on the unitholders. The IRS may challenge any method of
depreciating the Section 743(b) adjustment described in this paragraph. If this
challenge were sustained, the uniformity of units might be affected, and the
gain from the sale of units might be increased without the benefit of additional
deductions. Please read "-- Disposition of Common Units -- Recognition of Gain
or Loss."

TAX-EXEMPT ORGANIZATIONS AND OTHER INVESTORS

Ownership of 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 those investors and,
as described below, may have substantially adverse tax consequences to them.

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 our income allocated to a unitholder which is a tax-exempt
organization will be unrelated business taxable income and will be taxable to
them.

A regulated investment company or "mutual fund" is required to derive 90%
or more of its gross income from interest, dividends and gains from the sale of
stocks or securities or foreign currency or specified related sources. It is not
anticipated that any significant amount of our gross income will include that
type of income.

Non-resident aliens and foreign corporations, trusts or estates that own
units will be considered to be engaged in business in the United States because
of the ownership of units. As a consequence they will be required to file
federal tax returns to report their share of our income, gain, loss or deduction
and pay federal income tax at regular rates on their share of our net income or
gain. And, under rules applicable to publicly traded partnerships, we will
withhold (currently at the rate of 39.6%) on 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 or applicable substitute form in order to
obtain credit for these withholding taxes.

In addition, because a foreign corporation that owns units will be treated
as engaged in a United States trade or business, that corporation may be subject
to the United States branch profits tax at a rate of 30%, in addition to regular
federal income tax, on its share of our income and gain, as adjusted for changes
in the foreign corporation's "U.S. net equity," which are effectively connected
with the conduct of a United States trade or business. That tax may be reduced
or eliminated by an income tax treaty between the United States and the country
in which the foreign corporate unitholder is a "qualified resident." In
addition, this type of unitholder is subject to special information reporting
requirements under Section 6038C of the Internal Revenue Code.

Under a ruling of the IRS, a foreign unitholder who sells or otherwise
disposes of a unit will be subject to federal income tax on gain realized on the
sale or disposition of that unit to the extent that this 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 or subject to
withholding upon the sale or disposition of a unit if he has owned less than 5%
in value of the units during the five-year period ending on the date of the
disposition and if the units are regularly traded on an established securities
market at the time of the sale or disposition.

ADMINISTRATIVE MATTERS

Information Returns and Audit Procedures. We intend to furnish to each
unitholder, within 90 days after the close of each calendar year, specific tax
information, including a Schedule K-1, which describes his share of our income,
gain, loss and deduction for our preceding taxable year. In preparing this
information, which will not be reviewed by counsel, we will take various
accounting and reporting positions, some of which have been mentioned earlier,
to determine his share of income, gain, loss and deduction. We cannot assure you
that those positions will yield a result that conforms to the requirements of
the Internal Revenue Code, regulations or administrative interpretations of the
IRS. Neither we nor counsel can assure prospective unitholders that the IRS will
not successfully contend in court that those positions are impermissible. Any
challenge by the IRS could negatively affect the value of the units.

The IRS may audit our federal income tax information returns. Adjustments
resulting from an IRS audit may require each unitholder to adjust a prior year's
tax liability, and possibly may result in an audit of his own return. Any audit
of a unitholder's return could result in adjustments not related to our returns
as well as those related to our returns.

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 and deduction are determined in a partnership proceeding rather than
in separate proceedings with the partners. The Internal Revenue Code requires
that one partner be designated as the "Tax Matters Partner" for these purposes.
The partnership agreement names the General Partner as our Tax Matters Partner.

The Tax Matters Partner will make some elections on our behalf and on
behalf of unitholders. In addition, the Tax Matters Partner can extend the
statute of limitations for assessment of tax deficiencies against unitholders
for items in our returns. The Tax Matters Partner may bind a unitholder with
less than a 1% profits interest in us to a settlement with the IRS unless that
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, by which all the unitholders are bound, of a final partnership
administrative adjustment and, if the Tax Matters Partner fails to seek judicial
review, judicial review may be sought by any unitholder having at least a 1%
interest in profits or by any group of unitholders having in the aggregate at
least a 5% interest in profits. However, only one action for judicial review
will go forward, and each unitholder with an interest in the outcome may
participate.

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. Intentional or negligent disregard of this
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:

(a) the name, address and taxpayer identification number of the
beneficial owner and the nominee;

(b) whether the beneficial owner is

(1) a person that is not a United States person,

(2) a foreign government, an international organization or any
wholly owned agency or instrumentality of either of the
foregoing, or

(3) a tax-exempt entity;

(d) specific 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 specific
information on 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 Internal Revenue Code for failure to report that information to
us. The nominee is required to supply the beneficial owner of the units with the
information furnished to us.

Registration as a Tax Shelter. The Internal Revenue 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
Internal Revenue Code are extremely broad. It is arguable that we are not
subject to the registration requirement on the basis that we will not constitute
a tax shelter. However, the General Partner, as our principal organizer, has
registered us as a tax shelter with the Secretary of Treasury because of the
absence of assurance that we will not be subject to tax shelter registration and
in light of the substantial penalties which might be imposed if registration is
required and not undertaken.

ISSUANCE OF THIS REGISTRATION NUMBER DOES NOT INDICATE THAT INVESTMENT IN US OR
THE CLAIMED TAX BENEFITS HAVE BEEN REVIEWED, EXAMINED OR APPROVED BY THE IRS.

We must supply our tax shelter registration number to unitholders, and a
unitholder who sells or otherwise transfers a unit in a later transaction must
furnish the registration number to the transferee. The penalty for failure of
the transferor of a 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 or other benefit we generate is claimed or on which any of our
income is included. A unitholder who fails to disclose the tax shelter
registration number on his return, without reasonable cause for that failure,
will be subject to a $250 penalty for each failure. Any penalties discussed 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
specified causes, including negligence or disregard of rules or regulations,
substantial understatements of income tax and substantial valuation
misstatements, is imposed by the Internal Revenue Code. No penalty will be
imposed, however, for 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 regarding 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 generally is
reduced if any portion is attributable to a position adopted on the return:

(1) for which there is, or was, "substantial authority," or

(2) as to which there is a reasonable basis and the pertinent facts of
that position are disclosed on the return.

More stringent rules apply to "tax shelters," a term that in this context
does not appear to include us. If any item of income, gain, loss or deduction
included in the distributive shares of unitholders might result in that kind of
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 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%.

STATE, LOCAL AND OTHER TAX CONSIDERATIONS

In addition to federal income taxes, you will be subject to other taxes,
including state and local income taxes, unincorporated business taxes, and
estate, inheritance or intangible taxes that may be imposed by the various
jurisdictions in which we do business or own property or in which you are a
resident. Although an analysis of those various taxes is not presented here,
each prospective unitholder should consider their potential impact on his
investment in us. You will be required to file state income tax returns and to
pay state income taxes in some or all of the states in which we do business or
own property and may be subject to penalties for failure to comply with those
requirements. In some states,

tax losses may not produce a tax benefit in the year incurred and also may not
be available to offset income in subsequent taxable years. Some of the states
may require us, or we may elect, 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 of which may be greater or less than a particular
unitholder's income tax liability to the state, generally does not relieve a
nonresident unitholder from the obligation to file an income tax return. Amounts
withheld may be treated as if distributed to unitholders for purposes of
determining the amounts distributed by us. Please read "-- Tax Consequences of
Unit Ownership -- Entity-Level Collections." Based on current law and our
estimate of our 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 and localities, 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 state
and local, as well as United States federal tax returns, that may be required of
him. Counsel has not rendered an opinion on the 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.

SELLING UNITHOLDERS

In addition to covering our offering of securities, this Prospectus covers
the offering for resale of an unspecified number of common units by selling
unitholders. The applicable prospectus supplement will set forth, with respect
to each selling unitholder,

(1) the name of the selling unitholder,

(2) the nature of any position, office or other materials relationship
which the selling unitholder will have had within the prior three years
with us or any of our predecessors or affiliates,

(3) the number of common units owned by the selling unitholders prior
to the offering,

(4) the amount of common units to be offered for the selling
unitholder's account, and

(5) the amount and (if one percent or more) the percentage of the
common units to be owned by the selling unitholders after completion of the
offering.

PLAN OF DISTRIBUTION

We may sell the common units or debt securities directly, through agents,
or to or through underwriters or dealers. Please read the prospectus supplement
to find the terms of the common unit or debt securities offering including:

- the names of any underwriters, dealers or agents;

- the offering price;

- underwriting discounts;

- sales agents' commissions;

- other forms of underwriter or agent compensation;

- discounts, concessions or commissions that underwriters may pass on to
other dealers;

- any exchange on which the common units or debt securities are listed.

We may change the offering price, underwriter discounts or concessions, or
the price to dealers when necessary. Discounts or commissions received by
underwriters or agents and any profits on the resale of common units or debt
securities by them may constitute underwriting discounts and commissions under
the Securities Act of 1933.

Unless we state otherwise in the prospectus supplement, underwriters will
need to meet certain requirements before purchasing common units or debt
securities. Agents will act on a "best efforts" basis during their appointment.
We will also state the net proceeds from the sale in the prospectus supplement.

Any brokers or dealers that participate in the distribution of the common
units or debt securities may be "underwriters" within the meaning of the
Securities Act of 1933 (the "Securities Act") for such sales. Profits,
commissions, discounts or concessions received by such broker or dealer may be
underwriting discounts and commissions under the securities act.

The aggregate maximum compensation that members of the NASD or independent
broker-dealers will receive in connection with the sale of any securities
pursuant to this registration statement will not be greater than 8% of the gross
proceeds of such sale. Included in this compensation at 1% of such gross
proceeds will be any right of first refusal granted to the underwriters to
underwrite any offering of securities under this registration statement, unless
such right of first refusal is assigned another value.

When necessary, we may fix common unit or debt securities distribution
using changeable, fixed prices, market prices at the time of sale, prices
related to market prices, or negotiated prices.

We may, through agreements, indemnify underwriters, dealers or agents who
participate in the distribution of the common units or debt securities against
certain liabilities including liabilities under the Securities Act. We may also
provide funds for payments such underwriters, dealers or agents may be required
to make. Underwriters, dealers and agents, and their affiliates may transact
with us and our affiliates in the ordinary course of their business.

Because the NASD views our common units as interests in a direct
participation program, any offering of common units pursuant to this
registration statement will be made in compliance with Rule 2810 of the NASD
Conduct Rules. Investor suitability with respect to the common units will be
judged similarly to the suitability with respect to other securities that are
listed for trading on a national securities exchange.

DISTRIBUTION BY SELLING UNITHOLDERS

Distribution of any common units to be offered by one or more of the
selling unitholders may be effected from time to time in one or more
transactions (which may involve block transactions) (1) on the New York Stock
Exchange, (2) in the over-the-counter market, (3) in underwritten transactions;
(4) in transactions otherwise than on the New York Stock Exchange or in the
over-the-counter market or (5) in a combination of any of these transactions.
The transactions may be effected by the selling unitholders at market prices
prevailing at the time of sale, at prices related to the prevailing market
prices, at negotiated prices or at fixed prices. The selling unitholders may
offer their shares through underwriters, brokers, dealers or agents, who may
receive compensation in the form of underwriting discounts, commissions or
concessions from the selling unitholders and/or the purchasers of the shares for
whom they act as agent. The selling unitholders may engage in short sales, short
sales against the box, puts and calls and other transactions in our securities,
or derivatives thereof, and may sell and deliver their common units in
connection therewith. In addition, the selling unitholders may from time to time
sell their common units in transactions permitted by Rule 144 under the
Securities Act.

As of the date of this prospectus, we have not engaged any underwriter,
broker, dealer or agent in connection with the distribution of common units
pursuant to this prospectus by the selling unitholders. To the extent required,
the number of common units to be sold, the purchase price, the name of any
applicable agent, broker, dealer or underwriter and any applicable commissions
with respect to a particular offer will be set forth in the applicable
prospectus supplement. The aggregate net proceeds to the selling unitholders
from the sale of their common units offered hereby will be the sale price of
those shares, less any commissions, if any, and other expenses of issuance and
distribution not borne by us.

The selling unitholders and any brokers, dealers, agents or underwriters
that participate with the selling unitholders in the distribution of shares may
be deemed to be "underwriters" within the meaning of the Securities Act, in
which event any discounts, concessions and commissions received by such brokers,
dealers, agents or underwriters and any profit on the resale of the shares
purchased by them may be deemed to be underwriting discounts and commissions
under the Securities Act.

The applicable prospectus supplement will set forth the extent to which we
will have agreed to bear fees and expenses of the selling unitholders in
connection with the registration of the common units being offered hereby by
them. We may, if so indicated in the applicable prospectus supplement, agree to
indemnify selling unitholders against certain civil liabilities, including
liabilities under the Securities Act.

LEGAL MATTERS

Vinson & Elkins L.L.P., our counsel, will issue an opinion for us about the
legality of the common units and debt securities and the material federal income
tax considerations regarding the common units. Any underwriter will be advised
about other issues relating to any offering by their own legal counsel.

EXPERTS

The consolidated financial statements and the related consolidated
financial statement schedules incorporated in this prospectus by reference from
Enterprise Products Partners L.P.'s and Enterprise Products Operating L.P.'s
respective Annual Reports on Form 10-K for the years ended December 31, 2000 and
1999 have been audited by Deloitte & Touche LLP, independent auditors, as stated
in their reports, which are incorporated herein by reference, and have been so
incorporated in reliance upon the reports of such firm given upon their
authority as experts in accounting and auditing.

9,800,000 COMMON UNITS
REPRESENTING LIMITED PARTNER INTERESTS

[ENTERPRISE PRODUCTS PARTNERS L.P. LOGO]

ENTERPRISE PRODUCTS PARTNERS L.P.

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

PROSPECTUS SUPPLEMENT
OCTOBER 2, 2002
----------------------------

LEHMAN BROTHERS

GOLDMAN, SACHS & CO.

UBS WARBURG

RBC CAPITAL MARKETS

WACHOVIA SECURITIES

MCDONALD INVESTMENTS INC.

RAYMOND JAMES

SANDERS MORRIS HARRIS