UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                              Washington, DC 20549
                                   -----------

                                    FORM 10-K
                                   -----------

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

For the fiscal year ended December 31, 2000  Commission filenumber: 333-93239-01


                       Enterprise Products Operating L.P.
             (Exact name of registrant as specified in its charter)


           Delaware                                     76-0568220
(State or other Jurisdiction of             (I.R.S. Employer Identification No.)
Incorporation or Organization)

                 2727 North Loop West, Houston, Texas 77008-1037
               (Address of principal executive offices) (zip code)
       Registrant's telephone number, including area code: (713) 880-6500

           Securities registered pursuant to Section 12(b) of the Act:
                                      None

           Securities registered pursuant to Section 12(g) of the Act:
                                      None

         Indicate  by check  mark  whether  the  registrant:  (1) has  filed all
reports  required to be filed by Section 13 or 15(d) of the Securities  Exchange
Act of 1934 during the preceding 12 months (or for such shorter  period that the
registrant was required to file such reports),  and (2) has been subject to such
filing requirements for the past 90 days.

                                  Yes X No ___

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

         No common equity securities of Enterprise  Products Operating L.P. (the
"Company")  are held by  non-affiliates  of the  Company.  The  Company is owned
98.9899% by its Parent,  Enterprise  Products  Partners L.P. (a  publicly-traded
master limited  partnership  under the New York Stock Exchange  ("NYSE")  symbol
"EPD" (SEC File No.  1-14323),  and 1.0101% by its General  Partner,  Enterprise
Products GP, LLC.






<PAGE>
                       ENTERPRISE PRODUCTS OPERATING L.P.
                                TABLE OF CONTENTS

<TABLE>
<CAPTION>
                                                                                        Page No.
                                     PART I
<S>                                                                                     <C>
Glossary                                                                                ii

Items 1 and 2.    Business and Properties.                                              1

Item 3.           Legal Proceedings.                                                    24

Item 4.           Submission of Matters to a Vote of Security Holders.                  24

                                     PART II

Item 5.           Market for Registrant's Common Equity
                  and Related Partnership Matters.                                      25

Item 6.           Selected Financial Data.                                              25

Item 7.           Management's Discussion and Analysis of Financial
                  Condition and Results of Operation.                                   26


Item 7A.          Quantitative and Qualitative Disclosures about Market Risk.           42


Item 8.           Financial Statements and Supplementary Data.                          44


Item 9.           Changes in and disagreements with Accountants on Accounting
                  and Financial Disclosure.                                             44

                                    PART III

Item 10.          Directors and Executive Officers of the Registrant.                   45

Item 11.          Executive Compensation.                                               48

Item 12.          Security Ownership of Certain Beneficial Owners
                  and Management.                                                       49

Item 13.          Certain Relationships and Related Transactions.                       50

                                     PART IV

Item 14.          Exhibits, Financial Statement Schedules, and Reports on Form 8-K.     52
</TABLE>



                                       i
<PAGE>

                                    Glossary

         The following  abbreviations,  acronyms or terms used in this Form 10-K
are defined below:

Acadian                    Acadian Gas, LLC
Aristech                   Aristech Chemical Corporation and affiliates
Basell                     Basell polyolefins and affiliates (formerly Montell)
Bcfd                       Billion cubic feet per day
BEF                        Belvieu Environmental Fuels, a joint venture of EPOLP
Belle Rose                 Belle Rose NGL Pipeline LLC, a joint venture of EPOLP
BP                         BP Amoco PLC and affiliates
BPD                        Barrels per day
BRF                        Baton Rouge Fractionators LLC, a joint venture of
                           EPOLP
BRPC                       Baton Rouge Propylene Concentrator, LLC, a joint
                           venture of EPOLP
Btu                        British thermal units
Burlington Resources       Burlington Resources Inc. and affiliates
CERCLA                     Comprehensive Environmental Response, Compensation
                           and Liability Act
Company                    Enterprise Products Operating L.P. and subsidiaries
Conoco                     Conoco, Inc. and affiliates
Coral Energy               Coral Energy LLC, an affiliate of Shell
DIB                        Deisobutanizer
Dixie                      Dixie Pipeline Company, a joint venture of EPOLP
Duke Energy                Duke Energy Corporation and affiliates
Dynegy                     Dynegy Inc. and affiliates
EBITDA                     Earnings before Interest, Taxes, Depreciation and
                           Amortization
Energy Policy Act          Energy Policy Act of 1992
Enron                      Enron Corp. and affiliates
EPA                        United States Environmental Protection Agency
EPCO                       Enterprise Products Company, an affiliate of the
                           Company
EPE                        El Paso Energy Partners L.P. and affiliates
EPIK                       EPIK Terminalling L.P. and EPIK Gas Liquids, LLC,
                           collectively, a joint venture of
                           EPOLP
EPOLP                      Enterprise Products Operating L.P.
EPPLP                      Enterprise Products Partners L.P. (the "Limited
                           Partner"), the parent of the Company
Equistar                   A joint venture of Lyondell Chemical Company,
                           Millenium Chemicals, Inc. and
                           Occidental Petroleum Corporation
ETBE                       Ethyl Tertiary Butyl Ether
ExxonMobil                 ExxonMobil Corporation and affiliates
FERC                       Federal Energy Regulatory Commission
General Partner            Enterprise Products GP, LLC, the general partner of
                           the Company and EPPLP
HLPSA                      Hazardous Liquid Pipeline Safety Act
Huntsman                   Huntsman Corporation and affiliates
ICA                        Interstate Commerce Act
Kinder Morgan              Kinder Morgan Operating LP "A"
Koch                       Koch Industries Inc. and affiliates
Lakehead                   Lakehead Pipe Line Company
LIBOR                      London Interbank Offering Rate
Limited Partner            Enterprise Products Partners L.P.
Manta Ray                  Manta Ray Offshore Gathering Company, L.L.C.
MBA                        Mont Belvieu Associates
MBA acquisition            Refers to the acquisition of an additional interest
                           in the Mont Belvieu NGL fractionation facility from
                           Kinder Morgan and EPCO effective July 1, 1999
MBFC                       Mississippi Business Finance Corporation
MBPD                       Thousand barrels per day
Mitchell                   Mitchell Energy and Development Corp. and affiliates
MMBbls                     Millions of barrels


                                       ii
<PAGE>

Moray                      Moray Pipeline Company, LLC
MTBE                       Methyl tertiary butyl ether
Nautilus                   Nautilus Pipeline Company, L.L.C.
Nemo                       Nemo Gathering Company, L.L.C.
NGL or NGLs                Natural gas liquid(s)
NPDES                      National Pollutant Discharge Elimination System
NYSE                       New York Stock Exchange
OSHA                       Occupational Safety and Health Act
Phillips                   Phillips Petroleum Company and affiliates
Promix                     K/D/S Promix LLC, a joint venture of EPOLP
PTR                        Plant thermal reduction
PURPA                      Public Utility Regulatory Policy Act of 1978
RCRA                       Federal Resource Conservation and Recovery Act
Sailfish                   Sailfish Pipeline Company, LLC
SEP                        Shell Exploration and Production Company
SFAS                       Statement of Financial Accounting Standards
SG&A                       Selling, general and administrative costs
Shell                      Shell Oil Company, its subsidiaries and affiliates
Stingray                   Stingray Pipeline Company, LLC
Sun                        Sunoco, Inc. and affiliates
TAME                       Tertiary Amyl Methyl Ether
Tejas Energy               Tejas Energy, LLC, an affiliate of Shell
Texaco                     Texaco Inc. and affiliates
TNGL                       Tejas Natural Gas Liquids, LLC, a subsidiary of
                           Tejas Energy
TNGL acquisition           Refers to the acquisition of TNGL from Shell
                           effective August 1, 1999
Tri-States                 Tri-States NGL Pipeline LLC, a joint venture of EPOLP
Ultramar Diamond           Ultramar Diamond Shamrock and affiliates
Units                      Ownership interests in the Limited Partner (can refer
                           to Common Units, Subordinated Units or Special Units
                           or a combination thereof)
Valero                     Valero Energy Corporation and affiliates
VESCO                      Venice Energy Services Company, LLC, a joint venture
                           of EPOLP
West Cameron               West Cameron Dehydration, LLC
Williams                   Williams Companies, Inc. and affiliates
Wilprise                   Wilprise Pipeline Company, LLC, a joint venture of
                           EPOLP

1998 Trust                 Enterprise Products 1998 Unit Option Plan Trust, an
                           affiliate of EPCO
1999 Trust                 EPOLP 1999 Grantor Trust, a wholly-owned subsidiary
                           of EPOLP
2000 Trust                 Enterprise Products 2000 Rabbi Trust, an affiliate of
                           EPCO


















                                      iii
<PAGE>
                                     PART I

Items 1 and 2.  Business and Properties.

                                     Summary

         The Company is a leading  integrated North American provider of natural
gas  processing  and  natural  gas  liquids  ("NGL"  or  "NGLs")  fractionation,
transportation  and storage  services to producers of NGLs and  consumers of NGL
products.  The  Company  was  formed  on April  9,  1998 as a  Delaware  limited
partnership  to  acquire,  own and  operate  the  natural  gas  liquids  ("NGL")
processing and distribution assets of Enterprise Products Company ("EPCO").  The
Company  conducts  substantially  all of the  business of its  limited  partner,
Enterprise Products Partners L.P. (the "Limited  Partner"),  which owns 98.9899%
of the Company's  equity  interests.  Enterprise  Products GP, LLC (the "General
Partner") is the  Company's  general  partner and owns 1.0101% of the  Company's
equity  interests.  Both  the  Limited  Partner  and  the  General  Partner  are
subsidiaries of EPCO. The principal  executive  office of the Company is located
at 2727 North Loop West, Houston, Texas, 77008-1038, and the telephone number of
that office is 713-880-6500.

         The  Company  (i)  processes   natural  gas  into  a  merchantable  and
transportable  form of energy  that meets  industry  quality  specifications  by
removing NGLs and impurities;  (ii) fractionates for a processing fee mixed NGLs
produced as by-products of oil and natural gas production  into their  component
products: ethane, propane,  isobutane, normal butane and natural gasoline; (iii)
converts normal butane to isobutane through the process of  isomerization;  (iv)
produces MTBE from  isobutane and methanol;  and (v)  transports NGL products to
end users by pipeline  and  railcar.  The  Company  also  separates  high purity
propylene from refinery-sourced propane/propylene mix and transports high purity
propylene  to plastics  manufacturers  by  pipeline.  Products  processed by the
Company generally are used as feedstocks in petrochemical manufacturing,  in the
production of motor gasoline and as fuel for residential and commercial heating.
Beginning in the first  quarter of 2001,  the Company will enter the natural gas
pipeline business (see "Acquisitions" on page 2 of this Form 10-K).

         The Company's NGL operations are concentrated in the Texas,  Louisiana,
and  Mississippi  Gulf  Coast  area.  A large  portion is  concentrated  in Mont
Belvieu, Texas, which is the hub of the domestic NGL industry and is adjacent to
the largest  concentration of refineries and petrochemical  plants in the United
States. The facilities the Company operates at Mont Belvieu include:  (a) one of
the  largest  NGL  fractionation  facilities  in the  United  States  with a net
processing capacity of 131 MBPD; (b) the largest commercial butane isomerization
complex in the United States with a potential  isobutane  production capacity of
116 MBPD; (c) a MTBE  production  facility with a net  production  capacity of 5
MBPD;  and (d) two  propylene  fractionation  units with a  combined  production
capacity  of 31 MBPD.  The  Company  owns all of the assets at its Mont  Belvieu
facility  except  for  the  NGL  fractionation  facility,  in  which  it owns an
effective 62.5% interest; one of the propylene  fractionation units, in which it
owns a 54.6%  interest and controls the remaining  interest  through a long-term
lease; the MTBE production facility, in which it owns a 33.3% interest;  and one
of its three  isomerization  units and one  deisobutanizer  which are held under
long-term leases with purchase options.

          The Company's  operations in Louisiana and Mississippi include varying
interests in twelve  natural gas processing  plants with a combined  capacity of
11.6 Bcfd and net capacity of 3.2 Bcfd, six NGL fractionation  facilities with a
combined  net  processing  capacity  of 159 MBPD and a  propylene  fractionation
facility with a net capacity of 7 MBPD.

         The Company  owns,  operates or has an interest in  approximately  65.0
million barrels of gross storage capacity (44.3 million barrels of net capacity)
in Texas,  Louisiana and Mississippi that are an integral part of its processing
operations.  The Company also leases and operates one of only two commercial NGL
import/export  terminals  on the  Gulf  Coast.  In  addition,  the  Company  has
operating  and  non-operating  ownership  interests  in over 2,900  miles of NGL
pipelines.

         The Company's  operating  margins are derived from services provided to
its tolling  customers  and from  merchant  activities.  In the  Company's  toll
processing operations,  it does not take title to the product and is simply paid
a fee based on volumes processed,  transported, stored or handled. The Company's
profitability  from toll processing  operations depends primarily on the volumes


                                       1
<PAGE>

of natural gas, NGLs and  refinery-sourced  propane/propylene  mix processed and
transported  and the level of associated  fees charged to its customers.  In the
Company's  isobutane  merchant  activities and to a certain extent its propylene
fractionation business, it takes title to feedstock products and sells processed
end products.  The Company's  profitability  from these  merchant  activities is
dependent  on the prices of  feedstocks  and end  products,  which may vary on a
seasonal basis. In the Company's propylene  fractionation business and isobutane
merchant business,  the Company generally attempts to match the timing and price
of its  feedstock  purchases  with those of the sales of end  products  so as to
reduce  exposure to fluctuations in commodity  prices.  The Company's  operating
margins from its natural gas processing  business are generally derived from the
margins  earned on the sale of purity NGL  products  extracted  from natural gas
streams.  To the extent it takes title to the NGLs  removed from the natural gas
stream and  reimburses  the producer for the reduction in the Btu content and/or
the natural gas used as fuel (the "PTR" or "shrinkage"),  the Company's  margins
are affected by the prices of NGLs and natural  gas. The Company uses  financial
instruments  to reduce  its  exposure  to the  change in the  prices of NGLs and
natural gas.

         Uncertainty of Forward-Looking Statements and Information.  This annual
report on Form 10-K contains various forward-looking  statements and information
that are based on the belief of the Company and the General Partner,  as well as
assumptions made by and information  currently  available to the Company and the
General  Partner.  When  used  in this  document,  words  such as  "anticipate,"
"estimate,"   "project,"   "expect,"  "plan,"  "forecast,"   "intend,"  "could,"
"believe," "would," "may" and similar  expressions and statements  regarding the
plans and  objectives  of the Company  for future  operations,  are  intended to
identify  forward-looking  statements.  Although  the  Company  and the  General
Partner  believe  that  the  expectations   reflected  in  such  forward-looking
statements are  reasonable,  they can give no assurance  that such  expectations
will  prove to be  correct.  Such  statements  are  subject  to  certain  risks,
uncertainties,  and assumptions.  If one or more of these risks or uncertainties
materialize,  or if underlying  assumptions prove 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 the
Company's  results of operations and financial  condition  are: (a)  competitive
practices in the industries in which the Company  competes,  (b) fluctuations in
oil, natural gas, and NGL product prices and production due to weather and other
natural and market forces,  (c) operational and systems risks, (d) environmental
liabilities  that are not covered by indemnity or  insurance,  (e) the impact of
current and future laws and governmental  regulations  (including  environmental
regulations) affecting the NGL industry in general, and the Company's operations
in particular,  (f) loss of a significant customer,  and (g) failure to complete
one or more new projects on time or within budget.

         In addition,  the Company's  expectations  regarding its future capital
expenditures  as described in  "Liquidity  and Capital  Resources"  are only its
forecasts  regarding  these  matters.   These  forecasts  may  be  substantially
different  from  actual  results due to the factors  described  in the  previous
paragraph as well as uncertainties related to the following: (a) the accuracy of
the Company's estimates regarding its spending requirements,  (b) the occurrence
of any  unanticipated  acquisition  opportunities,  (c) the need to replace  any
unanticipated  losses in capital assets, (d) changes in the strategic  direction
of  the  Company  and  (e)  unanticipated  legal,   regulatory  and  contractual
impediments with regards to its construction projects.

                                  Acquisitions

         Effective  August 1, 1999,  the Company  acquired  TNGL from Shell,  in
exchange  for  14.5  million  non-distribution   bearing,   convertible  special
partnership  Units of the Limited  Partner  and $166  million in cash (the "TNGL
acquisition").  The  Limited  Partner  also  agreed  to issue up to 6.0  million
additional  non-distribution  bearing special  partnership Units to Shell in the
future if the volumes of natural gas that the Company  processes for Shell reach
agreed upon levels in 2000 and 2001.  The first 3.0 million of these  additional
special partnership Units were issued on August 1, 2000. The businesses acquired
from Shell include natural gas processing and NGL fractionation,  transportation
and  storage in  Louisiana  and  Mississippi  and its NGL  supply  and  merchant
business.  The assets acquired  include varying  interests in eleven natural gas
processing  plants,  four  NGL  fractionation   facilities,   four  NGL  storage
facilities, operator and non-operator ownership interests in approximately 1,500
miles of NGL  pipelines  and a 20-year  natural gas  processing  agreement  with
Shell.





                                       2
<PAGE>

         The Company has recently  announced and/or completed the acquisition of
three Louisiana-based natural gas pipeline systems:

     -    Acadian Gas, LLC ("Acadian") for $226 million;
     -    Stingray   Pipeline   Company,   LLC  ("Stingray")  and  West  Cameron
          Dehydration, LLC ("West Cameron") for approximately $25.1 million; and
     -    Sailfish  Pipeline  Company,   LLC  ("Sailfish")  and  Moray  Pipeline
          Company, LLC ("Moray") for approximately $88.1 million.

The Company has executed a definitive  agreement with the seller of Acadian with
closing  expected in the first  quarter of 2001.  The  Stingray,  West  Cameron,
Sailfish and Moray  acquisitions  closed on January 29, 2001. The acquisition of
these natural gas pipeline  systems  represents a strategic  investment  for the
Company  and allows for entry into the natural  gas  gathering,  transportation,
marketing  and storage  business.  Management  believes  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
extend the Company's  midstream energy service  relationship  with long-term NGL
customers  (producers,   petrochemical   suppliers  and  refineries)  and  offer
additional  fee-based  cash flows and  opportunities  for  enhanced  services to
customers.  For additional  information  regarding these 2001 acquisitions,  see
page 12 of this Form 10-K.

         The Company  will  continue to analyze  potential  acquisitions,  joint
ventures or similar  transactions  with businesses that operate in complementary
markets and  geographic  regions.  In recent years,  major oil and gas companies
have sold  non-strategic  assets including  assets in the midstream  natural gas
industry in which the Company operates. Management believes that this trend will
continue,  and the Company expects  independent oil and natural gas companies to
consider similar options.

                            The Company's Operations

         The Company's  operations are segregated into five reportable  business
segments:

     -    Fractionation
     -    Pipeline
     -    Processing
     -    Octane Enhancement
     -    Other

         The Fractionation segment is primarily comprised of the following three
business areas: NGL  Fractionation,  Isomerization and Propylene  Fractionation.
The Fractionation  segment also includes the Company's equity method investments
in BRF,  BRPC and  Promix.  In  addition,  this  segment  includes  the  support
facilities for the NGL Fractionation,  Isomerization and Propylene Fractionation
facilities  and  other  miscellaneous  minor  plants.   Pipelines  includes  the
Company's  pipeline  systems,  storage  facilities  and the Houston Ship Channel
Import/Export  terminal. The Pipeline segment also includes the Company's equity
method  investments in EPIK,  Wilprise,  Tri-States,  Belle Rose and Dixie.  The
Processing segment consists of the Company's natural gas processing business and
related merchant  activities.  Octane  Enhancement is comprised of the Company's
equity  interest in BEF which owns and operates a facility that  produces  motor
gasoline  additives to enhance  octane  (currently  producing  MTBE).  The Other
segment  is  primarily  comprised  of  fee-based  marketing  services  and other
operational support activities including engineering and plant-based information
technology functions.

         See  Note 13 of the  Notes to  Consolidated  Financial  Statements  for
additional  segment  information  including  revenues from  external  customers,
segment profit and loss and segment assets.










                                       3
<PAGE>

Fractionation

NGL Fractionation

         The  Company's   NGL   Fractionation   operations   include  seven  NGL
fractionators  with a combined  gross  processing  capacity  of 558 MBPD and net
processing  capacity of 290 MBPD. A summary of the Company's  NGL  fractionation
facilities at December 31, 2000 is as follows:

      NGL                             Gross                          Net
 Fractionation                       Capacity       Ownership     Capacity
    Facility         Location         (MBPD)        Interest       (MBPD)
-----------------  --------------  -------------  -------------- ------------
Mont Belvieu       Texas               210                62.5%      131
Norco              Louisiana            70               100.0%       70
BRF                Louisiana            60                32.2%       19
Promix             Louisiana           145                33.3%       48
Tebone             Louisiana            30                33.4%       10
Venice             Louisiana            36                13.1%        5
Petal              Mississippi           7               100.0%        7
                                   -------------                 ------------
                   Total               558                           290
                                   =============                 ============

         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 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 and in the  production of MTBE, an  oxygenation  additive used in
cleaner burning motor gasoline, 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  in 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 motor
gasoline blend stock or petrochemical feedstock.

         The three  principal  sources of mixed NGLs  fractionated in the United
States  are  (i)  domestic  gas  processing  plants,  (ii)  domestic  crude  oil
refineries  and (iii) 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 in the field, mixed NGLs are transported
to  a  centralized  facility  for  fractionation.  Mixed  NGL  recovery  by  gas
processing  plants  represents the most  important  source of throughput for the
Company's NGL fractionators and is generally governed by the degree to which NGL
prices  exceed  the cost  (principally  that of  natural  gas as a raw  material
feedstock and as a fuel) of separating the mixed NGLs from the purified  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 gained in
fractionation,  mixed NGL  recovery  levels by these  facilities  (and hence NGL
fractionation  volumes)  may  be  reduced.  For a  complete  discussion  of  the
Company's gas plants, see Processing on page 14 of this Form 10-K. 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 the Company.  The mixed NGLs  delivered  from  domestic gas  processing
plants and domestic  crude oil  refineries to the  Company's  NGL  fractionation
facilities  are typically  transported by NGL pipelines and, to a lesser extent,
by railcar and truck.  The Company takes  delivery of mixed NGL imports  through
its Houston ship channel NGL  import/export  facility which is connected to Mont
Belvieu via pipeline.

         In general,  the Company's NGL fractionation  business  processes mixed
NGL streams for a toll  processing fee charged to its  third-party  and merchant
business  customers.  Overall,  results of  operations of this business area are
dependent  upon  the  volume  of  mixed  NGLs  processed  and the  level of toll


                                       4
<PAGE>

processing  fees  charged  to  customers  and  exhibit  little  to  no  seasonal
variation.  NGL fractionation toll processing  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 in NGL
fractionation.  The NGL fractionation revenues earned from the Company's related
merchant  business  are based  primarily  on the mixed NGL volumes  flowing from
Company  and  affiliate-owned  gas  processing  plants.  Lastly,  NGL  producers
generally  retain  title to, and the  pricing  risks  associated  with,  the NGL
products.

         Management  believes that sufficient volumes of mixed NGLs,  especially
those  originating  from the Company's  and/or its  affiliate's  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.  In addition,  significant  volumes of mixed NGLs are  contractually
committed to the Company's facilities by third-party customers.

         NGL Fractionation Facilities

         During 2000, the Company's NGL fractionation facilities processed mixed
NGLs at an average  rate of 213 MBPD or 73% of  capacity,  both amounts on a net
basis. The table below shows net processing  volumes and capacity (both in MBPD)
and  the   corresponding   overall   utilization  rates  of  the  Company's  NGL
fractionation facilities for the last three years:

       NGL Fractionation                  For Year Ended December 31,
            Facility                  2000           1999            1998
-------------------------------------------------------------------------------
Mont Belvieu (a)                      106             78             71
Norco                                  47             48              -
BRF                                    15             13              -
Promix                                 34             30              -
Other (b)                              11             15              2
                                 ----------------------------------------------
  Total Processing Volume             213            184             73
Net Capacity (c)                      290            264             86
Utilization                           73%            70%            85%

-------------------------------------------------------------------------------
(a)      Net volumes increased in 1999 and 2000 due to increased ownership of
         facilities resulting from the MBA acquisition in July 1999
(b)      Includes Venice, Tebone and Petal NGL fractionation facilities
(c)      Capacities have been adjusted for acquisitions

          Mont Belvieu NGL Fractionation  facility.  The Company operates one of
the  largest  NGL  fractionation  facilities  in the United  States with a gross
processing capacity of 210 MBPD at Mont Belvieu,  Texas  (approximately 25 miles
east of Houston).  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.  The Company owns an  effective  62.5%  interest in the NGL  fractionation
facilities at the Mont Belvieu complex.

         At the Mont  Belvieu  NGL  fractionation  facilities,  the  Company has
long-term  fractionation  agreements with Burlington Resources,  Texaco and Duke
Energy  each of which is a  significant  producer  of NGLs and a co-owner of the
Mont Belvieu NGL fractionation  facility.  Burlington  Resources and Texaco have
agreed  to  deliver  either a minimum  of 39 MBPD of mixed  NGLs or all of their
mixed NGLs brought within 50 miles of the Mont Belvieu facility. Duke Energy has
agreed to deliver 26 MBPD of mixed  NGLs to Mont  Belvieu as well as  additional
barrels that exceed its commitments to other NGL fractionation  facilities.  The
Company  generally  enters  into  contracts  that  cover  most of the  remaining
capacity  at the  Mont  Belvieu  facilities  for one to  three-year  terms  with
customers that are producers and/or consumers of NGLs.



                                       5
<PAGE>

         In January  2001,  the Company  entered  into a five-year  agreement to
exchange  NGLs  produced  at the Sea  Robin  natural  gas  processing  plant for
finished NGL products at the Company's  Mont Belvieu  complex.  The NGLs will be
exchanged via the Company's recently completed Lou-Tex NGL Pipeline (see page 11
for  information  regarding this pipeline).  As a result of this agreement,  the
Company will utilize its Mont Belvieu NGL fractionation  facility to process the
mixed NGLs received from the Sea Robin plant into finished NGL products. Initial
net  processing  volumes  are  expected  to be 10 MBPD  and are  anticipated  to
increase to over 13 MBPD by the end of 2001.

         Norco NGL Fractionation  facility.  The Company owns and operates a NGL
fractionation  facility at Norco,  Louisiana.  The Norco facility receives mixed
NGLs via pipeline from the Yscloskey,  Toca, Paradis and Crawfish gas processing
plants and has an average processing capacity of 70 MBPD.

         BRF NGL  Fractionation  facility.  The Company operates and has a 32.2%
interest  in BRF which owns a 60 MBPD NGL  fractionation  facility  and  related
transportation  assets  located  near Baton Rouge,  Louisiana.  The BRF facility
processes mixed NGLs received from BP, ExxonMobil and Williams,  all of whom are
partners with the Company in BRF, through  long-term  fractionation  agreements.
The mixed NGLs provided by the partners originate from Alabama,  Mississippi and
southern Louisiana including offshore Gulf of Mexico areas.

         Promix NGL Fractionation facility. The Company operates and has a 33.3%
interest in Promix which owns a 145 MBPD NGL fractionation facility located near
Napoleonville,  Louisiana.  The  Promix  assets  include  a  315-mile  mixed NGL
gathering system connected to nine gas processing plants, five salt dome storage
wells which handle mixed NGLs,  propane,  isobutane,  normal  butane and natural
gasoline  and a barge  loading  facility.  Promix  receives  mixed NGLs from gas
processing plants located in southern Louisiana.

         Tebone NGL Fractionation facility. The Company operates and has a 33.4%
interest  in  a  captive  NGL  fractionation   facility  located  near  Geismar,
Louisiana. This facility serves the Company's gas processing facilities in North
Terrebonne, Louisiana and has a gross processing capacity of 30 MBPD.

         Venice NGL Fractionation  facility. The Company has a 13.1% interest in
VESCO  which  owns a captive 36 MBPD NGL  fractionation  facility  located  near
Venice,  Louisiana.  This  facility  serves  VESCO's gas  processing  operations
located in southern Louisiana and is operated by Dynegy.

         Petal NGL Fractionation  facility.  The Company owns and operates a NGL
fractionation  facility at Petal,  Mississippi  with a processing  capacity of 7
MBPD. The Petal plant is connected to the Company's  Chunchula  pipeline  system
and serves NGL producers in Mississippi, Alabama and Florida.























                                       6
<PAGE>

Isomerization

         The Company's  isomerization  facilities  include three butamer reactor
units and eight  associated  DIBs located in Mont Belvieu,  Texas which comprise
the largest commercial isomerization complex in the United States. The Company's
facilities have an average combined potential production capacity of 116 MBPD of
isobutane and account for more than 70% of the commercial  isobutane  production
capacity in the United  States.  The Company owns the  isomerization  facilities
with the exception of one of the butamer reactor units, which it holds through a
long-term lease.  The facilities are operated by the Company.  During the second
quarter of 2000, the Company  refurbished  one of its butamer  reactors that had
been shut down since July 1999  resulting  in improved  operational  flexibility
during periods of excess demand. This unit,  accounting for 36 MBPD of capacity,
was active only during the second  quarter of 2000.  The  following  table shows
isobutane production and capacity (both in MBPD) and overall utilization for the
last three years:

                           For Year Ended December 31,
     Mont Belvieu Facility            2000           1999            1998
-------------------------------------------------------------------------------
Production                             74             74              67
Capacity (a)                           86             98             116
Utilization                           86%            76%             58%

-------------------------------------------------------------------------------
(a) The  1999  capacity  figure  reflects  Isom II (36 MBPD of  capacity)  being
shutdown for the last half of the year.  The 2000 capacity has been adjusted for
the two  months  that Isom II ran during  the early  summer  and its  subsequent
placement into standby status thereafter.

         Commercial isomerization units convert normal butane into mixed butane,
which is subsequently  fractionated into isobutane and normal butane. The demand
for commercial  isomerization services depends upon the industry's  requirements
for (i) isobutane in excess of naturally  occurring  isobutane produced from NGL
fractionation and refinery operations and (ii) high purity isobutane.  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  operations  of this  business  area  are  generally
dependent upon the volume of normal and mixed butanes processed and the level of
processing  fees charged to customers.  The principal  uses of isobutane are for
alkylation and in the production of MTBE and propylene oxide.

         The Company uses its isomerization  facilities to convert normal butane
into  isobutane  for its toll  processing  customers,  including  its  isobutane
merchant business.  The Company's largest third-party toll processing  customers
operate  under  long-term  contracts  under  which  they  supply  normal  butane
feedstock  and pay the  Company a toll  processing  fee  based on the  volume of
isobutane  produced.  The  largest  of these  customers  in 2000 were  Lyondell,
Huntsman,  Sun and  Mitchell.  Sun and  Mitchell  use the high purity  isobutane
produced  for them to meet their  feedstock  obligations  as partners in the BEF
MTBE  facility.  The Company  also meets its  obligation  to provide high purity
isobutane   feedstock  to  the  BEF  MTBE  facility  with  production  from  the
isomerization   units.  During  2000,  59  MBPD  of  isobutane   production  was
attributable to third-party toll processing customers.

         The balance of isobutane production during 2000, or 15 MBPD, relates to
merchant activities  associated with isobutane sales contracts.  In general, the
merchant  business  (which  is  part  of  the  Processing   segment)  meets  the
requirements of its isobutane sales contracts by either purchasing  isobutane in
the spot market or paying the  isomerization  business  to process  Company-held
inventories  of normal and/or mixed  butanes.  The  isomerization  business area
collects a toll processing fee from the merchant business based on the volume of
normal and mixed butanes processed.  The normal and mixed butane inventories are
primarily  derived from  imports and NGL  fractionation  operations.  Management
believes  that it will have  access to  sufficient  volumes  of normal and mixed
butanes in the  foreseeable  future to meet the needs of its isobutane  merchant
activities.  For a further discussion of the Company's merchant activities,  see
Processing on page 14 of this Form 10-K.








                                       7
<PAGE>

Propylene Fractionation

         The Company's propylene  fractionation business consists of two polymer
grade propylene facilities (Splitters I and II) and one chemical grade propylene
plant  (BRPC)  with a combined  gross  production  capacity of 54 MBPD and a net
capacity of 38 MBPD. The following table summarizes the propylene  fractionation
business assets at December 31, 2000:

<TABLE>
<CAPTION>
                                             Gross                             Net
      Propylene                            Capacity        Ownership        Capacity
      Facility             Location         (MBPD)         Interest          (MBPD)
----------------------  ---------------  --------------   ------------    --------------
<S>                                           <C>              <C>             <C>
Splitter I (a)          Texas                 17               100.0%          17
Splitter II             Texas                 14               100.0%          14
BRPC                    Louisiana             23                30.0%           7
                                         --------------                   --------------
                        Total                 54                               38
                                         ==============                   ==============

----------------------------------------------------------------------------------------
</TABLE>

(a) The Company owns 54.6% with Basell owning the remaining  45.4%.  The Company
leases Basell's interest.

         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 is derived by processing  either refinery
grade or chemical  grade  propylene  feedstocks.  Approximately  one-half 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 produced either as a by-product of olefin
(ethylene)  plants or from the processing of refinery grade propylene.  Chemical
grade propylene is a basic petrochemical used in plastics,  synthetic fibers and
foams.

         During 2000, the Company's propylene fractionation  facilities produced
at an average rate of 33 MBPD or 94% of  capacity,  both amounts on a net basis.
The table below shows net production volumes and capacity (both in MBPD) and the
corresponding overall utilization rates of the Company's propylene fractionation
facilities for the last three years:

                           For Year Ended December 31,
            Facility                  2000           1999            1998
-------------------------------------------------------------------------------
Splitter I & II                              29              28             26
BRPC                                          4               -              -
                                 ----------------------------------------------
   Total                                     33              28             26
Capacity (a)                                 35              31             31
Utilization                                 94%             90%            84%

-------------------------------------------------------------------------------
(a)  2000 capacity adjusted for start-up of BRPC unit in July 2000

         Splitter  I and II  Propylene  Fractionation  facilities.  The  Company
operates two polymer grade propylene  fractionation  facilities at Mont Belvieu,
Texas with a gross capacity of 31 MBPD. The Company owns 54.6% of Splitter I and
100.0% of  Splitter  II. The  Company  leases the  remaining  45.4%  interest in
Splitter I from a customer, Basell (formerly Montell).

         Results of operations for the Company's  polymer grade propylene plants
are generally dependent upon (i) long-term toll processing arrangements and (ii)
merchant activities. The Company's largest toll processing customers during 2000
were  Equistar  and  Huntsman.  In  general,  pursuant to  contracts  with these
companies,  the Company is guaranteed  certain  minimum  volumes and paid a toll
processing  fee based on the  throughput  of refinery  grade  propylene  used to
produce polymer grade propylene.  In the Company's  propylene merchant business,
the Company has several long-term polymer grade propylene sales agreements,  the
largest  of which is with  Basell.  The  Basell  agreement  stipulates  that the


                                       8
<PAGE>

Company  will sell a certain  quantity of polymer  grade  propylene to Basell at
market-based prices through 2004. In order to meet its merchant obligations, the
Company has entered into several long-term agreements to purchase refinery grade
propylene.  The Company  reduces the  commodity  price  exposure in the merchant
portion of this business by matching the volumes and pricing mechanisms required
under sales contracts with its supply contracts. During 2000, 12 MBPD of polymer
grade propylene production was associated with toll processing  operations while
17 MBPD was attributable to merchant activities.

         The Company is able to unload barges carrying  refinery grade propylene
through its  import/export  terminal  located on the Houston ship  channel.  The
Company is also able to receive  supplies of refinery  grade  propylene from its
Mont Belvieu  truck and rail  loading  facility  and from  refineries  and other
producers through its pipeline located along the Houston ship channel.  In turn,
polymer grade propylene is shipped to customers by truck or pipeline.  Both toll
processing demand and merchant  requirements are generally  constant  throughout
the year and exhibit little seasonality, except to the extent that either of the
facilities is impacted by downtime  attributable to maintenance  and/or economic
reasons.

         BRPC Propylene  Fractionation facility. The Company operates and owns a
30.0% interest in BRPC which owns a 23 MBPD chemical grade propylene  production
facility  located  near Baton Rouge,  Louisiana.  The unit,  located  across the
Mississippi  River from ExxonMobil's  refinery and chemical plant,  fractionates
refinery grade  propylene  produced by ExxonMobil  into chemical grade propylene
for a toll processing fee.  Results of operations of BRPC are dependent upon the
volume of refinery grade  propylene  throughput and the level of toll processing
fees  charged.   Due  to  the  relatively   consistent  flow  of  feedstock  and
fixed-nature of the toll processing fees charged, results of operations for BRPC
exhibit  little  seasonality  (except to the extent that volumes are affected by
downtime  associated  with  maintenance  or other  economic  reasons).  The BRPC
facility  commenced  operations in the third quarter of 2000 and averaged 4 MBPD
(on an net basis) of chemical grade  propylene  production  during the period in
which it was operational.


Pipeline

         The Company's  Pipeline segment  includes its ownership  interests in a
2,942-mile  network of  transportation  and  distribution  pipeline  systems and
related hydrocarbon storage facilities and import/export assets. At December 31,
2000, the Company's major pipeline systems were as follows:

               Major NGL & Petroleum Liquid
                     Pipeline Systems                            Miles
-----------------------------------------------------------  ---------------
Dixie Pipeline                                                  1,301
Louisiana Pipeline System                                         471
Lou-Tex Propylene Pipeline System                                 291
Tri-States, Belle Rose and Wilprise Pipeline Systems              247
Lou-Tex NGL Pipeline System                                       206
Houston Ship Channel Pipeline System                              175
Lake Charles/Bayport Propylene Pipeline System                    134
Chunchula Pipeline System                                         117
                                                             ---------------
              Total Major Pipeline Systems                      2,942
                                                             ===============

         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,
total  pipeline  throughput  averaged 367 MBPD in 2000, 264 MBPD in 1999 and 200
MBPD in 1998 (all amounts on a net basis).




                                       9
<PAGE>

<TABLE>
<CAPTION>
                                                                  For Year Ended December 31,
                        Description                              2000        1999         1998
---------------------------------------------------------------------------------------------------
<S>                                                               <C>         <C>          <C>
Dixie Pipeline                                                    14          14            -
Louisiana Pipeline System                                        115          74           40
Lou-Tex Propylene Pipeline System (a)                             23           -            -
Tri-States, Belle Rose and Wilprise Pipeline Systems              42          41            -
Lou-Tex NGL Pipeline System (b)                                   30           -            -
Houston Ship Channel Pipeline System                             106          99          107
Lake Charles/Bayport Propylene Pipeline System                     5           5            7
Chunchula Pipeline System                                          6           7            5
EPIK Export Facility (c)                                          17          10           10
Houston Ship Channel NGL import facility                           9          14           31
                                                             --------------------------------------
   Total Throughput MBPD                                         367         264          200
                                                             ======================================

---------------------------------------------------------------------------------------------------
</TABLE>
     (a)  Volumes reflect the period in which the Company owned the asset (i.e.,
          March 2000 through December 2000)
     (b)  Pipeline commenced operations in late November 2000
     (c)  2000 volumes higher than 1999 due to  installation  of new NGL product
          chiller unit in the fourth quarter of 1999

         The Company's pipelines transport mixed NGLs and liquid hydrocarbons to
the Company's  NGL  fractionation  plants;  distribute  NGL purity  products and
propylene  to  petrochemical  plants  and  refineries;  and  deliver  propane to
customers   along  the  1,301-mile   Dixie  pipeline.   The  pipelines   provide
transportation  services  to  customers  on a fee  basis.  As such,  results  of
operations  for this business area are  generally  dependent  upon the volume of
product  transported  and the level of fees charged to customers  (which include
the Company's  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 the increased
use of propane for  heating in the  southeastern  United  States.  In  addition,
volumes on the Lou-Tex NGL pipeline  will  generally  increase  during the April
through September period due to gasoline blending considerations.

         The Company's  hydrocarbon  storage  facilities  and NGL  import/export
terminal are  integral  parts of its pipeline  operations.  In general,  storage
wells are used to store mixed NGLs and refinery  grade  propylene that have been
delivered to Company facilities for processing.  Such storage allows the Company
to mix various batches of feedstock and maintain a sufficient  supply and stable
composition of feedstock to its processing facilities. The Company also uses the
wells to store certain  fractionated  products for its  customers  when they are
unable to take immediate  delivery.  The profitability of storage  operations is
primarily  dependent upon the volume of material stored and the level of storage
fees charged to customers.  Some of the Company's processing contracts allow for
a short period of free storage (typically 30 days or less) and impose fees based
on volumes  stored for longer  periods.  Intersegment  revenues for the Pipeline
segment include those fees charged to the Company's various merchant  businesses
for use of the storage  facilities.  The Company owns and operates storage wells
at Mont Belvieu,  Texas with an aggregate  capacity of 21 MMBbls  (including the
recent  purchase of a storage well from  Equistar  mentioned  below under "Major
Pipeline  Acquisitions in 2001"). The Company's Louisiana storage assets consist
of  facilities  located at or near Breaux  Bridge,  Napoleonville,  Sorrento and
Venice  having a gross  capacity of 33 MMBbls and a net capacity of 14.8 MMBbls.
The Company's  Mississippi storage assets are comprised of facilities located at
or near Petal and  Hattiesburg,  Mississippi  with a gross capacity of 12 MMBbls
and a net capacity of 9.5 MMBbls.  Of the  facilities  located in Louisiana  and
Mississippi,  the Company operates those located in Breaux Bridge, Louisiana and
Petal, Mississippi. Koch, Dynegy and Equilon (an affiliate of Shell) operate the
remaining facilities.

         The Company leases and operates a NGL import facility at the Oiltanking
Houston marine  terminal on the Houston ship channel that enables NGL tankers to
be offloaded at their maximum  unloading  rate (10,000  barrels per hour),  thus
minimizing laytime and increasing the number of vessels that can be offloaded. A
methanol  pipeline,  which is part of the Houston Ship Channel  Pipeline System,
extends  from the import  facility to Mont  Belvieu  and enables  methanol to be
delivered by ship or barge and then  transported  to the Company's MTBE facility
at Mont  Belvieu  where it is consumed in the MTBE  process.  In  addition,  the
Company owns a combined 50%  interest in EPIK,  a joint  venture with  Idemitsu,
which owns NGL export assets at the terminal including a NGL product chiller and
related equipment used for loading  refrigerated marine tankers. The NGL product


                                       10
<PAGE>

chiller  speeds the loading of tankers at rates up to 5,000  barrels per hour of
refrigerated  propane and butane, one of the highest loading rates in the United
States. Traditionally, EPIK's export volumes are higher during the winter months
due  to  increased   propane   exports  by  Idemitsu  and  other  parties.   The
profitability of import and export activities depends primarily upon the volumes
unloaded and loaded and the level of fees associated with each activity.

         Major Pipeline Systems

         Dixie  Pipeline.  The Dixie Pipeline is a 1,301-mile  propane  pipeline
which moves propane  supplies from Mont Belvieu,  Texas and Louisiana to markets
in the  southeastern  United  States.  At December 31, 2000, the Company owned a
19.9% interest in Dixie (with 8.4% of its interest  being  purchased from Conoco
for $19.4 million in October 2000).  The other owners of Dixie are BP,  Chevron,
ExxonMobil, Phillips and Texaco with Phillips serving as operator.

         Louisiana  Pipeline System. The Louisiana Pipeline System is a 471-mile
Company-owned network of nine NGL pipelines located in Louisiana. This system is
used to transport propane,  butanes and natural gasoline 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 the Company's gas processing  and other  facilities
located in the Louisiana area. The Company operates 233 miles of the system, and
Equilon operates the remainder.

         Lou-Tex  Propylene  Pipeline  System.  The Lou-Tex  Propylene  Pipeline
System  consists  of a  263-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. The purchase of this system, effective March 1, 2000
from Concha Chemical Pipeline Company (an affiliate of Shell),  was completed at
a cost of  approximately  $100  million.  The Company  owns and  operates  these
assets.

         Tri-States,  Belle Rose and Wilprise Pipeline  Systems.  The Company is
participating  in pipeline joint ventures which supply mixed NGLs to the BRF and
Promix NGL fractionators. They are as follows:

     -    The Company owns a 33.3% interest in Tri-States  which owns a 169-mile
          NGL  pipeline  that  extends  from Mobil Bay,  Alabama to near Kenner,
          Louisiana.  Tri-States is a joint  venture with BP, Duke Energy,  Koch
          and Williams with Williams acting as operator of the assets.
     -    The  Company  operates  and owns a 41.7%  interest in Belle Rose which
          owns a 48-mile NGL pipeline  that extends from near Kenner,  Louisiana
          to the Promix NGL fractionation facility in Napoleonville,  Louisiana.
          Belle Rose is a joint venture with Gulf Coast NGL Pipeline and Koch.
     -    The Company owns a 37.4% interest in Wilprise which owns a 30-mile NGL
          pipeline  that  extends  from  near  Kenner,  Louisiana  to  Sorrento,
          Louisiana.  Wilprise  is a joint  venture  with  Williams  and BP with
          Williams acting as operator of the assets.

         Lou-Tex NGL Pipeline  System.  The Lou-Tex NGL Pipeline System consists
of a recently completed 206-mile NGL pipeline used (i) to provide transportation
services for NGL products and refinery grade propylene between the Louisiana and
Texas markets and (ii) to transport mixed NGLs from the Company's  Louisiana gas
processing   facilities  to  the  Mont  Belvieu  NGL   fractionation   facility.
Construction of this system was completed during the fourth quarter of 2000 at a
cost of approximately $87.9 million. The Company operates and owns the system.

         Houston Ship Channel Pipeline System. The Houston Ship Channel Pipeline
System is a collection of NGL and petrochemical  pipelines aggregating 175 miles
in length used to deliver feedstocks to Company facilities for processing and to
deliver  products  to  petrochemical  plants and  refineries.  This  system also
connects the Company's Mont Belvieu facilities to its NGL import/export terminal
located on the Houston ship channel.  This system extends west from Mont Belvieu
and runs along the Houston  ship channel to Pierce  Junction,  which is south of
Houston,  Texas.  Beginning  in April  2001,  management  anticipates  that this
pipeline  system will be used to  transport  to the  Oiltanking  Houston  marine
terminal approximately 15 MBPD of MTBE production from the BEF facility that had
been  previously  transported  by a  third-party  pipeline  system.  The Company
operates and owns this pipeline system.


                                       11
<PAGE>

         Lake    Charles/Bayport    Propylene    Pipeline   System.   The   Lake
Charles/Bayport  Propylene  Pipeline  System is a  134-mile  propylene  pipeline
system used to distribute  polymer grade propylene from Mont Belvieu to Basell's
polypropylene  plants  in  Lake  Charles,   Louisiana  and  Bayport,  Texas  and
Aristech's  facility in  LaPorte,  Texas.  A segment of the  pipeline is jointly
owned by the Company and Basell,  and another  segment of the pipeline is leased
from ExxonMobil.

         Chunchula  Pipeline System. The Chunchula Pipeline System is a 117-mile
NGL pipeline system extending from the  Alabama-Florida  border to the Company's
storage and NGL  fractionation  facilities near Petal,  Mississippi.  The system
gathers NGLs from  production  areas in Florida and Alabama and delivers them to
the Petal NGL  fractionation  facility  for  processing  or storage  and further
distribution. The Company owns and operates this pipeline.

         Major Pipeline Acquisitions in 2001

         The Company has recently  announced and/or completed the acquisition of
three Louisiana-based natural gas pipeline systems:

     -    Acadian Gas, LLC ("Acadian");
     -    Stingray   Pipeline   Company,   LLC  ("Stingray")  and  West  Cameron
          Dehydration, LLC ("West Cameron"); and
     -    Sailfish  Pipeline  Company,   LLC  ("Sailfish")  and  Moray  Pipeline
          Company, LLC ("Moray").

The  acquisition  of these natural gas pipeline  systems  represents a strategic
investment  for the Company and allows for entry into the natural gas gathering,
transportation,  marketing and storage business.  Management believes 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 extend the Company's  midstream  energy service  relationship  with
long-term NGL customers (producers,  petrochemical suppliers and refineries) and
offer additional fee-based cash flows and opportunities for enhanced services to
customers.

         Acadian.  On September  25,  2000,  the Company  announced  that it had
executed a  definitive  agreement  to purchase  Acadian  from Coral  Energy,  an
affiliate of Shell, for $226 million in cash,  inclusive of working capital. The
acquisition  of Acadian  integrates  its natural gas  pipeline  systems in South
Louisiana  with  the  Company's  Gulf  Coast  natural  gas  processing  and  NGL
fractionation,  pipeline and storage system.  The Acadian  acquisition gives the
Company an extensive  intrastate natural gas pipeline system with access to both
supply and markets; positions the Company to compete for incremental natural gas
supplies from new discoveries onshore, the offshore Louisiana  continental shelf
and Gulf of Mexico  deepwater  developments;  and  enables  the  Company to take
advantage  of  growing  industrial  and  petrochemical   demand  (including  new
gas-fired  power  generation   projects)  along  with  additional   natural  gas
processing opportunities.

         Acadian's  assets  are  comprised  of the  438-mile  Acadian,  577-mile
Cypress and 27-mile Evangeline natural gas pipeline systems, which together have
over 1.0 Bcfd of capacity.  These natural gas pipeline  systems are wholly-owned
by Acadian with the exception of the Evangeline system in which Acadian holds an
approximate  49.5%  interest.  The system  includes a leased natural gas storage
facility at Napoleonville,  Louisiana. Completion of this transaction is subject
to certain conditions,  including regulatory approvals. The purchase is expected
to be completed during the first quarter of 2001.

         Stingray, West Cameron, Sailfish and Moray (collectively,  the "El Paso
acquisition"). On January 29, 2001, the Company completed the purchase of 50% of
the  membership  interests  of Stingray  and West  Cameron,  together  with some
offshore  lateral  pipelines  for  approximately  $25.1  million  in  cash  from
affiliates  of El Paso Energy  Partners  L.P.  ("EPE") and Coastal  Corp.  Shell
purchased  the  remaining  50%  membership  interests of both  Stingray and West
Cameron for an equal amount of cash. In addition, the Company purchased from EPE
100% of the membership  interests of Sailfish and Moray for approximately  $88.1
million in cash.

         Collectively,  the  Company  acquired  interests  in five  natural  gas
gathering  and  transmission  pipeline  systems  in the Gulf of Mexico  totaling
approximately  737 miles of pipeline  with an aggregate  gross  capacity of 2.85
Bcfd. These pipelines and their associated assets are  strategically  located to


                                       12
<PAGE>

serve  continental  shelf and  deepwater  developments  in the  central  Gulf of
Mexico. As with the Acadian  acquisition,  the El Paso acquisition  broadens the
Company's midstream business by providing additional services to customers,  and
it benefits from increased  natural gas production from deepwater Gulf of Mexico
development.  Management  believes that the assets  acquired from EPE complement
and integrate well with those of the Acadian acquisition.

         Stingray owns a 375-mile  FERC-regulated two phase natural gas pipeline
system that transports natural gas and injected condensate from the High Island,
West  Cameron,  East Cameron,  Vermillion  and Garden Banks areas in the Gulf of
Mexico to  onshore  transmission  systems  at Holly  Beach and  Cameron  Parish,
Louisiana.  West Cameron is an unregulated  dehydration  facility located at and
connected  to the onshore  terminal of  Stingray.  Shell is the  operator of the
Stingray and West Cameron facilities.

         Sailfish  owns a  25.67%  interest  in  Manta  Ray  Offshore  Gathering
Company,   L.L.C.   ("Manta  Ray")  and  Nautilus   Pipeline   Company,   L.L.C.
("Nautilus"). Moray owns a 33.92% interest in the Nemo Gathering Company, L.L.C.
("Nemo").  Manta Ray (which is jointly owned by Sailfish, Shell and Marathon Gas
Transmission   Company  Inc.)  owns  237  miles  of   unregulated   natural  gas
transmission  lines primarily  located on the outer  continental  shelf offshore
Louisiana.  Nautilus  (which  is owned  by  Sailfish,  Shell  and  Marathon  Gas
Transmission  Company  Inc.)  owns  101  miles  of  FERC-regulated  natural  gas
pipelines and related  facilities  extending from points  offshore  Louisiana to
interconnecting  pipelines  near the  Garden  City and  Neptune  gas  processing
facilities.  Nemo (which is jointly  owned by Moray and Shell) is a  development
stage  enterprise  that is constructing  and will operate an offshore  Louisiana
natural gas gathering  pipeline and related facilities that will connect certain
Shell  offshore  platform  assets to Manta Ray.  Management  believes that these
assets  have a  significant  upside  potential,  since Shell and  Marathon  have
dedicated production from over 1,000 square miles of offshore natural gas leases
to these  systems and only a small  portion of this total has been  developed to
date. Shell is the operator of the Manta Ray, Nautilus and Nemo systems.

         Equistar  storage  facility.  In addition  to the natural gas  pipeline
acquisitions,  the Company  announced on February 1, 2001 that it had acquired a
NGL storage facility from Equistar Chemicals, LP for approximately $3.4 million.
The salt dome storage cavern,  which is located near the Company's Mont Belvieu,
Texas complex, has a capacity of one million barrels. The purchase also includes
adjacent  acreage which would  support the  development  of  additional  storage
capacity.




























                                       13
<PAGE>

Processing

         The Company's Processing segment consists of its natural gas processing
business and related merchant  activities.  At the core of the Company's natural
gas processing  business are twelve natural gas processing plants located on the
Louisiana and Mississippi Gulf Coast with gross natural gas processing  capacity
of 11.61  Bcfd or net  capacity  of 3.21  Bcfd  based on the  Company's  current
ownership  interest.  The NGL production from these facilities,  along with that
from the Mont Belvieu isomerization facilities, supports the merchant activities
included in this operating segment.

         The  following  table lists the natural gas  processing  facilities  in
which the Company has an ownership interest:
<TABLE>
<CAPTION>
                                                            Gross Gas      Net Gas         Company
         Gas                                               Processing     Processing      Ownership
      Processing                                            Capacity       Capacity      Interest in
       Facility                     Location                (Bcf/day)     (Bcf/day)       Facility        Operator
-----------------------------------------------------------------------------------------------------------------------
<S>                                                           <C>            <C>            <C>        <C>
Yscloskey              St. Bernard Parish, Louisiana          1.85           0.60           32.6%      Dynegy
Calumet                St. Mary Parish, Louisiana             1.60           0.57           35.4%      EPOLP
North Terrebonne       Terrebonne Parish, Louisiana           1.30           0.43           33.4%      EPOLP
Venice                 Plaquemines Parish, Louisiana          1.30           0.17           13.1%      Dynegy
Toca                   St. Bernard Parish, Louisiana          1.10           0.61           55.5%      EPOLP
Pascagoula             Pascagoula, Mississippi                1.00           0.40           40.0%      BP
Sea Robin              Vermillion Parish, Louisiana           0.95           0.06            6.4%      Texaco
Blue Water             Acadia Parish, Louisiana               0.95           0.07            7.4%      ExxonMobil
Iowa                   Jefferson Davis Parish, Louisiana      0.50           0.01            2.0%      Texas Eastern
Patterson II           St. Mary Parish, Louisiana             0.60           0.01            2.0%      Duke Energy
Neptune                St. Mary Parish, Louisiana             0.30           0.20           66.0%      EPOLP
Burns Point            St. Mary Parish, Louisiana             0.16           0.08           50.0%      Marathon
                                                          -----------------------------
                       Total Gas Processing Capacity         11.61           3.21
                                                          =============================
</TABLE>

         The Company's natural gas processing  facilities are primarily straddle
plants  which are  situated  on  mainline  natural  gas  pipelines  which  bring
unprocessed Gulf of Mexico natural gas production onshore. Straddle plants allow
plant  owners to extract NGLs from a natural gas stream when the market value of
the NGLs is higher than the market  value of the same  unprocessed  natural gas.
After extraction, mixed NGLs are typically transported 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 the Company in its merchant  activities to meet  contractual  requirements or
sold on the spot and forward markets.

         The Venice gas plant is part of a larger  processing  complex  owned by
VESCO. Along with the Venice gas plant, VESCO owns a NGL fractionation  facility
(previously mentioned under the Fractionation  segment),  storage assets and gas
gathering pipelines located in Louisiana. The other owners of VESCO are Chevron,
Koch, Venice Gathering and Dynegy. The Company owns 13.1% of VESCO.

         The natural gas throughput  capacities of the gas processing facilities
are  based  on  practical  limitations.  The  Company's  utilization  of the gas
processing assets depends upon general economic and operating  conditions and is
generally  measured  in terms of equity NGL  production.  Production  of NGLs is
generally a function of throughput  (i.e.,  higher natural gas throughput  rates
translate  into higher  equity NGL  production).  Equity NGL  production  can be
defined as the volume of NGLs  extracted by the gas  processing  plants to which
the  Company  takes  title under the terms of its  processing  agreements  or as
result of plant  ownership  interests.  Equity NGL  production can be negatively
affected by high fuel costs and/or low purity NGL product prices.

         The Company's  equity NGL  production was 72 MBPD in 2000 compared with
67 MBPD in 1999. For comparison  purposes only, Shell equity NGL production from
these  facilities  was 41 MBPD in 1998.  The 1999  volume is for the  period the
Company  owned the assets  after the TNGL  acquisition.  For the entire  year of


                                       14
<PAGE>

1999, equity NGL production (for both Shell and the Company) from the facilities
was 57 MBPD.  The  increase  in  equity  production  from 1999 to 2000 is due to
growing levels of natural gas production  available for  processing,  higher NGL
content natural gas and new processing facilities, such as the Company's Neptune
plant.  The increase in equity  production  from 1998 to 1999 is attributable to
increased Gulf of Mexico  deepwater  production,  the start-up of the Pascagoula
facility in 1999 and  improved  market  prices for NGLs which  justified  higher
extraction rates.

         Management believes that natural gas and associated NGL production from
the Gulf of Mexico will  significantly  increase in the coming years as a result
of advances in  three-dimensional  seismic and development systems and continued
capital spending by major oil companies regardless of the commodity environment.

         The majority of the operating  margins earned by the Company's  natural
gas processing  operations are based on the relative  economic value of the NGLs
extracted  by the gas plants  compared  to the fuel and  shrinkage  value of the
natural gas consumed to produce the NGLs,  less the  operating  costs of the gas
plants.  Processing  contracts  based on this type of arrangement  are generally
called keepwhole contracts.  Specifically,  a keepwhole contract is defined as a
natural gas  processing  arrangement  where the  processor  (i.e.,  the Company)
generally  takes title to the NGLs  extracted  from natural  gas. The  processor
reimburses  the  producer  (e.g.,  Shell or others) for the market  value of the
energy extracted from the natural gas stream in the form of fuel and NGLs (known
as "shrinkage") based on the Btus (a measure of heat value) consumed  multiplied
by the market value for natural gas. The  processor  derives a profit  margin to
the extent the market  value of the NGLs  extracted  exceeds the market value of
the fuel and shrinkage and the operating costs of the natural gas plant. The gas
processing business does not generally exhibit a high degree of seasonality.

         The most significant  contract  affecting this operating segment is the
20-year Shell Processing  Agreement that grants the Company 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 the  developments
currently  referred to as  deepwater.  Shell is the largest oil and gas producer
and holds one of the largest lease  positions in the  deepwater  Gulf of Mexico.
Generally,  the Shell  Processing  Agreement  grants the Company  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 the  Company's  gas  processing  facilities  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.

         As noted  previously,  this  segment  also  includes the results of the
Company's merchant activities.  Generally,  in its isobutane merchant activities
the Company takes title to feedstock  products and sells processed end products.
In the case of its gas  processing  facilities,  the  Company  takes  title to a
portion of the mixed NGLs (such  amount  defined by  contract)  that it extracts
from the natural gas stream.  The purity NGL products  extracted  from the mixed
NGL stream are then sold by the Company in the normal  course of  business.  The
Company from time to time uses  financial  instruments  to reduce its  commodity
price  exposure.  For a  general  discussion  on the  Company's  commodity  risk
management policies and exposure,  see Item 7A of this Form 10-K,  "Quantitative
and Qualitative Disclosures about Market Risk."

         In its  isobutane  merchant  business,  the Company  has  entered  into
contracts to sell isobutane.  The Company can meet its sales obligations  either
by:

     o    purchasing normal butane in the spot market or utilizing normal butane
          inventory from equity gas plant production and isomerizing it;
     o    purchasing  mixed butane on the spot market,  including  imports,  and
          processing  it through a DIB; or
     o    purchasing  isobutane  in the  spot  markets  or  utilizing  isobutane
          inventory from equity gas plant production.



                                       15
<PAGE>

         When the price differential  between normal butane and isobutane is not
substantial enough to economically justify isomerization,  the Company purchases
isobutane  or uses its own  inventory  of  isobutane  for  delivery to its sales
customers who pay market-based prices.

         The  Company  utilizes a fleet of  approximately  625  railcars  in its
merchant activities, the majority of which are under short and long-term leases.
The railcars are used to deliver  feedstocks to Company facilities and transport
NGL  products   throughout  the  United  States.   The  Company  also  has  rail
loading/unloading  facilities at Mont Belvieu,  Texas, Breaux Bridge,  Louisiana
and Petal,  Mississippi.  These  facilities  service  the  Company's  as well as
customers' rail shipments.  The costs of maintaining the railcars and associated
assets are a cost of the NGL merchant business.


Octane Enhancement

         The Company's Octane Enhancement segment consists of its 33.3% interest
in BEF,  which  owns and  operates  a  facility  that  produces  motor  gasoline
additives to enhance  octane.  The BEF facility  currently  produces MTBE and is
located within the Company's Mont Belvieu,  Texas complex. The gross capacity of
the MTBE facility is  approximately  15 MBPD with a net capacity of 5 MBPD.  For
the years 2000, 1999 and 1998, net production  averaged 5 MBPD or near capacity.
The other owners of BEF are Sun and Mitchell. EPCO operates the facility under a
long-term contract.

         MTBE is  produced  by  reacting  methanol  with  isobutylene,  which is
derived from isobutane.  MTBE was originally used as an octane enhancer in motor
gasoline,  partly  in  response  to the  lead  phase-down  program  begun in the
mid-1970's.  Following  implementation  of the Clean Air Act Amendments of 1990,
MTBE became a widely-used  oxygenate to enhance the clean burning  properties of
motor gasoline.  Although oxygen  requirements  can be obtained by using various
oxygenates  such as  ethanol,  ETBE and  TAME,  MTBE  has  gained  the  broadest
acceptance 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.

         Substantially  all of the MTBE produced in the United States is used in
the  production  of  oxygenated  motor  gasoline  that is required to be used in
carbon monoxide and ozone  non-attainment areas designated pursuant to the Clean
Air Act Amendments of 1990 and the California oxygenated motor gasoline program.
Demand for MTBE is primarily  affected by the demand for motor gasoline in these
areas.  Motor gasoline usage in turn is affected by many factors,  including the
price of motor  gasoline  (which is dependent upon crude oil prices) and general
economic conditions.  Historically, the spot price for MTBE has been at a modest
premium to gasoline  blend  values.  Future MTBE demand is highly  dependent  on
environmental  regulation,  federal  legislation  and the actions of  individual
states.

         Each of the owners of BEF is responsible for supplying one-third of the
facility's  isobutane  feedstock  through June 2004.  Sun and Mitchell have each
contracted  to  supply  their  respective  portions  of the  feedstock  from the
Company's  isomerization  facilities.  The methanol  feedstock is purchased from
third parties under  long-term  contracts and  transported  to Mont Belvieu by a
dedicated pipeline which is part of the Houston Ship Channel Pipeline System. As
mentioned previously in the Pipeline segment discussion,  management anticipates
that BEF's MTBE production  will be transported  using this same pipeline system
beginning in April 2001.

         BEF has a ten-year  off-take  agreement  with Sun under  which they are
required to purchase all of the plant's MTBE production through September 2004 .
Through May 31, 2000,  Sun was required to pay for the MTBE using the  following
pricing structure:

     -    for the first 193,450,000  gallons of MTBE produced per contract year,
          the  higher of (i) a  contractual  floor  price or (ii) a toll or spot
          market-related price (as defined within the agreement); and,
     -    a spot market-related price for all volumes in excess of this amount.

The  floor  price  was a price  sufficient  to  cover  essentially  all of BEF's
operating  costs plus principal and interest  payments on its bank term loan. In
general,  Sun paid the floor price during the periods in which it was in effect.


                                       16
<PAGE>

Beginning  June 1, 2000 through the remainder of the  agreement,  the pricing on
all MTBE  delivered to Sun changed to a  market-related  negotiated  price which
generally   approximates  Gulf  Coast  MTBE  spot  prices.   The  market-related
negotiated  price is subject to fluctuations in commodity  prices for MTBE. MTBE
spot prices are generally  stronger during the April to September period of each
year which corresponds with the summer driving season.

         Recent  Regulatory  Developments.  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.

         Alternative  Uses of the  BEF  facility.  In  light  of the  regulatory
climate, the owners of BEF are formulating a contingency plan for use of the BEF
facility if MTBE were banned or significantly  curtailed.  The owners of BEF are
exploring a possible  conversion  of the BEF facility  from MTBE  production  to
alkylate production. One conversion alternative is expected to result in similar
operating  margin as that currently  anticipated from the facility if it were to
remain in MTBE service.  If this  approach  were taken,  the cost to convert the
facility would range from $20 million to $25 million,  with the Company's  share
being $6.7  million  to $8.3  million.  A second  conversion  alternative  would
increase  both  production  capacity  and  overall  margin and cost  between $50
million and $90 million,  with the  Company's  share being $16.7  million to $30
million. Management anticipates that if MTBE is banned alkylate demand will rise
as producers  use it to replace  MTBE as an octane  enhancer.  Greater  alkylate
production would be expected to increase  isobutane  consumption  nationwide and
result in improved isomerization margins for the Company.


Other

         This operating  segment is primarily  comprised of fee-based  marketing
services.  The Company  performs  NGL  marketing  services for a small number of
clients  for which it charges a  commission.  The clients  served are  primarily
located  in the states of  California,  Illinois  and  Washington.  The  Company
utilizes the resources of its gas processing  merchant business group to perform
these services.  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. The Company handles approximately 30,000 barrels per
day of various NGL products  through its  fee-based  services with the period of
highest activity occurring during the winter months.  This segment also includes
other engineering services,  construction equipment rentals and computer network
services that support various plant operations.


Competition

         The  consumption  of NGL products in the United States can be separated
among four  distinct  markets.  Petrochemical  production  provides  the largest
end-use  market,   followed  by  motor  gasoline  production,   residential  and
commercial   heating  and  agricultural   uses.  There  are  other   hydrocarbon
alternatives, primarily refined petroleum products, which can be substituted for
NGL products in most end uses. In some uses,  such as residential and commercial
heating,  a substitution  of other  hydrocarbon  products for NGL products would
require  a  significant  expense  or  delay,  but for  other  uses,  such as the
production  of motor  gasoline,  ethylene,  industrial  fuels and  petrochemical
feedstocks, such a substitution can be readily made without significant delay or
expense.

         Because  certain NGL  products  compete  with other  refined  petroleum
products in the fuel and petrochemical feedstock markets, NGL product prices are
set by or in competition with refined petroleum products.  Increased  production
and  importation  of NGLs and NGL products in the United States may decrease NGL


                                       17
<PAGE>

product  prices in  relation  to  refined  petroleum  alternatives  and  thereby
increase  consumption of NGL products as NGL products are  substituted for other
more  expensive  refined  petroleum  products.  Conversely,  a  decrease  in the
production  and  importation of NGLs and NGL products could increase NGL product
prices in  relation to refined  petroleum  product  prices and thereby  decrease
consumption  of NGLs.  However,  because  of the  relationship  of crude oil and
natural gas production to NGL production,  the Company believes any imbalance in
the prices of NGLs and NGL products and alternative products would be temporary.

         Although competition for NGL fractionation  services is based primarily
on the  fractionation  fee,  the  ability  of a NGL  fractionator  to obtain and
distribute  product is a function of the  existence  of the  necessary  pipeline
transportation  and  storage  facilities.  A NGL  fractionator  connected  to an
extensive  transportation and distribution  system has direct access to a larger
market than its competitors. Overall, the Company believes it provides a broader
range of services than any of its competitors. In addition, the Company believes
its  joint  venture  relationships  enable  it to  contract  for  the  long-term
utilization of a significant  amount of its NGL  fractionation  facilities  with
major producers and consumers of NGLs or NGL products.

         The  Company's  Mont Belvieu NGL  fractionation  facility  competes for
volumes of mixed NGLs with three other NGL fractionators at Mont Belvieu:  Cedar
Bayou Fractionators,  a joint venture between Dynegy and BP (205 MBPD capacity);
Gulf Coast  Fractionators,  a joint venture of Conoco,  Mitchell and Dynegy (110
MBPD capacity); and Diamond-Koch, a joint venture between Ultramar Diamond, Koch
and Duke Energy  (reported to be 160 MBPD capacity).  ExxonMobil  operates a NGL
fractionation  facility (110 MBPD capacity) in Hull,  Texas that is connected to
Mont Belvieu by pipeline and Phillips operates a NGL fractionation facility (100
MBPD  capacity) in Sweeny,  Texas that is connected to Mont Belvieu by pipeline.
ExxonMobil and Phillips use their facilities  primarily to process their own NGL
production  but  at  certain  times  these  facilities   compete  with  the  NGL
fractionators at Mont Belvieu.

         The  Company's  NGL  fractionation  facilities  also  compete on a more
limited basis with two NGL fractionators in Conway,  Kansas:  Williams (107 MBPD
capacity)  and Koch (200  MBPD  capacity)  and with a number  of  decentralized,
smaller NGL fractionation facilities in Louisiana, the most significant of which
are Promix at Napoleonville, in which the Company owns a one-third interest (145
MBPD capacity),  Texaco/Williams at Paradis (45 MBPD capacity) and EPE at Eunice
and Riverside (62 MBPD combined  capacity).  In recent years,  the Conway market
has  experienced  excess capacity and prices for NGL products that are generally
lower than prices at Mont Belvieu,  although prices in Conway tend to strengthen
along with demand for propane in winter months.  Finally,  a number of producers
operate   smaller-scale   NGL   fractionators  at  individual  field  processing
facilities.

         In the isomerization  market,  the Company competes primarily with Koch
at Conway,  Kansas;  Enron at Riverside,  Louisiana;  and Conoco at Wingate, New
Mexico.  Enron  and  Valero  also  produce  isobutane,  primarily  for  internal
production  of MTBE.  Competitive  factors  affecting  isomerization  operations
include the market price  differential  between  normal  butane and isobutane as
well as the fees charged for isomerization  services,  long-term contracts,  the
availability  of  commercial  capacity,  the ability to produce a higher  purity
isobutane product and storage and transportation support.

         BEF  competes  with a number of MTBE  producers,  including a number of
refiners  who  produce  MTBE for  internal  consumption  in the  manufacture  of
reformulated  motor  gasoline.  Competitive  factors  affecting MTBE  production
include production costs,  long-term  contracts,  the availability of commercial
capacity and federal and state environmental regulations relating to the content
of motor gasoline.

         The Company competes with numerous  producers of high purity propylene,
which  include many of the major  refiners on the Gulf Coast.  The Company is in
direct  competition  with  Diamond-Koch  which also has polymer grade  propylene
production facilities in Mont Belvieu,  Texas. Both the Company and Diamond-Koch
facilities  process refinery grade propylene produced by third party refineries.
The  Company's  ability to attract  feedstock  is enhanced  by its  distribution
system  capabilities which include pipelines,  a dock for unloading barges and a
tank truck and railcar  unloading  facility.  The  Company's  facilities  use an
integrated heat pump system, supplemented by electric drivers. This provides for
very efficient operating costs and flexibilities. The Company is able to attract
feedstock  from a  variety  of  suppliers  by  providing  service  to match  the
suppliers logistic requirements. The Company has entered into long-term sale and


                                       18
<PAGE>

processing  agreements with key customers and is able to be competitive in price
due to its lower operating costs and variable  feedstock supply. The Company has
developed  delivery  systems to its key customers  which meet or exceed those of
its competitors.

         Certain of the  Company's  competitors  are major oil and  natural  gas
companies  and other large  integrated  pipeline or energy  companies  that have
greater  financial  resources  than  the  Company.   The  Company  believes  its
independence  from the major  producers of NGLs and  petrochemical  companies is
often an  advantage  in its  dealings  with  its  customers,  but the  Company's
continued success will depend upon its ability to maintain strong  relationships
with the primary  producers of NGLs and consumers of NGL products,  particularly
in the form of long-term contracts and joint venture relationships.

         The United States Gulf Coast gas  processing  business is  competitive.
The  Company  encounters   competition  from  fully  integrated  oil  companies,
intrastate  pipeline  companies,  major interstate  pipeline companies and their
non-regulated  affiliates,  and independent processors.  Each of these companies
have varying levels of financial and personnel resources. The principal areas of
competition  include  obtaining  the gas plant  capacities  required to meet the
Company's processing needs,  obtaining gas supplies where the Company has excess
processing  capacity  and in the  marketing  of the  final NGL  products  at the
tailgate of the  Company's  fractionation  facilities.  Overall  competition  is
impacted by supply and demand for both  natural gas as a feedstock  and finished
NGL  products.  In the Company's  fee-based  marketing  services,  the principal
methods of competition revolves around price and quality of service.


Employees

         At December  31, 2000,  EPCO  employed  782  employees  involved in the
management  and  operation  of assets  owned and operated by the Company none of
whom were members of a union.  The Norco  facilities  are managed by the Company
with the assets  operated  under contract by union  employees of Shell.  Shell's
relationship  with its union employees at Norco can be characterized as good and
the Company believes that this good relationship will continue.


Major Customers of the Company

         The  Company's  revenues are derived from a wide  customer  base and no
single customer  accounted for more than 10% of consolidated  revenues in fiscal
2000. For a more complete discussion of significant  customers in the last three
fiscal years, see Note 13 of the Notes to the Consolidated Financial Statements.


Regulation

         Interstate Common Carrier Pipeline Regulation

         The  Company's  Chunchula,  Lou-Tex  Propylene,  Lou-Tex  NGL and  Lake
Charles/Bayport pipelines are interstate common carrier oil pipelines subject to
regulation by Federal Energy Regulatory Commission ("FERC") under the October 1,
1977 version of the Interstate Commerce Act ("ICA").

         Standards  for  Terms  of  Service  and  Rates.  As  interstate  common
carriers, the Chunchula, Lou-Tex Propylene, Lou-Tex NGL and Lake Charles/Bayport
pipelines provide service to any shipper who requests  transportation  services,
provided that the products  tendered for  transportation  satisfy the conditions
and  specifications  contained in the  applicable  tariff.  The ICA requires the
Company to  maintain  tariffs on file with the FERC that set forth the rates the
Company charges for providing  transportation  services on the interstate common
carrier pipelines as well as the rules and regulations governing these services.

         The ICA gives the FERC  authority  to  regulate  the rates the  Company
charges  for  service  on the  interstate  common  carrier  pipelines.  The  ICA
requires,  among  other  things,  that such rates be "just and  reasonable"  and
nondiscriminatory.  The ICA permits interested persons to challenge proposed new
or changed rates and  authorizes the FERC to suspend the  effectiveness  of such


                                       19
<PAGE>

rates for a period of up to seven months and to investigate such rates. If, upon
completion of an  investigation,  the FERC finds that the new or changed rate is
unlawful,  it is  authorized  to require the  carrier to refund the  revenues in
excess of the prior tariff collected during the term of the  investigation.  The
FERC may also investigate,  upon complaint or on its own motion,  rates that are
already in effect  and may order a carrier  to change  its rates  prospectively.
Upon an  appropriate  showing,  a shipper  may obtain  reparations  for  damages
sustained for a period of up to two years prior to the filing of a complaint.

         On October  24,  1992,  Congress  passed the Energy  Policy Act of 1992
("Energy  Policy Act").  The Energy Policy Act deemed  petroleum  pipeline rates
that were in effect for the 365-day  period  ending on the date of  enactment or
that  were in  effect on the  365th  day  preceding  enactment  and had not been
subject to complaint,  protest or investigation  during the 365-day period to be
just and reasonable under the ICA (i.e., "grandfathered"). The Energy Policy Act
also limited the circumstances  under which a complaint can be made against such
grandfathered  rates. In order to challenge  grandfathered  rates, a party would
have to show that it was previously  contractually  barred from  challenging the
rates or that the economic circumstances or the nature of the service underlying
the rate had substantially changed or that the rate was unduly discriminatory or
preferential.  These grandfathering provisions and the circumstances under which
they may be  challenged  have  received  only limited  attention  from the FERC,
causing a degree of uncertainty as to their application and scope. The Chunchula
and Lake Charles/Bayport  pipelines are covered by the grandfathered  provisions
of the Energy Policy Act.

         The Energy Policy Act required the FERC to issue rules  establishing  a
simplified  and  generally  applicable  ratemaking   methodology  for  petroleum
pipelines,  and to streamline procedures in petroleum pipeline proceedings.  The
FERC  responded to this  mandate by issuing  Order No. 561,  which,  among other
things,  adopted a new indexing rate methodology for petroleum pipelines.  Under
the new regulations, which became effective January 1, 1995, petroleum pipelines
are able to change their rates within prescribed ceiling levels that are tied to
an  inflation  index.  Rate  increases  made within the  ceiling  levels will be
subject to  protest,  but such  protests  must show that the portion of the rate
increase  resulting from  application of the index is substantially in excess of
the  pipeline's  increase in costs.  If the  indexing  methodology  results in a
reduced ceiling level that is lower than a pipeline's  filed rate, Order No. 561
requires the pipeline to reduce its rate to comply with the lower ceiling. Under
Order  No.  561,  a  pipeline  must  as a  general  rule  utilize  the  indexing
methodology to change its rates.  The FERC,  however,  retained  cost-of-service
ratemaking,  market-based  rates, and settlement as alternatives to the indexing
approach, which alternatives may be used in certain specified circumstances.

         The Company believes the rates it charges for transportation service on
its  interstate  pipelines are just and  reasonable  under the ICA. As discussed
above,  however,  because of the  uncertainty  related to the application of the
Energy Policy Act's grandfathering  provisions to the Company's rates as well as
the novelty and uncertainty related to the FERC's new indexing methodology,  the
Company  is unable to  predict  what  rates it will be  allowed to charge in the
future for service on its  interstate  common  carrier  pipelines.  Furthermore,
because rates charged for transportation  must be competitive with those charged
by other  transporters,  the rates set forth in the  Company's  tariffs  will be
determined   based  on   competitive   factors   in   addition   to   regulatory
considerations.

         Allowance  for  Income  Taxes in Cost of  Service.  In a 1995  decision
regarding Lakehead Pipe Line Company ("Lakehead"), FERC ruled that an interstate
pipeline owned by a limited partnership could not include in its cost of service
an allowance  for income taxes with  respect to income  attributable  to limited
partnership  interests held by  individuals.  On request in 1996, FERC clarified
that,  in order to avoid any effect of a  "curative  allocation"  of income from
individual partners to the corporate partner, an allowance for income taxes paid
by corporate  partners  must be based on income as  reflected on the  pipeline's
books for  earning  and  distribution  rather  than as  reported  for income tax
purposes. Subsequent appeals of these rulings were resolved by a 1997 settlement
among the parties and were never  adjudicated.  The effect of this policy on the
Company is uncertain.  The Company's rates are set using the indexing method and
have  been  grandfathered.  It is  possible  that a party  might  challenge  the
Company's  grandfathered  rates on the basis that the  creation  of the  Company
constituted  a  substantial  change in  circumstances,  potentially  lifting the
grandfathering protection.  Alternatively,  a party might contend that, in light
of the Lakehead ruling and creation of the Company,  the Company's rates are not
just and  reasonable.  While it is not possible to predict the  likelihood  that
such challenges  would succeed at FERC, if such challenges were to be raised and
succeed,   application  of  the  Lakehead  ruling  would  reduce  the  Company's
permissible  income tax  allowance  in any cost of  service,  and rates,  to the
extent  income is  attributable  to  partnership  interests  held by  individual
partners rather than corporations.



                                       20
<PAGE>

         Intrastate Common Carrier Regulation

         The Sorrento NGL products  pipeline,  the Yscloskey  and  Toca-to-Norco
petroleum products pipeline,  the  Norco-to-Sorrento  and the  Tebone-to-Vulcan,
Sorrento,  Norco, and Geismar ethane pipelines and the Norco-to-Sorrento propane
pipeline are  intrastate  common  carrier  pipelines that are subject to various
Louisiana state laws and regulations  that affect the terms of service and rates
for such services. The Company's Houston Ship Channel Pipeline and the remainder
of its Louisiana  pipelines are intrastate  private carriers not subject to rate
regulation.

         Other State and Local Regulation

         The  Company's  activities  are subject to various state and local laws
and  regulations,  as well as  orders of  regulatory  bodies  pursuant  thereto,
governing a wide variety of matters, including marketing,  production,  pricing,
community  right-to-know,  protection  of  the  environment,  safety  and  other
matters.

         Cogeneration

         The Company cogenerates  electricity for internal  consumption and heat
for a process-related  hot oil system at Mont Belvieu.  If this electricity were
sold to third parties, the Company's Mont Belvieu cogeneration  facilities could
be certified as qualifying facilities under the Public Utility Regulatory Policy
Act of 1978  ("PURPA").  Subject to  compliance  with certain  conditions  under
PURPA, this certification  would exempt the Company from most of the regulations
applicable  to electric  utilities  under the  Federal  Power Act and the Public
Utility  Holding  Company  Act, as well as from most state laws and  regulations
concerning the rates, finances, or organization of electric utilities.  However,
since  such  electric  power  is  consumed   entirely  by  the  Company's  plant
facilities,  the  Company's  cogeneration  activities  are not subject to public
utility regulation under federal or Texas law.

         Environmental Matters

         General.  The  operations of the Company are subject to federal,  state
and local  laws and  regulations  relating  to release  of  pollutants  into the
environment or otherwise relating to protection of the environment.  The Company
believes its operations and facilities are in general compliance with applicable
environmental regulations.

         However,  risks of process  upsets,  accidental  releases or spills are
associated  with the  Company's  operations  and there can be no assurance  that
significant costs and liabilities will not be incurred, including those relating
to claims for damage to property and persons.

         The  clear  trend  in   environmental   regulation  is  to  place  more
restrictions and limitations on activities that may affect the environment, such
as  emissions  of  pollutants,  generation  and  disposal  of wastes and use and
handling of  chemical  substances.  The usual  remedy for failure to comply with
these laws and  regulations is the assessment of  administrative,  civil and, in
some instances,  criminal penalties or, in rare circumstances,  injunctions. The
Company believes the cost of compliance with  environmental laws and regulations
will not have a  significant  effect on the results of  operations  or financial
position of the Company.  However,  it is possible  that the costs of compliance
with  environmental  laws and  regulations  will continue to increase,  and thus
there can be no assurance as to the amount or timing of future  expenditures for
environmental  compliance or remediation,  and actual future expenditures may be
different  from the  amounts  currently  anticipated.  In the  event  of  future
increases in costs,  the Company may be unable to pass on those increases to its
customers. The Company will attempt to anticipate future regulatory requirements
that might be imposed and plan accordingly in order to remain in compliance with
changing  environmental  laws and  regulations and to minimize the costs of such
compliance.

         Solid Waste. The Company currently owns or leases,  and has in the past
owned  or  leased,  properties  that  have  been  used  over the  years  for NGL
processing,  treatment,  transportation  and storage and for oil and natural gas
exploration and production activities. Solid waste disposal practices within the
NGL industry and other oil and natural gas related industries have improved over
the years with the passage and implementation of various  environmental laws and
regulations.  Nevertheless,  a possibility  exists that  hydrocarbons  and other
solid wastes may have been disposed of on or under various  properties  owned by
or leased by the Company during the operating  history of those  facilities.  In
addition,  a small number of these  properties  may have been  operated by third
parties  over whom the Company had no control as to such  entities'  handling of
hydrocarbons  or other wastes and the manner in which such  substances  may have


                                       21
<PAGE>

been  disposed of or  released.  State and federal  laws  applicable  to oil and
natural  gas wastes and  properties  have  gradually  become  more  strict  and,
pursuant to such laws and  regulations,  the Company could be required to remove
or remediate  previously  disposed  wastes or property  contamination  including
groundwater  contamination.  The Company does not believe  that there  presently
exists  significant   surface  and  subsurface   contamination  of  the  Company
properties by hydrocarbons or other solid wastes.

         The Company  generates  both  hazardous and  nonhazardous  solid wastes
which are subject to  requirements  of the  federal  Resource  Conservation  and
Recovery Act ("RCRA") and comparable state statutes.  From time to time, the EPA
has considered making changes in nonhazardous  waste standards that would result
in stricter disposal requirements for such wastes.  Furthermore,  it is possible
that some wastes  generated  by the Company  that are  currently  classified  as
nonhazardous may in the future be designated as "hazardous wastes," resulting in
the wastes being subject to more rigorous and costly disposal requirements. Such
changes in the  regulations  may result in additional  capital  expenditures  or
operating expenses by the Company.

         Superfund. The Comprehensive  Environmental Response,  Compensation and
Liability Act ("CERCLA"),  also known as the "Superfund"  law, and similar state
laws,  impose liability  without regard to fault or the legality of the original
conduct,  on certain  classes of persons,  including  the owner or operator of a
site and  companies  that disposed or arranged for the disposal of the hazardous
substances found at the site. CERCLA also authorizes the EPA and, in some cases,
third parties to take actions in response to threats to the public health or the
environment and to seek to recover from the  responsible  classes of persons the
costs they incur. Although "petroleum" is excluded from CERCLA's definition of a
"hazardous substance," in the course of its ordinary operations the Company will
generate wastes that may fall within the definition of a "hazardous  substance."
The  Company  may be  responsible  under  CERCLA  for all or  part of the  costs
required to clean up sites at which such wastes have been disposed.  The Company
has not received any  notification  that it may be potentially  responsible  for
cleanup costs under CERCLA.

         Clean Air  Act--General.  The  operations of the Company 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 the pipelines, processing and storage facilities. For example, the
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. One of the other consequences of
this  non-attainment  status 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 imposing more strict requirements on existing
facilities  were  issued  in  December,  2000.  These  regulations  mandate  90%
reductions  in oxides of nitrogen  emissions  from point sources such as the gas
turbines at the  Company's  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 litigation filed
in the District  Court of Travis  County,  Texas,  on January 19,  2001,  by the
Company as part of a coalition of major  Houston-Galveston  area industries.  In
addition to the Company,  the plaintiffs in this case are the BCCA Appeal Group,
Equistar Chemicals, LP, Lyondell Chemical Company,  Lyondell-CITGO Refining L.P.
and Reliant  Energy,  Incorporated;  named as  defendants  are the Texas Natural
Resource Conservation  Commission and its chairman,  commissioners and executive
director.  The suit seeks a ruling that these  regulations  are invalid and void
and asks for a temporary  injunction to stay their  effectiveness  pending final
judgment in the case. If these regulations  stand as issued,  they would require
substantial  redesign and modification of the Mont Belvieu facilities to achieve
the mandated  reductions;  however,  the precise impact of these requirements on
the Company's operations cannot be determined until this litigation is resolved.
Regardless  of the  outcome of this  litigation,  the capital  expenditures  for
making the required  modifications  would be spread over the years leading up to
the compliance deadline, which could be as early as 2005.

         Failure to comply with air statutes or the implementing regulations may
lead to the assessment of administrative,  civil or criminal  penalties,  and/or
result in the  limitation or cessation of  construction  or operation of certain
air  emission  sources.  The Company  believes  its  operations,  including  its
processing  facilities,  pipelines and storage  facilities,  are in  substantial
compliance with applicable air requirements.


                                       22
<PAGE>

     Clean  Air  Act--Fuels.  See  discussion  of  Octane  Enhancement  - Recent
     Regulatory Developments.

         Clean Water Act. The Federal Water Pollution Control Act, also known as
the Clean Water Act,  and similar  state laws require  containment  of potential
discharges  of   contaminants   into  federal  and  state  waters.   Regulations
promulgated  pursuant to these laws  require that  entities  such as the Company
that discharge into federal and state waters obtain National Pollutant Discharge
Elimination System ("NPDES") and/or state permits  authorizing these discharges.
The Clean Water Act and analogous  state laws provide  penalties for releases of
unauthorized  contaminants into the water and impose  substantial  liability for
the costs of removing spills from such waters. In addition,  the Clean Water Act
and  analogous  state laws require  that  individual  permits or coverage  under
general  permits be obtained by covered  facilities for discharges of stormwater
runoff.  The Company  believes it will be able to obtain,  or be included under,
these Clean Water Act permits and that  compliance  with the  conditions of such
permits will not have a material effect on the Company.

         Underground  Storage  Requirements.  The  Company  currently  owns  and
operates  underground  storage  caverns  that have  been  created  in  naturally
occurring salt domes in Texas, Louisiana and Mississippi.  These storage caverns
are used to store  NGLs,  NGL  products,  propane/propylene  mix and  propylene.
Surface  brine pits and brine  disposal  wells are used in the  operation of the
storage  caverns.  All of these  facilities are subject to strict  environmental
regulation  by state  authorities  under the Texas  Natural  Resources  Code and
similar statutes in Louisiana and  Mississippi.  Regulations  implemented  under
such statutes  address the  operation,  maintenance  and/or  abandonment of such
underground  storage  facilities,  pits and  disposal  wells,  and require  that
permits  be  obtained.  Failure to comply  with the  governing  statutes  or the
implementing regulations may lead to the assessment of administrative,  civil or
criminal  penalties.  The Company  believes  its salt dome  storage  operations,
including the caverns,  brine pits and brine disposal wells,  are in substantial
compliance with applicable statutes.

          Safety Regulation

         The  Company's   pipelines  are  subject  to  regulation  by  the  U.S.
Department of Transportation  under the Hazardous Liquid Pipeline Safety Act, as
amended ("HLPSA"), relating to the design, installation,  testing, construction,
operation,  replacement and management of pipeline facilities.  The HLPSA covers
crude oil, carbon dioxide, NGL and petroleum products pipelines and requires any
entity which owns or operates pipeline facilities to comply with the regulations
under the HLPSA,  to permit  access to and allow  copying of records and to make
certain  reports  and  provide  information  as  required  by the  Secretary  of
Transportation.  The Company believes its pipeline operations are in substantial
compliance with applicable HLPSA requirements;  however,  due to the possibility
of new or amended laws and regulations or  reinterpretation of existing laws and
regulations,  there can be no assurance  that future  compliance  with the HLPSA
will not have an impact on the  Company's  results of  operations  or  financial
position.

         The workplaces  associated  with the processing and storage  facilities
and the pipelines  operated by the Company are also subject to the  requirements
of the federal  Occupational Safety and Health Act ("OSHA") and comparable state
statutes.  The Company  believes it has operated in substantial  compliance with
OSHA  requirements,   including  general  industry  standards,   record  keeping
requirements and monitoring of occupational exposure to regulated substances.

         In  general,  the Company  expects  expenditures  will  increase in the
future to comply with likely higher  industry and  regulatory  safety  standards
such as those described above. Such expenditures cannot be accurately  estimated
at this time,  although the Company does not expect that such  expenditures will
have a significant effect on the Company.


Title to Properties

         Real property held by the Company falls into two basic categories:  (a)
parcels that it owns in fee,  such as the land at the Mont  Belvieu  complex and
Petal fractionation and storage facility,  and (b) parcels in which its interest
derives  from  leases,  easements,  rights-of-way,   permits  or  licenses  from
landowners  or  governmental  authorities  permitting  the use of such  land for
Company  operations.  The fee sites upon which the major  facilities are located
have been  owned by the  Company  or its  predecessors  in title for many  years


                                       23
<PAGE>

without any  material  challenge  known to the Company  relating to title to the
land upon  which  the  assets  are  located,  and the  Company  believes  it has
satisfactory  title to such fee  sites.  The  Company  has no  knowledge  of any
challenge  to  the  underlying  fee  title  of  any  material  lease,  easement,
right-of-way  or  license  held by it or to its  title  to any  material  lease,
easement,  right-of-way,  permit  or  lease,  and the  Company  believes  it has
satisfactory title to all of its material leases,  easements,  rights-of-way and
licenses.


Item 3.  Legal Proceedings.

         EPCO has indemnified  the Company against any litigation  pending as of
the date of its  formation.  The Company is  sometimes  named as a defendant  in
litigation  relating to its normal  business  operations.  Although  the Company
insures itself 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  the Company  against
liabilities  arising from future legal  proceedings  as a result of its ordinary
business  activity.  See the discussion of litigation the Company has instituted
in connection with air pollution  control  regulations in the  Houston-Galveston
area on page 22 of this Form 10-K.  Other than this  litigation,  management  is
aware of no  significant  litigation,  pending  or  threatened,  that may have a
significant  adverse  effect on the Company's  financial  position or results of
operations.


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

         There were no matters related to the Company submitted to a vote of the
Limited and General Partner during the fourth quarter of 2000.

























                                       24
<PAGE>

                                     PART II


Item 5.  Market for Registrant's Common Equity and Related Partnership Matters

         Not applicable.  There are only two holders of equity  interests in the
Registrant.


Item 6.  Selected Financial Data.

         The  following  table  sets  forth  for the  periods  and at the  dates
indicated,  selected  historical  financial  data for the Company.  The selected
historical financial data (except for EBITDA of unconsolidated  affiliates) have
been derived from the Company's  audited  financial  statements  for the periods
indicated.  The selected  historical income statement data for each of the three
years in the period ended December 31, 2000 and the selected  balance sheet data
as of December 31, 2000 and 1999 should be read in conjunction  with the audited
financial statements for such periods included elsewhere in this report.  EBITDA
of unconsolidated  affiliates has been derived from the financial  statements of
such entities for the periods indicated.  See also "Management's  Discussion and
Analysis of Financial Condition and Results of Operation." The dollar amounts in
the  table   below,   except  per  Unit   data,   are  in   thousands.   Certain
reclassifications have been made to prior year's financial statements to conform
to the current year presentation.

<TABLE>
<CAPTION>
                                                                          For the Year Ended December 31,
                                                      ------------------------------------------------------------------------
                                                          2000           1999          1998           1997          1996
                                                      ------------------------------------------------------------------------
<S>                                        <C>          <C>            <C>             <C>          <C>           <C>
Income Statement Data:
     Revenues from consolidated operations (1)          $ 3,049,020    $ 1,332,979     $ 738,902    $ 1,020,281   $   999,506
     Equity in income of unconsolidated affiliates           24,119         13,477        15,671         15,682        15,756
                                                      ------------------------------------------------------------------------
           Total                                          3,073,139      1,346,456       754,573      1,035,963     1,015,262
     Operating costs and expenses  (1)                    2,801,060      1,201,605       685,884        938,392       907,524
                                                      ------------------------------------------------------------------------
     Operating margin                                       272,079        144,851        68,689         97,571       107,738
     Selling, general and administrative expenses (2)        28,345         12,500        18,216         21,891        23,070
                                                      ------------------------------------------------------------------------
     Operating income                                       243,734        132,351        50,473         75,680        84,668
     Interest expense                                       (33,329)       (16,439)      (15,057)       (25,717)      (26,310)
     Interest income                                          4,295          1,247           772          1,934         2,705
     Interest income from unconsolidated affiliates           1,662          1,625           809
     Dividend income from unconsolidated affiliates           7,091          3,435
     Other income (expense), net                               (272)          (379)          358            793           364
                                                      ------------------------------------------------------------------------
     Income before extraordinary charge and
       minority interest                                    223,181        121,840        37,355         52,690        61,427
     Extraordinary charge on early
        extinguishment of debt                                    -              -       (27,176)             -             -
                                                      ------------------------------------------------------------------------
     Income before minority interest                        223,181        121,840        10,179         52,690        61,427
     Minority interest                                         (113)          (110)         (122)           (78)          (92)
                                                      ------------------------------------------------------------------------
     Net income                                         $   223,068    $   121,730     $  10,057    $    52,612   $    61,335
                                                      ========================================================================

Balance Sheet Data (at period end):
     Total assets                                       $ 1,948,763    $ 1,492,712     $ 741,037    $   697,713   $   711,151
     Long-term debt                                         404,000        295,000        90,000        230,237       255,617
     Combined equity/Partners' equity                       942,671        794,626       567,273        311,885       266,021
</TABLE>

Notes to Selected Financial Data Table
(1)  The increase in 2000  revenues and expenses is primarily  due to the impact
     of the TNGL and MBA acquisitions. The TNGL acquisition was effective August
     1, 1999 with the MBA acquisition effective July 1, 1999.
(2)  1998 and 1999  expenses  are lower than 1997 amounts due to the adoption of
     the EPCO  agreement.  The increase in 2000  expenses over 1999 is primarily
     due to the additional  staff and resources  deemed necessary to support the
     Company's  ongoing  expansion  activities  resulting from  acquisitions and
     various capital expenditures.



                                       25
<PAGE>

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

         The following  discussion  and analysis  should be read in  conjunction
with the audited  consolidated  financial  statements  and notes  thereto of the
Company  included  elsewhere herein as well as the other portions of this report
on  Form  10-K.  In  particular,   the  reader  should  review  "Uncertainty  of
Forward-Looking  Statements and  Information"  found on page 2 of this report on
Form 10-K for  information  regarding  forward-looking  statements  made in this
discussion  and certain risks  inherent in the Company's  business.  Other risks
involved in the Company's business are discussed under Item 7A "Quantitative and
Qualitative Disclosures about Market Risk" beginning on page 42 of this report.

Current Business Environment

         During most of 2000,  the U.S.  NGL  industry  benefited  from a steady
demand  for NGLs,  petroleum  liquids  and MTBE as a result of the  strong  U.S.
economy and firm international demand.  Overall, the Company enjoyed outstanding
earnings in 2000 in all of its business segments despite the tighter  processing
margins encountered late in the fourth quarter.  The Company's solid performance
in 2000 is the result of an  integrated  NGL system  that  allows the Company to
extract margins through its access to multiple supplies and markets.

         The near term enthusiasm of the U.S. NGL industry was somewhat dampened
at the  end of  last  year  as the  cost  of  natural  gas  (which  is the  most
significant  variable  operating expense of most facilities)  soared to all time
record levels in the fourth  quarter of 2000 and first quarter of 2001.  Natural
gas prices increased from an average of $2.49/MMBtu in the first quarter of 2000
to  $5.22/MMBtu  in the fourth  quarter of 2000  (with  December  2000 being the
highest of the year at  $5.97/MMBtu).  In January 2001, the price of natural gas
reached record levels of  approximately  $10/MMBtu (or $60 per barrel on a crude
oil  equivalent).  Generally,  as the cost of  natural  gas  increases,  certain
facilities  may become too  expensive to operate and are  consequently  shutdown
temporarily.  In the case of a natural gas  processing  plant,  high natural gas
prices may result in the cost of fuel and  shrinkage  exceeding the value of the
NGLs  extracted  leading  either to  shutdown  of the  facility or to operate at
decreased extraction rates (i.e., to operate in "rejection mode").

         Because the Company has an integrated NGL system, the Company's natural
gas  processing  plants  continued  to operate at high levels  during the fourth
quarter of 2000 when many of its competitors were in rejection mode or shutdown.
In December  2000, the Company  maintained an equity NGL  production  rate of 67
MBPD, or about 90% of the full NGL extraction  rate. At the beginning of January
2001,  with natural gas prices  climbing to near  $10/MMBtu,  it finally  became
uneconomic to run the Company's natural gas processing  facilities at these high
extraction  rates.  As a result of minimal  or no NGL  extraction,  natural  gas
volumes  downstream of the  processing  plants became higher in NGL content than
allowed by pipeline specifications. The natural gas pipeline operators responded
by issuing  operational  flow orders that threatened to shut-in some of the rich
natural  gas from the  deepwater  developments  unless the NGL  content of these
natural  gas  streams  was  reduced  to  lower  levels.  In  order  to meet  the
specifications of the natural gas pipeline operators,  the Company and producers
negotiated  interim  reductions in fuel and shrinkage  costs to levels that were
significantly  below the  prevailing  cost of natural  gas.  With these  interim
provisions  in  place,  the  Company's  gas  processing   plants  increased  NGL
extraction  rates with the objective to lower the NGL content of the natural gas
to a level satisfactory to the pipeline operators.

         As natural  gas prices  increased  to  unprecedented  levels in January
2001,  refiners  switched to burning  propane as fuel and sold their natural gas
into the spot markets.  In late  December  2000 and January 2001,  petrochemical
demand  softened as  petrochemical  companies  elected to deplete  their NGL raw
material  inventories  and their  finished  product  inventories of ethylene and
propylene  and  optimized  their  ethylene   production  from  cracking  naptha.
Management believes that the petrochemical  companies can take this position for
only a short time and these  companies  will  return to the NGL  marketplace  to
purchase  ethane  later in the  first  quarter  of 2001 due to their  needs  for
greater ethylene production.

         As a result of reduced supplies of NGLs from gas processing  facilities
and  refineries in December  2000 and extending  into the first quarter of 2001,
U.S.  Gulf Coast  fractionation  and pipeline  volumes  (including  those at the
Company's facilities) declined.  This situation,  however, also created regional
shortages of NGLs, especially propane,  which resulted in large regional pricing
differences.  This  provided  the  Company  with  opportunities  to serve  these
supply-short  markets  through the sale of inventory by its Processing  merchant
business.


                                       26
<PAGE>

         Management  believes  that  the gas  processing  business  will  have a
challenging  first quarter of 2001.  The current  processing  environment  does,
however, present opportunities to take advantage of the Company's integrated NGL
system.  Looking  back over the last year,  the  Company's  NGL  production  has
significantly  increased over 1999 levels as a result of steadily growing levels
of natural gas production  available for processing,  higher NGL content natural
gas and new processing  facilities such as the Company's Neptune plant.  Neptune
commenced  operations in February 2000 and added  approximately 7 MBPD of equity
NGL production for the year.  For 2000,  equity NGL production  averaged 72 MBPD
versus  67 MBPD in 1999.  Management  believes  that the  Company's  equity  NGL
production  volumes  will  continue  to  increase  in  2001 as a  result  of gas
production from several new Gulf of Mexico gas fields  scheduled to come on-line
in which the Company holds gas processing  rights, the most significant of which
is Shell's deepwater Brutus  development (with an expected equity NGL production
of 10 MBPD by the end of  2001).  Management's  belief  is  based in part on the
premise that natural gas prices will continue to moderate over the coming months
(see First Quarter 2001 natural gas prices in the table on page 29); however, if
fuel  costs  return to the  record  levels  seen in  January  2001,  equity  NGL
production rates may actually decline in 2001.

         The highly competitive  environment in which the Company's Mont Belvieu
NGL fractionators  operate has continued to suppress NGL  fractionation  fees at
these facilities.  The Company has and is continuing to aggressively acquire new
and  reacquire  previous  NGL  fractionation  customers,   along  with  offering
competitively-priced   bundled  service   packages   involving   transportation,
fractionation  and other services.  These service  packages allow the Company to
take advantage of its presence throughout the entire Gulf Coast NGL value chain.
As a result of these efforts,  gross processing  volumes at the Mont Belvieu NGL
fractionation facility increased to 170 MBPD in 2000 from 156 MBPD in 1999. With
the  completion of the Lou-Tex NGL Pipeline in the fourth  quarter of 2000,  the
Company is  positioned  to fully  utilize  its Mont  Belvieu  NGL  fractionation
facilities  to process  NGL's from  Louisiana  starting in the first  quarter of
2001.  In  January  2001,  the  Company  announced  that it had  entered  into a
long-term  agreement  to exchange  NGLs  produced  at the Sea Robin  natural gas
processing plant in Vermilion  Parish,  Louisiana,  for finished NGL products at
Mont Belvieu using the Lou-Tex NGL Pipeline.  Initial gross  processing  volumes
are  expected to be 16 MBPD and are  forecast to increase to over 20 MBPD by the
end of 2001.

         The demand  for  commercial  isomerization  services  depends  upon the
industry's  requirements  for (i)  isobutane  in excess of  naturally  occurring
isobutane produced from NGL fractionation and refinery  operations and (ii) high
purity isobutane. The market for the Company's services was firm throughout most
of  2000  due to the  continued  need  for  isobutane  for  alkylation  and  the
production of propylene oxide and MTBE. As part of its commercial  isomerization
business,  the Company produces the high purity isobutane used in the production
of MTBE  at the BEF  facility.  Isobutane  demand  from  the  BEF  facility  was
temporarily  curtailed due to a maintenance  outage at the MTBE plant that began
in early December 2000. With the startup of the BEF plant in mid-February  2001,
management anticipates that the demand for its commercial isomerization services
will return to normal levels.

         During  the  third  quarter  of 2000,  the  rapid  price  increase  for
propylene experienced during the first half of 2000 began to reverse. During the
first half,  propylene prices were driven by the dramatic increases in crude oil
and NGL prices.  These factors  contributed to similar increases in the cost for
ethylene and  propylene  from steam  crackers and for refinery  grade  propylene
produced by refineries. In addition, the price spike in motor gasoline,  natural
gas and propane created a very  competitive  market for refinery grade propylene
which is used in the  production  of  alkylate  (which  is  blended  into  motor
gasoline), substituted for natural gas as refinery fuel and blended into propane
streams for the fuels market. With the perceived  stabilization and softening in
crude oil and natural  gas prices,  propylene  buyers  have been  successful  in
achieving  price  reductions  by reducing  purchases  and  consuming  inventory.
Contract prices for polymer grade propylene  increased from  approximately  19.5
cents per pound at the  beginning  of 2000 to 27.5 cents per pound by the end of
June. By the end of December,  the contract  price had slipped to 23.5 cents per
pound.  Management anticipates that prices will continue to soften in early 2001
with the price  leveling out to that seen at the beginning of 2000.  The Company
is exposed to these price  decreases  only to the extent  that it sells  product
pursuant to long-term  agreements having market-based pricing or transactions on
the spot market (see page 8 for a  discussion  of  propylene  merchant  business
contracts).

         During 2000, the favorable domestic economy supported strong demand for
the Company's  pipeline  transportation  services as NGL feedstocks and products
were consumed at record levels  throughout the Gulf Coast region.  The Company's
pipeline  volumes  increased  significantly to 367 MBPD in 2000 from 264 MBPD in


                                       27
<PAGE>

1999 primarily due to volumes  attributable  to the assets  acquired in the TNGL
acquisition,  the purchase of the Lou-Tex  Propylene  Pipeline in March 2000 and
the  completion  of the Lou-Tex NGL Pipeline in November  2000.  As noted above,
pipeline  volumes  weakened as NGL  production  from gas  processing  facilities
decreased  in late 2000 and January  2001 in  reaction  to the high  natural gas
prices.  This trend  began to reverse  itself in  February  2001 as natural  gas
prices  declined  and  processing   volumes  at  the  Company's  gas  processing
facilities increased.

         The  Company  anticipates  using the  Lou-Tex  NGL  Pipeline to provide
transportation  services for NGL products  and mixed  propane/propylene  streams
between  the  Louisiana  and Texas  markets  in  addition  to  transporting  NGL
production  from  Louisiana  gas  processing  facilities  to  Mont  Belvieu  for
fractionation.  Management  believes  that the  Company's  pipeline  system  and
storage  assets  in the  Louisiana  to  Mont  Belvieu,  Texas  corridor  and its
import/export  terminal on the Houston Ship Channel provide the Company with the
infrastructure for continued success in the NGL marketplace.

         During the second quarter of 2000,  BEF's MTBE  operations  (classified
under the "Octane Enhancement" business segment) benefited from higher crude oil
prices  as  well  as a  tight  international  MTBE  supply  environment.  Due to
contractual arrangements, BEF began selling its MTBE at market-related prices in
April 2000 at a time when MTBE market prices were increasing  significantly  due
to their  indirect link to crude oil prices (which were on the  increase),  MTBE
supply  imbalances  between  Europe and the United  States (due to the temporary
diversion  of Middle  East MTBE  production  to Europe)  and  domestic  gasoline
refining  demand in  anticipation  of the  normal  summer  driving  season.  The
combination  of these  external  factors  resulted in the market  price for MTBE
increasing  to near record  levels in the second  quarter of 2000  peaking at an
average $1.58 per gallon in June.  During the third quarter,  MTBE market prices
deflated  rapidly as imports  returned  to the  domestic  market and as gasoline
refiners  trimmed  oxygenate usage (due to the end of the summer driving season)
and depleted MTBE  inventories in anticipation  of falling crude oil prices.  By
October 2000, MTBE prices had hit a low of $0.98 per gallon.

         As MTBE prices weakened during the latter half of 2000, feedstock costs
began to increase  (primarily  due to the rise in natural  gas prices  mentioned
previously)  resulting  in negative  operating  margins.  In order to reduce its
exposure to negative  margins,  BEF  management  elected to  reschedule  routine
annual maintenance activities that had been originally planned for the spring of
2001 to be  performed  during  December  2000 and  January  2001.  The  facility
restarted  operations in mid-February 2001 with the return of positive operating
margins. Management anticipates that MTBE prices will strengthen in the next few
months as refiners begin  purchasing  MTBE in  preparation of gasoline  blending
requirements for the upcoming summer driving season.


















                                       28
<PAGE>
         The following table  illustrates  selected average quarterly prices for
natural gas, crude oil,  selected NGL products and polymer grade propylene since
the first quarter of 1999:
<TABLE>
<CAPTION>

                                                                                                   Polymer
                      Natural                                             Normal                    Grade
                        Gas,      Crude Oil,    Ethane,     Propane,     Butane,     Isobutane,  Propylene,
                      $/MMBtu      $/barrel    $/gallon     $/gallon     $/gallon     $/gallon     $/pound
                    -----------------------------------------------------------------------------------------
                        (a)          (b)          (a)         (a)          (a)          (a)          (a)
<S>                        <C>         <C>          <C>          <C>          <C>          <C>         <C>
Fiscal 1999:
   First quarter           $1.70       $13.05       $0.20        $0.24        $0.29        $0.31       $0.12
   Second quarter          $2.12       $17.66       $0.27        $0.31        $0.37        $0.38       $0.13
   Third quarter           $2.56       $21.74       $0.34        $0.42        $0.49        $0.49       $0.16
   Fourth quarter          $2.52       $24.54       $0.30        $0.41        $0.52        $0.52       $0.19
Fiscal 2000:
   First quarter           $2.49       $28.84       $0.38        $0.54        $0.64        $0.64       $0.21
   Second quarter          $3.41       $28.79       $0.36        $0.52        $0.60        $0.68       $0.26
   Third quarter           $4.22       $31.61       $0.40        $0.60        $0.68        $0.67       $0.26
   Fourth quarter          $5.22       $31.98       $0.49        $0.67        $0.75        $0.73       $0.24
Fiscal 2001:
   First quarter (c)       $8.02       $29.66       $0.44        $0.57        $0.67        $0.71       $0.23
------------------------------------------------------------------------------------------------------------
</TABLE>

     (a)  Natural  gas,  NGL and polymer  grade  propylene  prices  represent an
          average of index prices
     (b)  Crude Oil price is representative of West Texas Intermediate
     (c)  Natural  gas  prices  averaged  $9.87 per  MMBtu  during  January  and
          moderated to $6.17 per MMBtu during  February.  The first quarter 2001
          prices reflect January and February only.


Results of Operation of the Company

         The  Company has five  reportable  operating  segments:  Fractionation,
Pipeline,  Processing,  Octane Enhancement and Other. Fractionation includes NGL
fractionation,  butane isomerization  (converting normal butane into high purity
isobutane) and polymer grade propylene fractionation services. Pipeline consists
of pipeline,  storage and import/export  terminal services.  Processing includes
the natural gas  processing  business and its related NGL  merchant  activities.
Octane  Enhancement  represents  the  Company's  33.3%  ownership  interest in 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.

         The  management of the Company  evaluates  segment  performance  on the
basis of gross operating margin ("gross  operating  margin" or "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  selling,  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.  The Company's  equity earnings from
unconsolidated affiliates are included in segment gross operating margin.










                                       29
<PAGE>

         The  Company's  gross  operating  margin by segment  (in  thousands  of
dollars) along with a reconciliation  to consolidated  operating income over the
past three years were as follows:

<TABLE>
<CAPTION>
                                                               For the Year Ended December 31,
                                                    -------------------------------------------------------
                                                           2000              1999              1998
                                                    -------------------------------------------------------
<S>                                                         <C>               <C>               <C>
Gross Operating Margin by segment:
     Fractionation                                          $  129,376        $  110,424        $   66,627
     Pipeline                                                   56,099            31,195            27,334
     Processing                                                122,240            28,485              (652)
     Octane enhancement                                         10,407             8,183             9,801
     Other                                                       2,493               908            (3,483)
                                                    -------------------------------------------------------
Gross Operating Margin total                                   320,615           179,195            99,627
     Depreciation and amortization                              35,622            23,664            18,579
     Retained lease expense, net                                10,644            10,557            12,635
     Loss (gain) on sale of assets                               2,270               123              (276)
     Selling, general and administrative expenses               28,345            12,500            18,216
                                                    -------------------------------------------------------
Consolidated operating income                               $  243,734        $  132,351        $   50,473
                                                    =======================================================
</TABLE>

Certain  1999  amounts  have  been   reclassified   to  conform  with  the  2000
presentation.

         The Company's  significant  plant  production and other volumetric data
(in  thousands  of barrels per day on a net basis) for the last three years were
as follows:

<TABLE>
<CAPTION>
                                                               For the Year Ended December 31,
                                                    -------------------------------------------------------
                                                           2000              1999              1998
                                                    -------------------------------------------------------
<S>                                                                <C>               <C>                <C>
Plant production data:
        NGL Production                                              72                67                n/a
        NGL Fractionation                                          213               184                 73
        Isomerization                                               74                74                 67
        Propylene Fractionation                                     33                28                 26
        MTBE                                                         5                 5                  5
        Major Pipelines                                            367               264                200
</TABLE>

         In order to more  accurately  compare  operating rates between the 2000
and 1999 periods, the 1999 volumes associated with the assets acquired from TNGL
have been adjusted to reflect the period in which the Company owned them.

Recent Acquisitions

         1999 Acquisitions.  Effective August 1, 1999, the Company acquired TNGL
from an affiliate of Shell Oil Company.  TNGL engages in natural gas  processing
and NGL  fractionation,  transportation,  storage and marketing in Louisiana and
Mississippi. TNGL has varying interests in eleven natural gas processing plants,
four NGL fractionation  facilities,  four NGL storage facilities,  approximately
1,500 miles of pipelines and is party to the Shell  Processing  Agreement,  a 20
year natural gas processing agreement.  TNGL was purchased with a combination of
$166 million in cash and the issuance of 14.5 million non-distribution  bearing,
convertible  special partnership Units of the Limited Partner The $210.4 million
value of the special partnership Units was contributed by the Limited Partner to
the Company.

         As part of the  agreements  to purchase  TNGL from  Shell,  the Limited
Partner agreed to issue up to 6.0 million additional  non-distribution  bearing,
convertible special partnership Units to Shell provided that certain performance
criteria were met in calendar years 2000 and 2001. In general,  if Shell met the
performance  criteria  for 2000,  3.0 million of the special  partnership  Units
would be  issued;  likewise,  if Shell met the 2001  goals,  the  remaining  3.0
million special  partnership  Units would be issued.  The Limited Partner issued


                                       30
<PAGE>

3.0  million  special  partnership  Units  to Shell  in  August  2000 due to the
successful  completion of the 2000 performance  test. The $55.2 million value of
the new special  partnership Units was contributed by the Limited Partner to the
Company.

         The Company  accounted for this acquisition  using the purchase method.
The purchase price  allocation for the 20-year natural gas processing  agreement
(classified as an Intangible Asset on the balance sheet) was a net $84.6 million
and $52.9 million at December 31, 2000 and 1999, respectively.  During 2000, the
asset's  recorded  value was  increased  to reflect the 3.0  million  additional
special partnership Units issued to Shell on August 1, 2000, purchase accounting
adjustments and related amortization.

         Effective  July 1, 1999,  the  Company  acquired  an  additional  25.5%
interest in the Mont Belvieu NGL  fractionation  facility from Kinder Morgan and
EPCO  for a  purchase  price  of  approximately  $42  million  in  cash  and the
assumption  of $4 million in debt.  This  acquisition  (referred  to as the "MBA
acquisition") increased the Company's effective interest in the Mont Belvieu NGL
fractionation facility from 37.0% to 62.5%. As a result of this acquisition, the
results of operations after July 1, 1999 were consolidated  rather than included
in equity income from unconsolidated affiliates.

         The results of operations  for the year ended December 31, 1999 include
five month's impact of the TNGL  businesses  acquired from Shell and six month's
impact  of  the   additional   ownership   interest  in  the  Mont  Belvieu  NGL
fractionation  facility  acquired from Kinder Morgan and EPCO. See Note 2 to the
Consolidated   Financial  Statements  for  selected  pro  forma  financial  data
reflecting  these  transactions  as if they had  occurred on January 1, 1999 and
1998.

         2001 Acquisitions.  The Company has recently announced and/or completed
the acquisition of three Louisiana-based natural gas pipeline systems:

     -    Acadian Gas, LLC ("Acadian");
     -    Stingray   Pipeline   Company,   LLC  ("Stingray")  and  West  Cameron
          Dehydration, LLC ("West Cameron"); and
     -    Sailfish  Pipeline  Company,   LLC  ("Sailfish")  and  Moray  Pipeline
          Company, LLC ("Moray").

The  acquisition  of these natural gas pipeline  systems  represents a strategic
investment  for the Company and allows for entry into the natural gas gathering,
transportation,  marketing and storage business.  Management believes 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 extend the Company's  midstream  energy service  relationship  with
long-term NGL customers (producers,  petrochemical suppliers and refineries) and
offer additional fee-based cash flows and opportunities for enhanced services to
customers.

         Acadian.  On September  25,  2000,  the Company  announced  that it had
executed a  definitive  agreement  to purchase  Acadian  from Coral  Energy,  an
affiliate of Shell, for $226 million in cash,  inclusive of working capital. The
acquisition  of Acadian  integrates  its natural gas  pipeline  systems in South
Louisiana  with  the  Company's  Gulf  Coast  natural  gas  processing  and  NGL
fractionation,  pipeline and storage system.  The Acadian  acquisition gives the
Company an extensive  intrastate natural gas pipeline system with access to both
supply and markets; positions the Company to compete for incremental natural gas
supplies from new discoveries onshore, the offshore Louisiana  continental shelf
and Gulf of Mexico deepwater developments; enables the Company to take advantage
of growing  industrial and  petrochemical  demand (including new gas-fired power
generation projects) along with additional natural gas processing opportunities.

         Acadian's  assets  are  comprised  of the  438-mile  Acadian,  577-mile
Cypress and 27-mile Evangeline natural gas pipeline systems, which together have
over one billion  cubic feet  ("Bcf")  per day of  capacity.  These  natural gas
pipeline  systems  are  wholly-owned  by  Acadian  with  the  exception  of  the
Evangeline system in which Acadian holds an approximate 49.5% economic interest.
The system  includes a leased  natural  gas storage  facility at  Napoleonville,
Louisiana.  Completion  of this  transaction  is subject to certain  conditions,
including regulatory approvals.  The purchase is expected to be completed during
the first quarter of 2001.

         Stingray, West Cameron, Sailfish and Moray (collectively,  the "El Paso
acquisition"). On January 29, 2001, the Company completed the purchase of 50% of
the  membership  interests  of Stingray  and West  Cameron,  together  with some


                                       31
<PAGE>

offshore  lateral  pipelines  for  approximately  $25.1  million  in  cash  from
affiliates  of El Paso Energy  Partners  L.P.  ("EPE") and Coastal  Corp.  Shell
purchased  the  remaining  50%  membership  interests of both  Stingray and West
Cameron for an equal amount of cash. In addition, the Company purchased from EPE
100% of the membership  interests of Sailfish and Moray for approximately  $88.1
million in cash.

         Collectively,  the  Company  acquired  interests  in five  natural  gas
gathering  and  transmission  pipeline  systems  in the Gulf of Mexico  totaling
approximately  737 miles of pipeline  with an aggregate  gross  capacity of 2.85
Bcfd. These pipelines and their associated assets are  strategically  located to
serve  continental  shelf and  deepwater  developments  in the  central  Gulf of
Mexico. As with the Acadian  acquisition,  the El Paso acquisition  broadens the
Company's midstream business by providing additional services to customers,  and
it benefits from increased  natural gas production from deepwater Gulf of Mexico
development.  Management  believes that the assets  acquired from EPE complement
and integrate well with those of the Acadian acquisition.

         Stingray owns a 375-mile  FERC-regulated two phase natural gas pipeline
system that transports natural gas and injected condensate from the High Island,
West  Cameron,  East Cameron,  Vermillion  and Garden Banks areas in the Gulf of
Mexico to  onshore  transmission  systems  at Holly  Beach and  Cameron  Parish,
Louisiana.  West Cameron is an unregulated  dehydration  facility located at and
connected  to the onshore  terminal of  Stingray.  Shell is the  operator of the
Stingray and West Cameron facilities.

         Sailfish  owns a  25.67%  interest  in  Manta  Ray  Offshore  Gathering
Company,   L.L.C.   ("Manta  Ray")  and  Nautilus   Pipeline   Company,   L.L.C.
("Nautilus"). Moray owns a 33.92% interest in the Nemo Gathering Company, L.L.C.
("Nemo").  Manta Ray (which is jointly  owned by  Sailfish,  Shell  Marathon Gas
Transmission   Company  Inc.)  owns  237  miles  of   unregulated   natural  gas
transmission  lines primarily  located on the outer  continental  shelf offshore
Louisiana. Nautilus (which is owned by Sailfish, Shell and Marathon Transmission
Company Inc.) owns 101 miles of FERC-regulated natural gas pipelines and related
facilities extending from points offshore Louisiana to interconnecting pipelines
near the Garden  City and  Neptune  gas  processing  facilities.  Nemo (which is
jointly  owned by Moray and Shell) is a  development  stage  enterprise  that is
constructing  and will  operate an  offshore  Louisiana  natural  gas  gathering
pipeline  and  related  facilities  that will  connect  certain  Shell  offshore
platform  assets to Manta Ray.  Management  believes  that these  assets  have a
significant upside potential, since Shell and Marathon have dedicated production
from over 1,000 square miles of offshore natural gas leases to these systems and
only a small  portion of this  total has been  developed  to date.  Shell is the
operator of the Manta Ray, Nautilus and Nemo systems.

         Equistar  storage  facility.  In addition  to the natural gas  pipeline
acquisitions,  the Company  announced on February 1, 2001 that it had acquired a
NGL storage facility from Equistar Chemicals, LP for approximately $3.4 million.
The salt dome storage cavern,  which is located near the Company's Mont Belvieu,
Texas complex, has a capacity of one million barrels. The purchase also includes
adjacent  acreage which would  support the  development  of  additional  storage
capacity.

Year Ended December 31, 2000 Compared to Year Ended December 31, 1999

         Revenues,  Costs and  Expenses  and  Operating  Income.  The  Company's
revenues increased 128% to $3,073.1 million in 2000 compared to $1,346.5 million
in 1999.  The  Company's  operating  costs  and  expenses  increased  by 133% to
$2,801.1  million in 2000  versus  $1,201.6  million in 1999.  Operating  income
increased  84% to  $243.7  million  in 2000 from  $132.3  million  in 1999.  The
principal  factors  behind  the  increase  in  operating  income  were  (a)  the
improvement  in NGL product  prices in 2000  versus 1999 and (b) the  additional
margins  associated with the businesses  acquired in the TNGL  acquisition.  The
1999 period includes five months of margins  associated with the TNGL operations
whereas the 2000 period includes twelve months.

         Fractionation.   The   Company's   gross   operating   margin  for  the
Fractionation segment increased to $129.4 million in 2000 from $110.4 million in
1999. During 2000, NGL fractionation margin increased $29.7 million over 1999 as
a result of  additional  margins from the four NGL  fractionators  acquired from
Shell  in  the  TNGL  acquisition   (Promix,   Tebone,   Venice  and  Norco  NGL
fractionators).  As noted previously,  the 1999 period includes only five months
of margin  from these  fractionators  whereas the 2000  period  includes  twelve
months. In addition, equity income from BRF reflects twelve months of operations
in 2000 versus six months in 1999.  BRF commenced  operations in July 1999.  Net
NGL  fractionation  volumes  increased from 184 MBPD in 1999 to 213 MBPD in 2000


                                       32
<PAGE>

primarily due to the Company's  acquisition of new and previous customers at its
Mont Belvieu NGL  fractionator  in 2000 and the increased  ownership of the Mont
Belvieu NGL  fractionator as a result of the MBA  acquisition.  For 2000,  gross
operating margin from the isomerization business decreased $7.8 million compared
to 1999  primarily  due to higher  fuel and other  operating  costs and  charges
related to the  refurbishment of an isomerization  unit.  Isomerization  volumes
were 74 MBPD in both  1999 and  2000  due to  strong  demand  for the  Company's
services.  Gross operating  margin from propylene  fractionation  decreased $1.4
million for 2000 compared to 1999  primarily  due to higher  energy  costs.  Net
volumes at these  facilities  improved to 33 MBPD in 2000 versus 28 MBPD in 1999
due to the startup of the BRPC propylene concentrator in July 2000.

         Pipeline. The Company's gross operating margin for the Pipeline segment
was $56.1  million in 2000 compared to $31.2  million in 1999.  Overall  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
Houston Ship Channel  Distribution  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. On
February 25, 2000,  the purchase of the Lou-Tex  Propylene  Pipeline and related
assets from  Concha  Chemical  Pipeline  Company,  an  affiliate  of Shell,  was
completed at a cost of  approximately  $100 million.  The effective  date of the
transaction was March 1, 2000. The Lou-Tex Propylene Pipeline is a 263-mile, 10"
pipeline that transports  chemical grade  propylene from Sorrento,  Louisiana to
Mont Belvieu, Texas. Also acquired in this transaction was a 27.5-mile 6" ethane
pipeline between Sorrento and Norco,  Louisiana and a 0.5 million barrel storage
cavern at Sorrento, Louisiana.

         The  Lou-Tex  NGL  Pipeline  System  consists  of a recently  completed
206-mile  NGL  pipeline  used (i) to  provide  transportation  services  for NGL
products and refinery  grade  propylene  between the Louisiana and Texas markets
and (ii) to transport  mixed NGLs from the Company's  Louisiana  gas  processing
facilities to the Mont Belvieu NGL fractionation facility.  Construction of this
system  was  completed   during  the  fourth  quarter  of  2000  at  a  cost  of
approximately $87.9 million.

         Processing.  The Company's  gross  operating  margin for Processing was
$122.2  million  in 2000  compared  to $28.5  million  in 1999.  Due to the TNGL
acquisition,  the 1999  margin  includes  only  five  months  of gas  processing
operations  whereas  the  2000  period  includes  twelve  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.

         Octane  Enhancement.  The Company's gross  operating  margin for Octane
Enhancement  increased to $10.4 million in 2000 from $8.2 million in 1999.  This
segment  consists  entirely  of the  Company's  equity  earnings  from its 33.3%
investment in BEF, a joint venture  facility that  currently  produces MTBE. The
1999 results  include the impact of the Company's $1.5 million pro rata share of
a non-cash  write-off of BEF's  unamortized  balance of deferred start-up costs.
The 2000  results  reflect the impact of higher  than normal MTBE market  prices
during the second  quarter and early third quarter and lower debt service costs.
BEF made  its  final  note  payment  in May 2000 and now owns the MTBE  facility
debt-free.

         The MTBE facility was  temporarily  shutdown in early December 2000 for
maintenance.  The facility  restarted  operations  in  mid-February  2001.  MTBE
production, on a net basis, was 5 MBPD in both 1999 and 2000.

         Other.  The Company's gross operating  margin for the Other segment was
$2.5 million in 2000 compared to $0.9 million in 1999. The increase is primarily
due to fee-based  marketing  services added in the fourth quarter of 1999. Apart
from this portion of the segment's operations,  the gross margin contribution of
the other aspects of this segment were insignificant in both 2000 and 1999.

         Selling,  general and administrative  expenses ("SG&A").  SG&A expenses
increased to $28.3  million in 2000 from $12.5 million  during 1999.  The higher
costs result from an increase in the administrative services fee charged by EPCO
to an average  $1.2  million  per month in 2000  versus the  approximately  $1.0
million per month charged in 1999. The remainder of the increase is attributable


                                       33
<PAGE>

to the additional  staff and resources deemed necessary to support the Company's
ongoing  expansion  activities  resulting from  acquisitions  and other business
development.

         Interest  expense.  The Company's  interest expense  increased to $33.3
million  in  2000  from  $16.4  million  in  1999.  The  increase  is  primarily
attributable  to a rise in average debt levels to $408 million in 2000 from $213
million in 1999.  Debt levels have increased over the last year primarily due to
capital  expenditures  for assets such as the  Lou-Tex  Propylene  Pipeline  and
Lou-Tex NGL Pipeline.

         Loss on sale of assets.  During the second quarter of 2000, the Company
recognized a one-time $2.3 million  non-cash  charge on the sale of its Longview
Terminal  to  Huntsman  Corporation.  The  Longview  Terminal  was  part  of the
Pipelines  segment and was used to unload polymer grade  propylene from NGL tank
trucks.

         Dividend income from  unconsolidated  affiliates.  The Company received
$7.1  million in cash  distributions  from its cost method  investment  in VESCO
during 2000.  During 1999, the Company  recorded  dividend income from Dixie and
VESCO in the amounts of $0.8 million and $2.6 million,  respectively. In October
2000,  the Company  purchased  an  additional  interest in Dixie  resulting in a
retroactive change in accounting for this investment from the cost method to the
equity method (see Note 4 of the Notes to the Consolidated  Financial Statements
for a description of the Dixie investment).

Year Ended December 31, 1999 Compared to Year Ended December 31, 1998

         Revenues,  Costs and  Expenses  and  Operating  Income.  The  Company's
revenues increased 78% to $1,346.5 million in 1999 compared to $754.6 million in
1998. The Company's  operating  costs and expenses  increased by 75% to $1,201.6
million in 1999 versus $685.9 million in 1998.  Operating  income increased 162%
to $132.3  million in 1999 from  $50.5  million in 1998.  The  principal  factor
behind the $81.8 increase in operating income was the TNGL acquisition. Earnings
attributable  to these  assets  from the date of  acquisition,  August 1,  1999,
through December 31, 1999 added  approximately  $48.4 million in gross operating
margin to the Company's financial  performance.  The other primary source of the
increase was an overall  improvement  in NGL product  prices in 1999 compared to
1998 levels.

         Fractionation.   The   Company's   gross   operating   margin  for  the
Fractionation  segment increased to $110.4 million in 1999 from $66.7 million in
1998. NGL fractionation  margin increased $13.7 million over 1998 as a result of
additional margins from the four TNGL  fractionators.  As noted previously,  the
1999 period includes five months of margin from these NGL fractionators  whereas
the 1998 period includes none. In addition,  the 1999 period reflects six months
of increased ownership of the Mont Belvieu NGL fractionation  facility resulting
from the MBA  acquisition  and six  months  of  equity  income  from  BRF  which
commenced operations in July 1999. Net NGL fractionation  volumes increased from
73  MBPD in  1998  to 184  MBPD  primarily  due to the  TNGL  fractionators  and
increased  ownership of the Mont Belvieu NGL  fractionator.  During 1999,  gross
operating  margin from  isomerization  increased $19.6 million  compared to 1998
levels  due to  exceptional  pricing  conditions  in the first  half of 1999 and
higher overall production.  Isomerization volumes increased from 67 MBPD in 1998
to 74  MBPD  in  1999.  Gross  operating  margin  from  propylene  fractionation
increased  $11.2 million over 1998 levels  generally due to increases in polymer
grade propylene prices and higher production rates.  Volumes at these facilities
improved to 28 MBPD in 1999 versus 26 MBPD in 1998.

         Pipeline.  The Company's 1999 gross  operating  margin for the Pipeline
segment  increased $3.9 million compared to 1998.  Overall volumes  increased to
264 MBPD in 1999  from 200 MBPD in 1998.  Of the  increase  in both  margin  and
volumes,  $4.7 million in margin and approximately 56 MBPD in throughput volumes
are  attributable to the TNGL pipeline and related assets.  In addition,  equity
income from EPIK increased $0.4 million due to increased export volumes. Margins
from  the  Company's   Houston  Ship  Channel   import   terminal  and  pipeline
distribution system decreased $2.0 million in 1999 primarily due to lower import
volumes.

         Processing.  The Company's 1999 gross  operating  margin for Processing
increased $29.1 million over 1998 results.  The increase is primarily due to the
gas processing  operations  acquired from TNGL effective August 1, 1999. The gas
processing  operations benefited from a favorable NGL pricing environment during
the fourth quarter of 1999 and 67 MBPD of equity NGL production.



                                       34
<PAGE>

         Octane  Enhancement.  The  Company's  1999 gross  operating  margin for
Octane  Enhancement  decreased  $1.6 million  from 1998 levels.  The decrease is
attributable  to a $4.5 million  non-cash charge by BEF in January 1999 of which
the Company's  share was $1.5 million.  MTBE net production  volumes  averaged 5
MBPD in both 1999 and 1998.

         Other.  The Company's 1999 gross operating margin for the Other segment
increased $4.4 over 1998 levels.  The increase is  attributable to the fee-based
marketing  business acquired from TNGL. Apart from this portion of the segment's
operations,  the gross margin  contribution of the other aspects of this segment
were insignificant in both 1999 and 1998.

         Selling,  general  and  administrative  expenses  ("SG&A").  1999  SG&A
expenses  decreased by $5.7 million  compared to 1998.  The 1999  expenses  were
lower due to the fixed administrative fees charged to the Company under the EPCO
Agreement.  The fixed  administrative  service fees partially reimburse EPCO for
the cost of providing  certain  management  and  administrative  support for the
Company.  During 1999, these fixed fees ranged from $1.0 million to $1.1 million
per  month.  The  Audit  and  Conflicts  Committee  of the  General  Partner  is
responsible   for   reviewing  and  approving  any  increases  in  the  standard
administrative   fees  chargeable  by  EPCO  to  the  Company.   For  additional
information regarding the EPCO Agreement, see page 50 of this Form 10-K.

         Interest  expense.  The Company's 1999 interest expense  increased $1.3
over 1998 primarily due to the amortization of loan origination  costs.  Average
debt levels in 1999 were generally consistent with those of 1998.

         Dividend income from unconsolidated affiliates. As a result of the TNGL
acquisition,  the Company owned cost method  investments in Dixie and VESCO.  As
such,  the  Company  recorded  dividend  income from these  investments  as cash
dividends were received.  During 1999, the Company recorded dividend income from
Dixie and VESCO in the amounts of $0.8 million and $2.6 million, respectively.

         Extraordinary  charge  on early  extinguishment  of debt.  The  Company
incurred a $27.2 million  extraordinary loss during the third quarter of 1998 in
connection with the early extinguishment of debt assumed from EPCO in connection
with the Company's initial public offering.  The extraordinary loss was equal to
the remaining  unamortized debt origination  costs associated with such debt and
make-whole premiums payable in connection with the repayment of such debt.


Liquidity and Capital Resources

         General

         The  Company's  primary  cash  requirements,   in  addition  to  normal
operating  expenses,   are  for  capital   expenditures  (both  maintenance  and
expansion-related),  business  acquisitions,  distributions  to the partners and
debt service. The Company expects to fund its short-term needs for such items as
maintenance  capital  expenditures  and quarterly  distributions to the partners
from operating cash flows.  Capital  expenditures  for long-term needs resulting
from future  expansion  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,
the issuance of additional public debt and contributions from its partners.  The
Company's debt service  requirements are expected to be funded by operating cash
flows or refinancing arrangements.

         As noted above, certain of the Company's liquidity and capital resource
requirements are met using borrowings  under bank credit  facilities  and/or the
issuance  of  additional  public  debt  (separately  or in  combination).  As of
December 31, 2000,  availability  under the Company's bank credit facilities was
$400 million (which may be increased to $500 million under certain  conditions).
In addition to the  existing  bank credit  facilities,  the Company  issued $450
million of public debt in January 2001 using the  remaining  shelf  availability
under its $800 million December 1999 universal shelf registration (the "December
1999 Registration  Statement").  The proceeds from this offering were or will be
used to acquire the Acadian  and EPE  natural  gas  pipeline  systems for $339.2
million and to finance the cost to construct  certain NGL  pipelines and related
projects and for working capital and other general  partnership  purposes.  $350
million of shelf availability under the December 1999 Registration Statement was
used in March 2000 with the issuance of the $350 Million Senior Notes.



                                       35
<PAGE>

         On February  23,  2001,  the Company and Limited  Partner  filed a $500
million   universal  shelf   registration   (the  "February  2001   Registration
Statement")  covering  the issuance of an  unspecified  amount of equity or debt
securities or a combination  thereof.  For a broader discussion of the Company's
outstanding debt and changes therein,  see the section below labeled  "Long-term
Debt".

         In  June  2000,  the  Limited  Partner   received   approval  from  its
Unitholders to increase by 25,000,000 the number of Common Units  available (and
unreserved) for general  partnership  purposes during its subordination  period.
This  increase  has  improved the future  financial  flexibility  of the Limited
Partner to  contribute  cash and/or  other  assets to the  Company for  business
expansions and acquisitions.

         If deemed  necessary,  management  believes that  additional  financing
arrangements  can be obtained at  reasonable  terms.  Management  believes  that
maintenance of the Company's investment grade credit ratings (currently, Baa3 by
Moody's  Investor  Service  and  BBB by  Standard  and  Poors)  combined  with a
continued  ready  access to debt (and  equity-sourced  capital  from its Limited
Partner)  at  reasonable  rates  and  sufficient  trade  credit to  operate  its
businesses  efficiently  are a solid  foundation  to providing  the Company with
ample resources to meet its long and short-term  liquidity and capital  resource
requirements.

         Operating,  Investing and Financing Cash Flows for Years Ended December
         31, 2000 and 1999

         Cash flows from  operating  activities  were a $358.8 million inflow in
2000  compared to a $178.0  million  inflow in 1999.  Cash flows from  operating
activities  primarily  reflect  the  effects  of net  income,  depreciation  and
amortization,   extraordinary   items,  equity  income  and  distributions  from
unconsolidated  affiliates and changes in working capital.  Net income increased
significantly  in 2000  over  1999 due to  reasons  mentioned  previously  under
"Results of Operation of the Company."  Depreciation  and  amortization  expense
increased a combined  $15.7  million in 2000 over 1999  primarily  the result of
additional capital expenditures and acquisitions. Of the $15.7 million increase,
$4.9 million is  attributable to increases in  amortization  expense  associated
with the 20-year Shell natural gas processing agreement,  excess cost related to
past  acquisitions  and loan  origination  and bond  issue  costs.  The  Company
received $37.3 million in  distributions  from its equity method  investments in
2000  compared  to $6.0  million  in 1999.  Of the  $31.3  million  increase  in
distributions,   $10.0  million  was  from  BEF  and  $8.1  million  from  EPIK.
Distributions  from BEF improved  period to period due to the strong MTBE prices
and margins during the second quarter of 2000. EPIK's distributions increased as
a result of higher export activity during 2000. In addition,  2000 included $7.0
million in cash  receipts from Promix which was acquired as a result of the TNGL
acquisition.  The net effect of changes in operating  accounts from year to year
is generally the result of timing of NGL sales and purchases near the end of the
period.

         Cash used for investing  activities was $268.8 million in 2000 compared
to $271.2 million in 1999. Cash outflows included capital expenditures of $243.9
million in 2000  versus  $21.2  million in 1999.  Capital  expenditures  in 2000
include  $99.5  million for the purchase of the Lou-Tex  Propylene  Pipeline and
related  assets and $83.7  million in  construction  costs for the  Lou-Tex  NGL
Pipeline. In addition,  capital expenditures include maintenance capital project
costs of $3.5 million in 2000 and $2.4 million in 1999. The 1999 period reflects
$208.1   million  in  net  cash  payments   resulting  from  the  TNGL  and  MBA
acquisitions.  In 2000,  the Company  received $6.5 million in payments from its
participation  in the BEF note that was purchased  during 1998 with the proceeds
from the Company's IPO. BEF made its final note payment in May 2000.  With BEF's
final payment, the Company's receivable relating to its participation in the BEF
note was extinguished.

         Investing  cash  outflows in 2000 include  $31.5 million in advances to
and investments in unconsolidated  affiliates compared to $61.9 million in 1999.
The  decrease is  primarily  due to the  completion  of the BRF facility and the
Tri-States  and  Wilprise  pipeline  systems  in 1999.  On March  8,  2000,  the
Company's  offer of  February  23,  2000 to buy the  remaining  88.5%  ownership
interests in Dixie from the other seven owners  expired,  with no interest being
purchased. In October 2000, the Company announced that a wholly-owned subsidiary
had  purchased an  additional  3,521 shares of common stock of Dixie from Conoco
for approximately  $19.4 million.  The purchase increased the Company's economic
interest in Dixie to approximately 19.9%.

         Cash flows from financing  activities  were a $36.7 million  outflow in
2000  compared to a $74.2  million  inflow for 1999.  Cash flows from  financing
activities are primarily  affected by repayments of debt,  borrowings under debt


                                       36
<PAGE>

agreements and  distributions to partners.  2000 includes proceeds from the $350
Million Senior Notes and the $54 Million MBFC Loan and the associated repayments
on the $200 Million Bank Credit Facility and $350 Million Bank Credit  Facility.
For a complete  discussion of the $350 Million  Senior Notes and the $54 Million
MBFC Loan and the use of proceeds  thereof,  see the section labeled  "Long-term
Debt" below. Financing activities in 1999 include the borrowings associated with
the TNGL and MBA  acquisitions  and  outflows  of $4.7  million  related  to the
purchase of the Limited  Partner's  Common Units by a consolidated  trust.  Debt
issuance  costs  increased  $0.9 million in 2000 due to the issuance of the $350
Million  Senior Notes and the $54 Million MBFC Loan.  Distributions  to partners
and the  minority  interest  increased  to $141.6  million  in 2000 from  $113.0
million in 1999  primarily  due to an  increase  in the  quarterly  distribution
requirements of the Limited Partner.

         In July 2000, the Limited  Partner  announced a 1,000,000 Unit buy-back
program  of its  publicly-owned  Common  Units to be  executed  over a  two-year
period.  The redemption  program will be funded by increased cash  distributions
from the  Company.  The  Company  will fund the higher  distribution  rates from
operating cash flows and  borrowings  under its bank credit  facilities.  During
2000,  28,400  Common Units were  repurchased  and retired  under this  buy-back
program at a cost of approximately $0.8 million.

         The Company is exposed to various market risks including  interest rate
and commodity  price risk through its gas processing and related NGL businesses.
These  risks may entail  significant  cash  outlays  in the future  that are not
offset by their underlying hedged positions.  For a complete  description of the
Company's  risk  management  policies  and  potential  exposures,  see "Item 7A.
Quantitative and Qualitative  Disclosures  about Market Risk" on page 42 of this
Form 10-K report.

         Future Capital Expenditures

          The Company  estimates  that its share of currently  approved  capital
expenditures  in  the  projects  of  its   unconsolidated   affiliates  will  be
approximately $3.1 million during 2001. In addition,  the Company forecasts that
$128.8 million will be spent during 2001 on currently  approved capital projects
that will be recorded as property,  plant and  equipment  (the majority of which
relate to various pipeline projects).

         As of December 31, 2000,  the Company had $10.9 million in  outstanding
purchase commitments attributable to its capital projects. Of this amount, $10.1
million  is related  to the  construction  of assets  that will be  recorded  as
property,  plant and  equipment  and $0.8  million is  associated  with  capital
projects  which will be recorded as  additional  investments  in  unconsolidated
affiliates.

         New Texas environmental  regulations may necessitate extensive redesign
and  modification  of the Company's  Mont Belvieu  facilities to achieve the air
emissions  reductions  needed  for  federal  Clean  Air  Act  compliance  in the
Houston-Galveston  area.  Until  litigation  challenging  these  regulations  is
resolved,  the  technology  to be  employed  and  the  cost  for  modifying  the
facilities to achieve enough reductions cannot be determined,  and capital funds
have  not been  budgeted  for  such  work.  Regardless  of the  outcome  of this
litigation,  expenditures for emissions  reduction  projects will be spread over
several years, and management  believes the Company will have adequate liquidity
and capital  resources to undertake them. For additional  information about this
litigation, see the discussion under the topic Clean Air Act--General on page 22
of this Form 10-K.
















                                       37
<PAGE>

         Long-term Debt

         Long-term debt consisted of the following at:

<TABLE>
<CAPTION>
                                                                 December 31,
                                                    ---------------------------------------
                                                           2000                1999
                                                    ---------------------------------------
<S>                                                             <C>                <C>
Borrowings under:
     $200 Million Bank Credit Facility (1)                                     $   129,000
     $350 Million Bank Credit Facility (1)                                         166,000
     $350 Million Senior Notes (2)                          $   350,000
     $54 Million MBFC Loan (3)                                   54,000
                                                    ---------------------------------------
            Total                                               404,000            295,000
Less current maturities of long-term debt                                          129,000
                                                    ---------------------------------------
            Long-term debt (4)                              $   404,000        $   166,000
                                                    =======================================
</TABLE>
               Notes to long-term debt table:
(1)      Revolving credit facility closed as of December 31, 2000.
(2)      8.25% fixed-rate, due March 2005
(3)      8.70% fixed-rate, due March 2010
(4)      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,  2000.  See  below  for a
         complete description of these new facilities.

         At December 31, 2000, the Company had a total of $50 million of standby
letters of credit  available under its $250 Million  Multi-Year  Credit Facility
(described  below)  of which  none  were  outstanding  under  letter  of  credit
agreements with the banks.

         On January 24, 2001,  the Company  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 "$450  Million
Senior Notes"). The Company received proceeds, net of underwriting discounts and
commissions,  of approximately  $446.8 million.  As noted earlier,  the proceeds
from this  offering  were or will be used to acquire the Acadian and EPE natural
gas  pipeline  systems for $339.2  million and to finance the cost to  construct
certain NGL  pipelines  and related  projects and for working  capital and other
general partnership purposes.

         The Company expects to use the net proceeds from any sale of securities
under the February 2001 Registration  Statement 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 of the Limited Partner 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  the  Company's  funding  requirements  and the
availability  of alternative  funding  sources.  The Company  routinely  reviews
acquisition opportunities.

         Description of Bank Credit Facilities, Senior Notes and other loans

         $200  Million  Bank  Credit  Facility.  On July 27,  1998,  the Company
entered  into a $200 million bank credit  facility  that  included a $50 million
working capital facility and a $150 million revolving credit facility.  On March
15, 2000, the Company used $169 million of the proceeds from the issuance of the
$350 Million Senior Notes to retire this credit  facility in accordance with its
agreement with the banks.

         $350  Million  Bank  Credit  Facility.  On July 28,  1999,  the Company
entered  into a $350 Million Bank Credit  Facility  that  included a $50 million
working  capital  facility,  a $300  million  revolving  credit  facility  and a
sublimit  of $40  million for letters of credit.  On  November  17,  2000,  this
facility was retired using funds  available under the Company's new $150 Million
364-Day Credit Facility  (described below) in accordance with its agreement with
the banks.

         $350 Million Senior Notes.  On March 13, 2000, the Company  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 Company received proceeds, net of underwriting discounts and commissions, of


                                       38
<PAGE>

approximately  $347.7  million.  The  proceeds  were used to pay the entire $169
million  outstanding  principal balance on the $200 Million Bank Credit Facility
and $179 million of the then $226 million  outstanding  principal balance on the
$350 Million Bank Credit Facility.

         The $350 Million  Senior  Notes are subject to a make-whole  redemption
right by the Company.  The notes are an unsecured  obligation of the Company and
rank  equally  with  its  existing  and  future  unsecured  and   unsubordinated
indebtedness and senior to any future subordinated  indebtedness.  The notes are
guaranteed  by the  Limited  Partner  through an  unsecured  and  unsubordinated
guarantee  and were issued under an  indenture  containing  certain  restrictive
covenants.  These covenants  restrict the ability of the Company and the Limited
Partner,  with certain exceptions,  to incur debt secured by liens and engage in
sale and  leaseback  transactions.  The  Company  and  Limited  Partner  were in
compliance with the restrictive covenants at December 31, 2000.

         The issuance of the $350 Million  Senior Notes was a takedown under the
Company's $800 million  December 1999  Registration  Statement;  therefore,  the
amount of securities available was reduced to $450 million. The remaining amount
available under the December 1999  Registration  Statement was used to issue the
$450 Million Senior Notes in January 2001.

         $54 Million MBFC Loan.  On March 27, 2000,  the Company  executed a $54
million loan  agreement  with the MBFC which was funded with  proceeds  from the
sale of Taxable Industrial Revenue Bonds ("Bonds") by the MBFC. The Bonds issued
by the MBFC are 10-year  bonds with a maturity  date of March 1, 2010 and bear a
fixed-rate interest coupon of 8.70%. The Company received proceeds from the sale
of the Bonds, net of underwriting  discounts and  commissions,  of approximately
$53.6  million.  The proceeds were used to pay the then $47 million  outstanding
principal  balance on the $350  Million  Bank  Credit  Facility  and for working
capital and other general partnership  purposes. In general, the proceeds of the
Bonds were used to reimburse  the Company for costs  incurred in  acquiring  and
constructing the Pascagoula, Mississippi natural gas processing plant.

         The Bonds were issued at par and are subject to a make-whole redemption
right by the Company. The Bonds are guaranteed by the Limited Partner through an
unsecured and  unsubordinated  guarantee.  The loan agreement  contains  certain
covenants  including   maintaining   appropriate  levels  of  insurance  on  the
Pascagoula natural gas processing  facility and restrictions  regarding mergers.
The Company was in  compliance  with the  restrictive  covenants at December 31,
2000.

         $250 Million  Multi-Year  Credit  Facility.  On November 17, 2000,  the
Company  entered into a $250 million  five-year  revolving  credit facility that
includes a sublimit of $50 million for letters of credit.  The November 17, 2005
maturity  date may be  extended  for one year at the  Company's  option with the
consent of the lenders,  subject to the extension  provisions in the  agreement.
The Company can increase the amount  borrowed under this  facility,  without the
consent of the lenders,  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 $150 Million  364-Day 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 Limited  Partner  through an unsecured and
unsubordinated 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, 2000.

         The Company's obligations under this bank credit facility are unsecured
general  obligations  and are  non-recourse to the General  Partner.  Borrowings
under this bank credit  facility will  generally bear interest at either (a) the
greater of the Prime Rate or the  Federal  Funds  Effective  Rate plus  one-half
percent or (b) a Eurodollar  rate plus an applicable  margin (as defined  within
the facility) or (c) a competitively  bid rate. The Company elects the basis for
the interest rate at the time of each borrowing.

         This  credit  agreement  contains  various   affirmative  and  negative
covenants  applicable to the Company to, among other  things,  (i) incur certain
additional  indebtedness,  (ii) grant  certain  liens,  (iii) enter into certain
merger or  consolidation  transactions  and (iv) make  certain  investments.  In
addition,  the Company may not directly or indirectly  make any  distribution in


                                       39
<PAGE>

respect of its partnership  interests,  except those payments in connection with
the Limited Partner's 1,000,000 Unit Buy-Back Program (not to exceed $30 million
in the aggregate) and distributions  from Available Cash from Operating Surplus,
both as defined within the agreement. The bank credit facility requires that the
Company satisfy certain  financial  covenants at the end of each fiscal quarter:
(i)  maintain  Consolidated  Net Worth of $750  million  (as defined in the bank
credit  facility) and (ii)  maintain a ratio of  Consolidated  Indebtedness  (as
defined  within the bank credit  facility)  to  Consolidated  EBITDA (as defined
within the bank credit  facility)  for the previous  four  quarter  period of at
least 4.0 to 1.0. The Company was in compliance with these restrictive covenants
at December 31, 2000.

         $150 Million  364-Day Credit  Facility.  Also on November 17, 2000, the
Company entered into a 364-day $150 million revolving bank credit facility which
may be  converted  into a one-year  term loan at the end of the initial  364-day
period.  Should  this  facility  be  converted  into a one-year  term loan,  the
maturity  date would be November 16, 2002.  Likewise,  this maturity date may be
extended for an  additional  one-year  period at the option of the Company (with
the  consent  of the  lenders),  subject  to  the  extension  provisions  in the
agreement;  therefore,  the ultimate maturity date of this credit facility could
be November 16, 2003.  The Company can increase the amount  borrowed  under this
facility, without the consent of the lenders, 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 $250  Million  Multi-Year  Credit
Facility  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 Limited  Partner  through an unsecured and
unsubordinated 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, 2000.  The Company used operating cash
flows to repay the  amount  borrowed  to retire  the $350  Million  Bank  Credit
Facility  in  November  2000.  For  the  period  in  which  the  Company  had an
outstanding principal balance under this credit facility,  the interest rate was
7.19%.

         Limitations on certain  actions by the Company and financial  condition
covenants of this bank credit facility are  substantially  consistent with those
existing for the $250 Million Multi-Year Credit Facility as described above. The
Company was in compliance with the restrictive covenants at December 31, 2000.

         Interest Rate Swaps

         The  Company's   interest  rate  exposure  results  from  variable-rate
borrowings from commercial banks and fixed-rate  borrowings pursuant to the $350
Million  Senior Notes and the $54 Million MBFC Loan.  The Company uses  interest
rate swaps to manage its overall costs of  financing.  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.

         In March 2000,  after the issuance of the $350 Million Senior Notes and
the execution of the $54 Million MBFC Loan,  100% of the Company's  consolidated
debt were fixed-rate  obligations.  To maintain a balance between  variable-rate
and fixed-rate exposure,  the Company entered into interest rate swap agreements
with a notional  amount of $154 million by which the Company  receives  payments
based on a fixed-rate and pays an amount based on a  floating-rate.  At December
31, 2000, the Company's  consolidated debt portfolio  interest rate exposure was
62% fixed and 38% floating,  after  considering  the effect of the interest rate
swap agreements. The notional amount does not represent exposure to credit loss.
The Company monitors its positions and the credit ratings of its counterparties.
Management  believes the risk of incurring a credit related loss is remote,  and
that if incurred, such losses would be immaterial.

         The effect of these swaps (none of which are leveraged) was to decrease
the  Company's  interest  expense  by $1.2  million  during  2000.  For  further
information  regarding the interest rate swaps,  see Note 10 of the Notes to the
Consolidated Financial Statements.

         Recent Accounting Developments

         Effective  January 1, 2001, the Company adopted  Statement of Financial
Accounting Standards No. 133 ("SFAS 133"), Accounting for Derivative Instruments
and  Hedging  Activities,  as  amended  and  interpreted.  SFAS 133  establishes


                                       40
<PAGE>

accounting and reporting standards for derivative instruments, including certain
derivative  instruments  embedded in other contracts and for hedging activities.
All  derivatives,  whether  designated in hedging  relationships or not, will be
required to be recorded on the balance sheet at fair value. If the derivative is
designated  as a fair value hedge,  the changes in fair value of the  derivative
and the  hedged  item will be  recognized  in  earnings.  If the  derivative  is
designated  as a cash flow  hedge,  changes in the fair value of the  derivative
will be recorded as a component of Partners' Equity entitled Other Comprehensive
Income (to the  extent the hedge is  effective)  and will be  recognized  in the
income statement when the hedged item affects earnings.  The ineffective portion
of the hedge is  required  to be  recorded  in  earnings.  SFAS 133  defines new
requirements for designation and documentation of hedging  relationships as well
as  ongoing  effectiveness  assessments  in order  to use  hedge  accounting.  A
derivative  that does not  qualify  as a hedge  will be  recorded  at fair value
through earnings.

         The Company  expects  that at January 1, 2001,  it will record a $ 42.2
million loss in Other Comprehensive Income as a cumulative transition adjustment
for derivatives  (commodity contracts) designated in cash flow-type hedges prior
to adopting SFAS 133. In addition,  the Company expects to record a $2.1 million
derivative asset and a corresponding  increase to its long term debt relating to
derivatives (interest rate swaps) designated in fair-value-type  hedges prior to
adopting  SFAS 133. The fair value  hedges will have no impact to earnings  upon
transition.

         The Company  will  reclassify  from Other  Comprehensive  Income  $21.7
million  as a charge to  earnings  during  the first  quarter  of 2001 and $20.5
million as a charge to earnings during the remainder of 2001. The actual gain or
loss amount to be recognized in earnings  related to these  commodity  contracts
over time is  dependent  upon the final  settlement  price  associated  with the
commodity prices.


         MTBE Facility

         The Company owns a 33.3% interest in the BEF partnership  that owns the
MTBE production facility located within the Company's Mont Belvieu complex.  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.

         In light of the regulatory climate, the owners of BEF are formulating a
contingency   plan  for  use  of  the  BEF  facility  if  MTBE  were  banned  or
significantly  curtailed.  The owners of BEF are exploring a possible conversion
of the BEF facility from MTBE production to alkylate production.  One conversion
alternative is expected to result in similar  operating margin as that currently
anticipated  from the  facility  if it were to remain in MTBE  service.  If this
approach  were  taken,  the cost to convert  the  facility  would range from $20
million to $25  million,  with the  Company's  share being $6.7  million to $8.3
million. A second conversion alternative would increase both production capacity
and  overall  margin and cost  between $50  million  and $90  million,  with the
Company's share being $16.7 million to $30 million.  Management anticipates that
if MTBE is banned  alkylate demand will rise as producers use it to replace MTBE
as an octane enhancer. Greater alkylate production would be expected to increase
isobutane  consumption  nationwide and result in improved  isomerization margins
for the Company.

         Sun, the MTBE facility's major customer and one of the partners of BEF,
has entered into a contract with BEF to take all of the MTBE production  through
September 2004.






                                       41
<PAGE>

Item 7A.  Quantitative and Qualitative Disclosures about Market Risk.

         The Company is exposed to financial market risks,  including changes in
interest rates with respect to a portion of its debt  obligations and changes in
commodity prices.  The Company may use derivative  financial  instruments (i.e.,
futures,  forwards, swaps, options, and other financial instruments with similar
characteristics)  to mitigate  these risks.  The Company  generally does not use
derivative financial instruments for speculative (or trading) purposes.

         The Company has adopted a  commercial  policy to manage its exposure to
the risks  generated  by its gas  processing  and  related  NGL  businesses  and
long-term  debt.  The  objective  of this  policy is to assist  the  Company  in
achieving its profitability  goals while maintaining a portfolio of conservative
risk, defined as remaining within the position limits established by the General
Partner.  The Company  will enter into risk  management  transactions  to manage
price risk, basis risk, physical risk, interest rate risk or other risks related
to the energy  commodities and long-term debt on both a short-term (less than 30
days) and long-term basis, not to exceed 18 months. The General Partner oversees
the  strategies of the Company  associated  with  physical and financial  risks,
approves  specific  activities of the Company  subject to the policy  (including
authorized   products,   instruments  and  markets)  and  establishes   specific
guidelines and  procedures for  implementing  and ensuring  compliance  with the
policy.

Interest rate risk

         Variable-rate  Debt. At December 31, 2000 and 1999,  the Company had no
derivative instruments in place to cover any potential interest rate risk on its
variable-rate  debt  obligations.  Variable-rate  debt  obligations  expose  the
Company to possible  increases in interest  expense and decreases in earnings if
interest  rates  were  to  rise.   During  2000  and  1999,  the  Company's  had
variable-rate  long-term debt outstanding  under the $200 Million,  $350 Million
and $150 Million  364-Day  bank credit  facilities.  At December  31, 2000,  the
Company had no variable-rate debt outstanding.

         If  the  weighted   average  base  interest   rates   selected  on  the
variable-rate  long-term  debt during 1999 were to have been 10% higher than the
weighted average of the actual base interest rates selected, assuming no changes
in weighted average variable debt levels,  interest expense would have increased
by approximately  $1.4 million with a corresponding  decrease in earnings before
minority  interest.  If the same calculation were performed on the variable-rate
long-term debt outstanding during 2000, interest expense would have increased by
approximately  $1.0 million  with a  corresponding  decrease in earnings  before
minority interest.

         Fixed-rate  Debt. In March 2000, the Company entered into interest rate
swaps whereby the fixed-rate of interest on a portion of the $350 Million Senior
Notes and the $54 Million MBFC Loan was effectively  swapped for  floating-rates
tied to the six month London  Interbank  Offering Rate ("LIBOR").  Interest rate
swaps are used to manage the Company's  overall costs of financing.  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.

         To maintain a balance between  variable-rate  and fixed-rate  exposure,
the Company entered into interest rate swap agreements with a notional amount of
$154 million by which the Company  receives  payments  based on a fixed-rate and
pays an amount based on a  floating-rate.  At December 31, 2000,  the  Company's
consolidated  debt  portfolio  interest  rate  exposure  was 62%  fixed  and 38%
floating, after considering the effect of the interest rate swap agreements. The
notional amount does not represent exposure to credit loss. The Company monitors
its positions and the credit ratings of its counterparties.  Management believes
the risk of  incurring a credit  related  loss is remote,  and that if incurred,
such losses would be immaterial.











                                       42
<PAGE>

         The effect of these swaps (none of which are leveraged) was to decrease
the  Company's  interest  expense by $1.2  million  during  2000.  Following  is
selected  information  on the  Company's  portfolio  of  interest  rate swaps at
December 31, 2000:

               Interest Rate Swap Portfolio at December 31, 2000 (1)
                             (Dollars in millions)
                                                 Early             Fixed /
  Notional                                    Termination         Floating
   Amount            Period Covered             Date (2)          Rate (3)
--------------------------------------------------------------------------------

      $ 50.0 March 2000 - March 2005        March 2001         8.25% / 7.3100%
      $ 50.0 March 2000 - March 2005        March 2001 (4)     8.25% / 7.3150%
      $ 54.0 March 2000 - March 2010        March 2003         8.70% / 7.6575%

 Notes to interest rate swap table:

(1)  All swaps  outstanding  at  December  31,  2000 were  entered  into for the
     purpose of managing a portion of the financing  costs  associated  with its
     fixed-rate debt.
(2)  In each case,  the  counterparty  has the option to terminate  the interest
     rate swap on the Early Termination Date.
(3)  In each case, the Company is the floating-rate payor. The floating rate was
     the rate in effect as of December 31, 2000.
(4)  Swap was terminated by the bank effective March 15, 2001.

         If the six month  LIBOR rates  applicable  to the  notional  amounts of
these  interest  rate swap  agreements  during 2000 were to have been 10% higher
than the six month LIBOR rates actually used in the swap agreements, assuming no
changes  in  fixed-rate  debt  levels,  interest  expense  for 2000  would  have
increased by $0.8  million,  with a  corresponding  decrease in earnings  before
minority interest.

         In connection  with the  implementation  of SFAS 133, the fair value of
the  interest  rate swaps were  recorded on the balance  sheet as a $2.1 million
receivable  with an offsetting gain recorded in earnings on January 1, 2001. The
value   recorded  for  the  interest  rate  swap   agreements   represents   the
capitalization  of these  derivative  instruments  using current market interest
rates. In accordance with SFAS 133, the value of the interest rate swaps will be
redetermined  each  reporting  period  based upon then current  market  interest
rates.  The value  assigned to the interest  rate swap  agreements is predicated
upon the expected life of the swap  agreements  as influenced by current  market
interest  rates.  The  change  in the  value of these  instruments  during  each
measurement period will result in either an increase or a decrease in earnings.

         At  December  31,  2000,  the  Company's  fixed-rate  debt  obligations
aggregated  $404.0 million and had a fair value of $423.8  million.  Since these
instruments  have  fixed-interest  rates,  they do not expose the Company to the
risk of loss in earnings due to changes in market interest rates.  However,  the
fair value of these instruments  would increase to approximately  $435.8 million
if interest rates were to decline by 10% from their levels at December 31, 2000.
In general,  such an increase in fair value would impact earnings and cash flows
only if the Company were to reacquire all or a portion of these  instruments  in
the open market prior to their maturity.

         Other. At December 31, 2000 and 1999, the Company had $58.4 million and
$5.2  million  invested  in cash and cash  equivalents,  respectively.  All cash
equivalent  investments  other  than  cash  are  highly  liquid,  have  original
maturities of less than three months,  and are considered to have  insignificant
interest rate risk.

Commodity Price Risk

         The  Company  is  exposed  to  commodity  price  risk  through  its gas
processing and related NGL businesses. In order to effectively manage this risk,
the Company may enter into swaps, forwards, commodity futures, options and other
derivative commodity instruments with similar characteristics that are permitted
by contract or business  custom to be settled in cash or with another  financial
instrument. The 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.


                                       43
<PAGE>

         The following  table presents the  hypothetical  changes in fair values
arising from immediate selected potential changes in the quoted market prices of
derivative  commodity  instruments  outstanding  at the dates  noted  within the
table.  The fair value of the  commodity  futures at the dates  noted  below are
estimates based on quoted market prices of comparable  contracts and approximate
the gain or loss that would have been realized if the contracts had been settled
at the respective balance sheet dates.

<TABLE>
<CAPTION>
                                                        Impact of a 10% increase              Impact of a 10% decrease
                             Asset (liability)             in market prices                      in market prices
                                Fair value        ------------------------------------  ------------------------------------
                              at date indicated                      Increase(Decrease)                    Increase(Decrease)
                                assuming no                            in Fair Value                         in Fair Value
                                 change in        Adjusted estimate  due to increase      Adjusted estimate  due to decrease
                               market prices        of Fair Value     in market prices      of Fair Value   in market prices
                             ------------------   ------------------------------------  ------------------------------------
<S>            <C> <C>           <C>                  <C>               <C>                <C>               <C>
Estimated impact of changes
  in quoted market prices on
  Commodity futures at:
  (in millions of dollars)
      December 31, 1999          $       (0.5)        $         1.2     $         1.7      $        (2.2)    $        (1.7)
      December 31, 2000                 (38.6)                (56.3)            (17.7)             (20.9)             17.7
      March 12, 2001                    (11.5)                (34.3)            (22.8)              11.5              23.0
</TABLE>

The fair value of the  commodity  futures at December 31, 1999 was  estimated at
$0.5 million  payable.  The fair value of the commodity  futures at December 31,
2000 was estimated at $38.6 million payable. The increase is primarily due to an
increase in volumes hedged,  a change in the  composition of commodities  hedged
and higher natural gas prices.  On March 12, 2001, the fair value of commodities
hedged  was $11.5  million  payable.  The  change  from  December  31,  2000 was
primarily  due to the  settlement of certain open  positions,  lower natural gas
prices and a change in the composition of commodities hedged.

To the extent that the hedged positions are effective,  gains or losses on these
derivative commodity instruments would be offset by a corresponding gain or loss
on the hedged  commodity  positions,  which are not included in the table above.
Beginning in January 2001 with the  implementation  of SFAS 133, the ineffective
portion of such  hedged  positions  will be recorded  in  earnings.  See "Recent
Accounting  Developments"  on page 40 for additional  information  regarding the
accounting treatment of hedged commodity positions under SFAS 133.


Item 8.  Financial Statements and Supplementary Data.

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


Item  9.  Changes  in and  disagreements  with  Accountants  on  Accounting  and
Financial Disclosure.

         None.















                                       44
<PAGE>

                                    PART III

Item 10.  Directors and Executive Officers of the Registrant.

         Company Management

         The Company does not directly employ any of the persons responsible for
the management of the Company. These functions are performed by the employees of
EPCO  (pursuant  to the EPCO  Agreement)  under  the  direction  of the Board of
Directors and executive officers of the General Partner.

         In accordance with NYSE rules  applicable to the Limited  Partner,  the
Board of  Directors  of the  General  Partner  has named three of its members to
serve on its  Audit  and  Conflicts  Committee.  The  members  of the  Audit and
Conflicts  Committee  are  financially  literate  and  independent  nonexecutive
directors,  free from any relationship that would interfere with the exercise of
independent  judgment.  The Audit and  Conflicts  Committee has the authority to
review specific matters as to which the Board of Directors believes there may be
a conflict of interests in order to determine if the resolution of such conflict
proposed by the  General  Partner is fair and  reasonable  to the  Company.  Any
matters approved by the Audit and Conflicts Committee are conclusively deemed to
be fair and  reasonable to the Company,  approved by all partners of the Company
and not a breach by the General  Partner or its Board of Directors of any duties
they may owe the Company or the unitholders of the Limited Partner.

         The  members  of the Audit and  Conflicts  Committee  must have a basic
understanding  of  finance  and  accounting  and be able to read and  understand
fundamental financial statements, and at least one member of the committee shall
have accounting or related financial management expertise. In addition to ruling
in cases involving  conflicts of interest,  the primary  responsibilities of the
Audit and Conflicts Committee include:

-    monitoring the integrity of the financial reporting process and its related
     systems of internal control;
-    ensuring  legal and  regulatory  compliance of the General  Partner and the
     Company (including its subsidiaries);
-    overseeing the  independence  and performance of the Company's  independent
     public accountants;
-    providing  for an avenue of  communication  among  the  independent  public
     accountants,   management,   internal  audit  function  and  the  Board  of
     Directors;
-    encouraging  adherence  to and  continuous  improvement  of  the  Company's
     policies, procedures and practices at all levels;
-    reviewing areas of potential significant financial risk to the Company; and
-    approving  increases in the  administrative  service fee payable  under the
     EPCO Agreement.

Pursuant  to its formal  written  charter  adopted  in June 2000,  the Audit and
Conflicts  has  the  authority  to  conduct  any  investigation  appropriate  to
fulfilling  its  responsibilities,  and it has direct access to the  independent
public accountants as well as EPCO personnel.  The Audit and Conflicts Committee
has the ability to retain, at the Company's expense,  special legal, accounting,
or other  consultants  or experts it deems  necessary in the  performance of its
duties.

         Notwithstanding  any  limitation  on its  obligations  or  duties,  the
General Partner is liable, as the general partner of the Company,  for all debts
of the  Company  (to the extent not paid by the  Company),  except to the extent
that  indebtedness  or  other  obligations  incurred  by the  Company  are  made
specifically non-recourse to the General Partner. Whenever possible, the General
Partner intends to make any such indebtedness or other obligations  non-recourse
to the General Partner.











                                       45
<PAGE>

         Directors, Executive Officers of the General Partner

         Set forth below is the name,  age and position of each of the directors
and  executive  officers  of the  General  Partner.  Each member of the Board of
Directors  serves  until  such  member's  death,  resignation  or  removal.  The
executive  officers are elected for one-year  terms and may be removed,  with or
without cause, only by the Board of Directors.

<TABLE>
<CAPTION>
               Name                   Age                  Position with General Partner
-----------------------------------  -------  ---------------------------------------------------------
<S>                                    <C>    <C>
Dan L. Duncan (1,3)                    68     Director and Chairman of the Board
O.S. Andras (1,3)                      65     Director, President and Chief Executive Officer
Randa L. Duncan (3)                    39     Director
J. R. Eagan                            46     Director
J. A. Berget (1)                       48     Director
Dr. Ralph S. Cunningham (2)            60     Director
Curtis R. Frasier (1)                  45     Director
Lee W. Marshall, Sr. (2)               68     Director
Richard S. Snell (2)                   58     Director
Richard H. Bachmann (1,3)              48     Director, Executive Vice President, Chief Legal Officer
                                               and Secretary
Albert W. Bell (3)                     62     Executive Vice President, President and Chief
                                               Operating Officer of Petrochemical Division
A.J. ("Jim") Teague (3)                56     Executive Vice President, President and Chief
                                               Operating Officer of NGL Division
Michael A. Creel (3)                   47     Executive Vice President, Chief Financial
                                               Officer and President and Chief Operating Officer of
                                               Natural Gas Division
William D. Ray (3)                     65     Executive Vice President
Charles E. Crain (3)                   67     Senior Vice President
Michael Falco (3)                      64     Senior Vice President
A. Monty Wells (3)                     55     Senior Vice President
Michael J. Knesek (3)                  46     Vice President and Principal Accounting Officer
W. Randall Fowler (3)                  44     Vice President and Treasurer

-------------------------------------------------------------------------------------------------------
</TABLE>
      (1) Member of the Executive Committee
      (2) Member of the Audit and Conflicts Committee
      (3) Executive Officer

         Dan L.  Duncan was  elected as  Chairman of the Board and a Director of
the General Partner in April 1998. Mr. Duncan joined EPCO in 1969 and has served
as Chairman of the Board of EPCO since 1979. He served as President of EPCO from
1970 to 1979 and Chief Executive Officer from 1982 to 1985.

         O. S. Andras was elected as President,  Chief  Executive  Officer and a
Director  of the  General  Partner  in April  1998.  Mr.  Andras  has  served as
President and Chief  Executive  Officer of EPCO since 1996. Mr. Andras served as
President  and Chief  Operating  Officer of EPCO from 1982 to 1996 and Executive
Vice  President of EPCO from 1981 to 1982.  Before joining EPCO, he was employed
by The Dow Chemical Company in various  capacities from 1960 to 1981,  including
Director of Hydrocarbons.

         Randa L. Duncan was elected as Group  Executive  Vice  President  and a
Director  of the  General  Partner in April  1998.  Ms.  Duncan  served as Group
Executive Vice President of EPCO from 1994 to 2001. In February 2001, she became
President and Chief  Executive  Officer of EPCO and resigned as Group  Executive
Vice  President of the General  Partner in order to devote full attention to the
responsibilities  of her new position.  Before joining EPCO, she was an attorney
with the firms of Butler & Binion  from 1988 to 1991 and Brown,  Sims,  Wise and
White from 1991 until 1994. Ms. Duncan is the daughter of Dan L. Duncan.



                                       46
<PAGE>

         J. R. (Jeri) Eagan was elected as a Director of the General  Partner in
October  2000.  Since  1999,  Ms.  Eagan has served in  various  executive-level
positions with Shell  Exploration  and Production  Company ("SEP") and currently
holds the office of Vice President Finance & Commercial Operations. From 1994 to
1999,  she  worked on  several  assignments  in the  London  office  with  Shell
International  Petroleum Company.  From 1976 to 1994, Ms. Eagan held a number of
managerial and accounting positions with various Shell companies.

         J. A. (Jorn) Berget was elected as a Director of the General Partner in
November  2000.  Since October 2000, Mr. Berget has served as Vice President and
General  Manager  for SEP.  From 1995 to  October  2000,  he  served in  various
managerial  positions with Shell Expro including General Manager of the Northern
Business Unit in which he managed Shell assets and activities of the Brent Field
in the United  Kingdom.  Over the past 20 years,  Mr.  Berget has held  numerous
operating,  engineering, planning and managerial positions covering most aspects
of SEP. 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  as a Director  of the  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  served as Vice Chairman of Huntsman  Corporation from 1994
until 1995 and as President of Texaco  Chemical  Company from 1990 through 1994.
Prior to joining Texaco Chemical Company,  Dr. Cunningham held various executive
positions  with  Clark Oil & Refining  and  Tenneco.  He  started  his career in
Exxon's refinery  operations.  He holds Ph.D., M.S. and B.S. degrees in Chemical
Engineering. Dr. Cunningham serves as a director of Tetra Technologies,  Inc. (a
public energy services and chemicals company), Huntsman Corporation (a privately
held   petrochemical   corporation),   and  Agrium,   Inc.  (a  Canadian  public
agricultural  chemicals  company ) and served as a director of EPCO from 1987 to
1997.

         Curtis R.  Frasier was  elected as  Director of the General  Partner in
November 1999. Mr. Frasier is Vice President of Shell N.A. Gas & Power,  SEP. He
has  served in  various  capacities  in the Shell  organization  since  1982 and
previously served as President of Shell Midstream Enterprises. He also served as
Shell's Manager of Supply Operations following  assignments in the London office
beginning in the Legal Department of Shell's corporate office.

         Lee W. Marshall,  Sr. was elected as a Director of the General  Partner
in April 1998. Mr. Marshall has been the Chief  Executive  Officer and principal
stockholder of Bison International,  Inc., and Bison Resources,  LLC since 1991.
Previously,  Mr.  Marshall was  Executive  Vice  President  and Chief  Financial
Officer of Wolverine  Exploration  Company and held senior management  positions
with Union Pacific Resources and Tenneco Oil.

         Richard S. Snell was elected as a Director  of the  General  Partner in
June 2000.  Mr. Snell was an attorney  with Snell & Smith,  P.C. for seven years
after  founding the company in 1993.  He is currently a partner with the firm of
Thompson  Knight  Brown  Parker  &  Leahy,  L.L.P.  and  is a  certified  public
accountant.

         Richard H. Bachmann was elected as a Director of the General Partner in
June 2000. He has served as Executive  Vice President and Chief Legal Officer of
the General Partner since January,  1999.  Before joining EPCO, he was a partner
with the firms of Snell & Smith P.C.  from 1993 to 1998 and Butler & Binion from
1988 to 1993.

         Albert W. Bell was elected as a Executive Vice President of the General
Partner in April 1998 and serves as the President and Chief Operating Officer of
the  Petrochemical  Division.  Mr. Bell has served as Executive Vice  President,
Business  Management  of  EPCO  since  1994.  Mr.  Bell  joined  EPCO in 1980 as
President of its Canadian subsidiary. Mr. Bell transferred to EPCO in Houston in
1988 as Vice  President,  Business  Development  and was promoted to Senior Vice
President,  Business  Management in 1992. Prior to joining EPCO, he was employed
by Continental  Emsco Supply Company,  Ltd. and Amoco Canada Petroleum  Company,
Ltd.

         A.J.  ("Jim")  Teague was elected as a Executive  Vice President of the
General  Partner  in  November,  1999 and  serves  as the  President  and  Chief
Operating  Officer  of the NGL  Division  of the  Company.  From 1998 to 1999 he
served as  President of Tejas  Natural Gas Liquids,  LLC, an affiliate of Shell.
From 1997 to 1998 he was President of Marketing and Trading for Mapco, Inc. From
1972 to 1996,  he held a variety of  positions  with The Dow  Chemical  Company,
including  Vice  President,  Feedstocks.



                                       47
<PAGE>

         Michael  A.  Creel was  elected  as an  Executive  Vice  President  and
President and Chief Operating Officer of the Natural Gas Division of the General
Partner in  February  2001,  having  served as a Senior  Vice  President  of the
General Partner since November 1999. In June 2000, Mr. Creel, a certified public
accountant,  assumed the role of Chief  Financial  Officer of the Company  along
with his other  responsibilities in investor relations,  information  technology
and corporate risk.  From 1997 to 1999 he held a series of positions,  including
Senior Vice President, Chief Financial Officer and Treasurer, with Tejas Energy.
From 1991 to 1997 he served as Vice  President  and  Treasurer  of NorAm  Energy
Corp.,  Treasurer of Enron Oil & Gas Company, and was employed by Enron Corp. in
various  capacities,  including Assistant  Treasurer.  From 1973 to 1991 he held
management  positions in accounting  and finance within the energy and financial
industries.

         William D. Ray was elected as a Executive Vice President of the General
Partner in April 1998. Mr. Ray has served as EPCO's  Executive  Vice  President,
Marketing and Supply since 1985.  Mr. Ray served as Vice  President,  Supply and
Distribution  of EPCO  from 1971 to 1973 and as EPCO's  Senior  Vice  President,
Supply,  Marketing and Distribution  from 1973 to 1979. Prior to joining EPCO in
1971, Mr. Ray was employed by Wanda Petroleum from 1958 to 1969 and Koch as Vice
President, Marketing and Supply from 1969 to 1971.

         Charles E. Crain was elected as a Senior Vice  President of the General
Partner in April 1998 and has served as Senior  Vice  President,  Operations  of
EPCO since  1991.  Mr.  Crain  joined  EPCO in 1980 as Vice  President,  Process
Operations.  Prior to joining EPCO,  Mr. Crain held  positions  with Shell,  Air
Products & Chemicals and Tenneco Chemicals.

         Michael  Falco was  elected as a Senior Vice  President  of the General
Partner in April 1998.  Mr. Falco had served as EPCO's Senior Vice  President in
the business  management  area since 1992.  Previously,  Mr. Falco had a 21 year
career with  Tenneco Oil  Company,  holding a variety of positions in NGL supply
and crude oil and refined products supply including 6 years as Vice President of
Tenneco Oil.

         A. Monty Wells was elected as a Senior  Vice  President  of the General
Partner in June 2000.  Since  joining  EPCO in 1980,  Mr.  Wells has served in a
number of managerial positions including Vice President of Marketing and Supply.
Prior to 1980,  he worked in the  international  natural  gas  liquids  group at
Atlantic  Richfield  and had  responsibilities  in ARCO  Chemical's  hydrocarbon
feedstock group.

         Michael J. Knesek was elected as the Principal Accounting Officer and a
Vice President of the General Partner in August 2000.  Since 1990, Mr. Knesek, a
certified  public  accountant,  has been the  Controller and a Vice President of
EPCO.  Mr.  Knesek  joined  EPCO in 1981 as revenue  accounting  manager and has
served in various managerial  accounting  positions including general manager of
accounting. Mr. Knesek has over twenty-five years of experience in corporate and
partnership accounting, tax and finance.

         W. Randall  Fowler was elected as the Treasurer and a Vice President of
the  General  Partner in August  2000.  Mr.  Fowler  joined  EPCO 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.  Mr. Fowler has over twenty years of experience in corporate finance,
investor relations, strategic planning and accounting.


Item 11.  Executive Compensation.

         The Company has no  executive  officers.  The Company is managed by the
General  Partner,  the  executive  officers of which are  employees  of, and the
compensation  of whom is paid by, EPCO.  For a discussion  of this related party
transaction, see "EPCO Agreement" under Item 13.

         Compensation of Directors

         No additional  remuneration is paid to employees of EPCO,  Shell or the
General  Partner  who also serve as  directors  of the General  Partner.  During
fiscal 2000, the independent  directors  received an annual retainer of $24,000,
for which each agreed to  participate  in four regular  meetings of the Board of
Directors  and  four  Audit  and  Conflicts  Committee  meetings  (plus  nominal
out-of-pocket   expenses  in  connection  with  attending  the  meetings).   The


                                       48
<PAGE>

independent  directors were also entitled to $500 per meeting when the number of
Board of Directors meetings and Audit and Conflicts  Committee meetings exceeded
the four mentioned  previously.  Effective  January 1, 2001, the General Partner
revised its independent  director  compensation  policy to reflect (i) an annual
retainer of  $18,000,  (ii)  $1,000 for each  meeting of the Board of  Directors
attended by a director,  (iii) $500 for each meeting of a committee of the Board
of Directors  attended by a committee member and (iv) an annual retainer of $500
for each  chairman of a committee of the Board of  Directors.  Each  director is
fully indemnified by the Company for his or her actions  associated with being a
director to the extent permitted under Delaware law.


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

         The Limited  Partner (the parent of the Company)  owns  98.9899% of the
Company with the General Partner owning the remainder.  The following table sets
forth  certain  information  as of  March  22,  2001  regarding  the  beneficial
ownership of the Limited Partner's equity securities by:

     -    all persons known by the General Partner to own beneficially more than
          five percent of the Common Units of the Limited Partner;
     -    the directors and certain  executive  officers of the General Partner;
          and,
     -    all  directors  and  executive  officers of the  General  Partner as a
          group.

Subordinated Units and Special Units represent non-voting ownership interests in
the Limited Partner.

<TABLE>
<CAPTION>
                                     Common Units              Subordinated Units             Special Units
                                     ------------              ------------------             -------------
                               Number of      Percent       Number of      Percent       Number of      Percent
                                 Units        of Class        Units        of Class        Units        of Class
                                 -----        --------        -----        --------        -----        --------

<S>                             <C>                 <C>      <C>                <C>       <C>                <C>
EPCO (1)                        33,552,915          71.7%    21,409,870         100.0%             -           0.0%
Coral Energy LLC (2)             1,000,000           2.1%             -           0.0%    16,500,000         100.0%
Dan Duncan (1,3)                35,070,115          71.7%    21,409,870         100.0%             -           0.0%
O.S. Andras                        180,600           0.4%             -           0.0%             -           0.0%
Randa L. Duncan                          -           0.0%             -           0.0%             -           0.0%
J. R. Eagan                              -           0.0%             -           0.0%             -           0.0%
J. A. Berget                             -           0.0%                         0.0%             -           0.0%
Dr. Ralph S. Cunningham                  -           0.0%             -           0.0%             -           0.0%
Curtis R. Frasier                        -           0.0%             -           0.0%             -           0.0%
Lee W. Marshall, Sr.                     -           0.0%             -           0.0%             -           0.0%
Richard S. Snell                         -           0.0%             -           0.0%             -           0.0%
Richard H. Bachmann                  1,428           0.0%             -           0.0%             -           0.0%
Albert W. Bell (4)                  34,252           0.1%             -           0.0%             -           0.0%
A.J. Teague (5)                     58,000           0.1%             -           0.0%             -           0.0%
Michael A. Creel                     5,000           0.0%             -           0.0%             -           0.0%
All directors and
    executive officers
     as a group
 (19 persons) (6)               35,457,498          77.6%    21,409,870         100.0%             -           0.0%

-------------------------------------------------------------------------------------------------------------------
</TABLE>

(1)  EPCO holds its Units through a  wholly-owned  subsidiary,  EPC Partners II,
     Inc. Mr.  Duncan owns 50.4% of the voting  stock of EPCO and,  accordingly,
     exercises sole voting and dispositive  power with respect to the 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 L. Duncan,  a director and executive  officer of the General Partner.
     The address of EPCO and Mr. Duncan is 2727 North Loop West, Houston,  Texas
     77008.
(2)  Special Units were issued to Coral Energy as part of the TNGL acquisition.
(3)  In addition to the Units held by EPCO, Dan Duncan has beneficial  ownership
     of an  additional  1,517,200  Common Units held by the 1998,  1999 and 2000
     Trusts (see Item 13).
(4)  Includes options (under an EPCO Unit option plan) to purchase 22,681 Common
     Units exercisable within 60 days of March 22, 2001.
(5)  Includes options (under an EPCO Unit option plan) to purchase 50,000 Common
     Units exercisable within 60 days of March 22, 2001.
(6)  Includes  options  (under an EPCO Unit  option  plan) to  purchase  101,403
     Common Units exercisable within 60 days of March 22, 2001.



                                       49
<PAGE>

Item 13.   Certain Relationships and Related Transactions.

         Relationships with EPCO and its affiliates

         The Company has an  extensive  ongoing  relationship  with EPCO and its
affiliates.  EPCO is majority-owned  and controlled by Dan L. Duncan, a director
and the Chairman of the Board of the General Partner.  In addition,  three other
members of the Board of Directors (O.S.  Andras,  Randa L. Duncan and Richard H.
Bachmann)  and the  remaining  executive  officers  (see Item 10 for a  complete
listing of the executive officers) of the General Partner are employees of EPCO.
The principal business activity of the General Partner is to act as the managing
partner of the Company.

         Mr.  Duncan  owns 50.4% of the voting  stock of EPCO and,  accordingly,
exercises  sole voting and  dispositive  power with respect to the 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 L.
Duncan, a director of the General Partner.  The Limited Partner's Units owned by
EPCO are held by EPC Partners II, Inc. ("EPC II"), a wholly-owned  subsidiary of
EPCO.  At December  31, 2000,  EPC II's  holdings of Limited  Partner  ownership
interests  consisted  of  33,552,915  Common Units and  21,409,870  Subordinated
Units,  representing a 39.3% interest and 25.1% interest,  respectively,  in the
Limited Partner.  In addition,  EPCO and Dan Duncan, LLC collectively own 70% of
the General Partner which in turn owns a combined 2% interest in the Company and
the Limited Partner.  In addition,  the following  affiliates of EPCO own Common
Units of the Limited Partner (amounts as of December 31, 2000):

     -    Enterprise  Products  1998 Unit Option  Plan Trust (the "1998  Trust")
          held 1,150,000 Common Units. The 1998 Trust was formed for the purpose
          of granting  options in the Limited  Partner's Units to management and
          certain key employees.  The 1998 Trust is no longer  accumulating  the
          Limited Partner's Units.
     -    Enterprise  Products  2000 Rabbi Trust (the "2000 Trust") held 100,000
          Common  Units.  The 2000  Trust  was  formed  for  general  investment
          purposes and for granting  additional options in the Limited Partner's
          Units to  management  and  certain key  employees.  The 2000 Trust may
          purchase  additional  Limited  Partner  Units  on the open  market  or
          through privately negotiated transactions.

         The Company's  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.

         Another  affiliate  of EPCO and the Company,  EPOLP 1999 Grantor  Trust
(the  "1999  Trust"),  was formed for the  purpose of funding  liabilities  of a
long-term  incentive  employee  benefit plan. As of December 31, 2000,  the 1999
Trust held 267,200 Common Units of the Limited Partner.

         EPCO Agreement

         The  Company  has no  employees.  All  management,  administrative  and
operating  functions  are  performed by  employees of EPCO  pursuant to the EPCO
Agreement  entered  into by EPCO,  the  General  Partner and the Company in July
1998.  Under the terms of the agreement,  EPCO agreed to (i) manage the business
and affairs of the Company;  (ii) employ the operating personnel involved in the
Company's  business for which EPCO is  reimbursed  by the Company at cost (based
upon EPCO's actual salary costs and related  fringe  benefits);  (iii) allow the
Company 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;  (iv)  grant an  irrevocable,  non-exclusive  worldwide
license to all of the  trademarks  and trade  names used in its  business to the
Company;  (v) indemnify the Company  against any losses  resulting  from certain
lawsuits;  and (vi)  sublease 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 to the Company for $1 per year
and  assigned  its purchase  options  under such leases to the Company.  EPCO is
liable for the lease payments associated with these assets.  Operating costs and
expenses (as shown on the audited Statements of Consolidated Operations) include
charges for EPCO's employees who operate the Company's various facilities.



                                       50
<PAGE>

         Pursuant to the EPCO  Agreement,  the charges for EPCO's  employees who
manage the business and affairs of the Company are reimbursed only under certain
circumstances.  SG&A  charges to EPCO  resulting  from the hiring of  additional
personnel and other costs associated with the expansion and business development
activities of the Company  (through the  construction  of new  facilities or the
completion  of  acquisitions)  are  reimbursed  by  the  Company.   In  lieu  of
reimbursement  for all other SG&A costs  incurred  by EPCO,  EPCO is entitled to
receive an annual Administrative Services Fee (the "EPCO Fees", initially set at
$12.0  million).

         The General  Partner,  with the  approval  and consent of the Audit and
Conflicts  Committee,  may agree to increases in the EPCO Fees of up to 10% each
contract  year  (defined as August 1 to July 31) during the 10-year  term of the
EPCO Agreement.  Since the initial contract year ending July 31, 1999, the Audit
and Conflicts  Committee has approved two increases in the EPCO Fees. The annual
fee was increased to $13.2 million for the second contract year and subsequently
raised to $14.5 million for the third  contract year. The following is a summary
of the SG&A amounts paid to EPCO by the Company during the last three years:

                                           2000        1999      1998 (1)
                                        ------------------------------------
                                             (in millions of dollars)
                                        ------------------------------------

EPCO Fees                                    $ 13.8      $ 12.5      $  5.1
Expansion-related costs reimbursed to
  EPCO by the Company                          14.5           -           -
                                        ------------------------------------
  Total                                      $ 28.3      $ 12.5      $  5.1
                                        ====================================

     (1)  Amount reflects the five-month  period during which the EPCO Agreement
          was  outstanding  in 1998 after the  initial  public  offering  of the
          Company in late July 1998. As noted earlier, the initial payments made
          to EPCO were on the basis of $12.0 million  annually ($1.0 million per
          month).

         Other Related Party Transactions with EPCO or its affiliates

         The   following  is  a  summary  of  the  other   ongoing   significant
relationships and transactions between EPCO and the Company and its affiliates:

     -    EPCO is the  operator  of the plants and  facilities  owned by BEF and
          EPIK  and is  paid a  management  fee by  these  entities  in  lieu of
          reimbursement  for the actual cost of providing  management  services.
          BEF and EPIK paid $0.9 million in management fees to EPCO during 2000.
     -    EPCO and the Company have entered into an agreement  pursuant to which
          EPCO   provides   trucking   services   involving   the   loading  and
          transportation  of NGL products for the Company.  EPCO  recorded  $7.9
          million in revenues for these services during 2000.
     -    In the normal course of business, the Company may, on occasion, engage
          in transactions  with EPCO (including its  wholly-owned  subsidiaries)
          involving the buying and selling of NGL products. The Company recorded
          net sales to EPCO of $3.2 million during 2000.

         Relationships with Shell

         Shell, through its subsidiary Coral Energy, owns approximately 20.5% of
the Limited Partner and 30.0% of the General Partner. Three members of the Board
of Directors  of the General  Partner  (J.R.  Eagan,  J.A.  Berget and Curtis R.
Frasier) are employees of Shell.

         Shell is a significant customer of the gas processing assets. Under the
terms of the Shell  Processing  Agreement,  the Company has the right to process
substantially  all of Shell's current and future natural gas production from the
Gulf of Mexico.  This  includes  natural gas  production  from the  developments
currently referred to as deepwater.  Generally,  the Shell Processing  Agreement
grants the Company the following rights and obligations:



                                       51
<PAGE>

     -    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 raw make
          extracted by the  Company's  gas  processing  facilities  from Shell's
          natural gas production from such leases; with
     -    the  obligation  to deliver to Shell the natural gas stream  after the
          raw make is extracted.

For fiscal 2000,  revenues from Shell aggregated  $292.7 million while purchases
from Shell totaled $736.7 million.

See Note 8 of the Notes to the Consolidated  Financial Statements for additional
information regarding related party transactions.


                                     PART IV

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

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

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

(a)(3) Exhibits

*2.1        Purchase and Sale Agreement between Coral Energy, LLC and Enterprise
            Products  Operating  L.P.  dated ad of September 22, 2000.  (Exhibit
            10.1 to Form 8-K filed on September 26, 2000).

^3.1        Form of Amended and  Restated  Agreement of Limited  Partnership  of
            Enterprise  Products  Operating  L.P.  (Exhibit 3.2 to  Registration
            Statement  on Form  S-1/A,  File  No.  333-52537,  filed on July 21,
            1998).

+3.2        Second  Amended and  Restated  Agreement of Limited  Partnership  of
            Enterprise  Products  Partners L.P. dated  September 17, 1999.  (The
            Company  incorporates  by reference the above  document  included as
            Exhibit "D" to the  Schedule 13D filed  September  27, 1999 by Tejas
            Energy, LLC.)

^3.3        First Amended and Restated Limited  Liability  Company  Agreement of
            Enterprise  Products GP, LLC dated September 17, 1999. (Exhibit 99.8
            on Form 8-K/A-1 filed October 27, 1999).

^3.4        Amendment No. 1 to Second Amended and Restated  Agreement of Limited
            Partnership of Enterprise Products Partners L.P. dated June 9, 2000.
            (Exhibit 3.6 to Form 10-Q filed August 11, 2000).

+4.1        Unitholder  Rights Agreement among Tejas Energy LLC, Tejas Midstream
            Enterprises,  LLC,  Enterprise  Products  Partners L.P.,  Enterprise
            Products  Operating L.P.,  Enterprise  Products Company,  Enterprise
            Products GP, LLC and EPC Partners II, Inc. dated September 17, 1999.
            (The Company  incorporates by reference the above document  included
            as Exhibit "C" to the Schedule 13D filed September 27, 1999 by Tejas
            Energy, LLC).

+4.2        Contribution  Agreement  between Tejas Energy LLC,  Tejas  Midstream
            Enterprises,  LLC,  Enterprise  Products  Partners L.P.,  Enterprise
            Products  Operating L.P.,  Enterprise  Products Company,  Enterprise
            Products GP, LLC and EPC Partners II, Inc. dated September 17, 1999.
            (The Company  incorporates by reference the above document  included
            as Exhibit "B" to the Schedule 13D filed September 27, 1999 by Tejas
            Energy, LLC).

^4.3        Form of  Indenture  dated as of March  15,  2000,  among  Enterprise
            Products  Operating L.P., as Issuer,  Enterprise  Products  Partners
            L.P.,  as  Guarantor,  and First Union  National  Bank,  as Trustee.
            (Exhibit 4.1 on Form 8-K filed March 10, 2000).



                                       52
<PAGE>

^4.4        Form of Global Note  representing  $350 million  principal amount of
            8.25%  Senior  Notes Due 2005.  (Exhibit 4.2 on Form 8-K filed March
            10, 2000).

*4.5        $250 Million Multi-Year  Revolving Credit Agreement among Enterprise
            Products   Operating   L.P.,   First   Union   National   Bank,   as
            administrative  agent; Bank One, NA, as documentation agent; and The
            Chase  Manhattan  Bank, as  syndication  agent and the Several Banks
            from time to time parties thereto dated November 17, 2000.  (Exhibit
            4.2 on Form 8-K filed January 25, 2001).

*4.6        $150 Million 364-Day Revolving Credit Agreement  between  Enterprise
            Products   Operating   L.P.  and  First  Union   National  Bank,  as
            administrative  agent; Bank One, NA, as documentation agent; and The
            Chase  Manhattan  Bank, as  syndication  agent and the Several Banks
            from time to time parties thereto dated November 17, 2000.  (Exhibit
            4.3 on Form 8-K filed January 25, 2001).

*4.7        Guaranty   Agreement   (relating  to  the  $250  Million  Multi-Year
            Revolving Credit Agreement) by Enterprise  Products Partners L.P. in
            favor of First Union  National Bank, as  administrative  agent dated
            November 17, 2000. (Exhibit 4.4 on Form 8-K filed January 25, 2001).

*4.8        Guaranty  Agreement  (relating to the $150 Million 364-Day Revolving
            Credit  Agreement) by Enterprise  Products Partners L.P. in favor of
            First Union  National Bank, as  administrative  agent dated November
            17, 2000. (Exhibit 4.5 on Form 8-K filed January 25, 2001).

*4.9        Form of Global Note  representing  $450 million  principal amount of
            7.50% Senior Notes due 2011.  (Exhibit 4.1 to Form 8-K filed January
            25, 2001).

^10.1       Articles of Merger of  Enterprise  Products  Company,  HSC  Pipeline
            Partnership,   L.P.,  Chunchula  Pipeline  Company,  LLC,  Propylene
            Pipeline   Partnership,   L.P.,  Cajun  Pipeline  Company,  LLC  and
            Enterprise Products Texas Operating L.P. dated June 1, 1998.(Exhibit
            10.1 to Registration  Statement on Form S-1/A,  File No:  333-52537,
            filed on July 8, 1998).

^10.2       Form of EPCO Agreement  between  Enterprise  Products Partners L.P.,
            Enterprise Products Operating L.P.,  Enterprise Products GP, LLC and
            Enterprise Products Company. (Exhibit 10.2 to Registration Statement
            on Form S-1/A, File No. 333-52537, filed on July 21, 1998).

^10.3       Transportation  Contract between Enterprise  Products Operating L.P.
            and Enterprise  Transportation  Company dated June 1, 1998. (Exhibit
            10.3 to Registration  Statement on Form S-1/A,  File No.  333-52537,
            filed on July 8, 1998).

^10.4       Venture  Participation  Agreement  between Sun Company,  Inc. (R&M),
            Liquid Energy Corporation and Enterprise  Products Company dated May
            1, 1992.  (Exhibit 10.4 to Registration  Statement on Form S-1, File
            No. 333-52537, filed on May 13, 1998).

^10.5       Partnership  Agreement  between Sun BEF,  Inc.,  Liquid Energy Fuels
            Corporation  and  Enterprise  Products  Company  dated May 1,  1992.
            (Exhibit  10.5 to  Registration  Statement  on Form  S-1,  File  No.
            333-52537, filed on May 13, 1998).

^10.6       Amended  and  Restated  MTBE  Off-Take   Agreement  between  Belvieu
            Environmental  Fuels and Sun  Company,  Inc.  (R&M) dated August 16,
            1995. (Exhibit 10.6 to Registration  Statement on Form S-1, File No.
            333-52537, filed on May 13, 1998).

^10.7       Propylene   Facility  and  Pipeline   Agreement  between  Enterprise
            Petrochemical  Company and Hercules  Incorporated dated December 13,
            1978. (Exhibit 10.9 to Registration  Statement on Form S-1, File No.
            333-52537, dated May 13, 1998).

^10.8       Restated  Operating  Agreement  for the Mont  Belvieu  Fractionation
            Facilities  Chambers  County,   Texas  between  Enterprise  Products
            Company,  Texaco  Producing Inc., El Paso  Hydrocarbons  Company and


                                       53
<PAGE>

            Champlin  Petroleum  Company dated July 17, 1985.  (Exhibit 10.10 to
            Registration  Statement on Form S-1/A, File No. 333-52537,  filed on
            July 8, 1998).

^10.9       Ratification  and  Joinder   Agreement   relating  to  Mont  Belvieu
            Associates  Facilities between Enterprise  Products Company,  Texaco
            Producing Inc., El Paso  Hydrocarbons  Company,  Champlin  Petroleum
            Company and Mont Belvieu  Associates  dated July 17, 1985.  (Exhibit
            10.11 to Registration  Statement on Form S-1/A,  File No. 333-52537,
            filed on July 8, 1998).

^10.10      Amendment  to  Propylene   Facility  and  Pipeline  Sales  Agreement
            between HIMONT U.S.A.,  Inc. and Enterprise  Products  Company dated
            January 1, 1993.  (Exhibit 10.12 to  Registration  Statement on Form
            S-1/A, File No. 333-52537, filed on July 8, 1998).

^10.11      Amendment to  Propylene  Facility  and  Pipeline  Agreement  between
            HIMONT U.S.A., Inc. and Enterprise Products Company dated January 1,
            1995.  (Exhibit 10.13 to Registration  Statement on Form S-1/A, File
            No. 333-52537, filed on July 8, 1998).

^10.12      Fourth  Amendment to Conveyance  of Gas  Processing  Rights  between
            Tejas  Natural  Gas  Liquids,  LLC  and  Shell  Oil  Company,  Shell
            Exploration  &  Production  Company,   Shell  Offshore  Inc.,  Shell
            Deepwater  Development  Inc.,  Shell Land & Energy Company and Shell
            Frontier Oil & Gas Inc. dated August 1, 1999. (Exhibit 10.14 to Form
            10-Q filed on November 15, 1999).

++12.1      Computation  of ratio of  earnings  to fixed  charges  for the years
            ended December 31, 2000, 1999, 1998, 1997 and 1996.

++21.1      List of subsidiaries.

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

*    Incorporated by reference to the filings of the Registrant as indicated

^    Incorporated by reference to the filings of Enterprise Products Partners
     L.P. as indicated

+    Incorporated by reference to the filings of Tejas Energy LLC as indicated

++   Filed herewith

(b)  Reports on Form 8-K

None.







                                       54
<PAGE>
                          INDEX TO FINANCIAL STATEMENTS


<TABLE>
<CAPTION>
                                                                                        Page
Enterprise Products Operating L.P.

<S>                                                                                       <C>
         Independent Auditors' Report                                                   F-2

         Consolidated Balance Sheets as of December 31, 2000 and 1999                   F-3

         Statements of Consolidated Operations
            for the Years Ended December 31, 2000, 1999 and 1998                        F-4

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

         Statements of Consolidated Partners' Equity
            for the Years Ended December 31, 2000, 1999 and 1998                        F-6

         Notes to Consolidated Financial Statements                                     F-7

Supplemental Schedule

         Schedule II - Valuation and Qualifying Accounts

</TABLE>





























     All schedules,  except the one listed above, have been omitted because they
 are either not applicable,  not required or the information  called for therein
 appears in the consolidated financial statements or notes thereto.


                                       F-1
<PAGE>

                          Independent Auditors' Report


Enterprise Products Operating L.P.:

We have  audited the  accompanying  consolidated  balance  sheets of  Enterprise
Products  Operating  L.P. (the  "Company") as of December 31, 2000 and 1999, 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, 2000.  Our audits also included the  consolidated  financial
statement  schedule  of the  Company  listed  in  the  Index  to  the  Financial
Statements.  These  consolidated  financial  statements  and  schedule  are  the
responsibility  of the  management  of the  Company.  Our  responsibility  is to
express an opinion on these consolidated financial statements and schedule 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, 2000 and 1999, 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, 2000 in conformity with accounting principles generally accepted in
the United States of America.  Also, in our opinion, such consolidated financial
statement  schedule,  when  considered  in  relation  to the basic  consolidated
financial statements taken as a whole,  presents fairly in all material respects
the information set forth therein.



/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 28, 2001


























                                       F-2
<PAGE>

<TABLE>
<CAPTION>
                       Enterprise Products Operating L.P.
                           Consolidated Balance Sheets
                             (Dollars in Thousands)

                                                                                               December 31,
                                     ASSETS                                              2000                1999
                                                                                  ---------------------------------------
<S>                                                                                       <C>                 <C>
Current Assets
     Cash and cash equivalents                                                           $     58,446       $      5,159
     Accounts receivable - trade, net of allowance for doubtful accounts of
        $10,916 in 2000 and $15,897 in 1999                                                   409,085            262,348
     Accounts receivable - affiliates                                                           5,738             53,906
     Inventories                                                                               93,222             39,907
     Current maturities of participation in notes receivable from
        unconsolidated affiliates                                                                                  6,519
     Prepaid and other current assets                                                          12,143             14,459
                                                                                  ---------------------------------------
               Total current assets                                                           578,634            382,298
Property, Plant and Equipment, Net                                                            975,322            767,069
Investments in and Advances to Unconsolidated Affiliates                                      298,954            280,606
Intangible assets, net of accumulated amortization of $5,374 in
     2000 and $1,345 in 1999                                                                   92,869             61,619
Other Assets                                                                                    2,984              1,120
                                                                                  ---------------------------------------
               Total                                                                     $  1,948,763       $  1,492,712
                                                                                  =======================================

                        LIABILITIES AND PARTNERS' EQUITY
Current Liabilities
     Current maturities of long-term debt                                                                   $    129,000
     Accounts payable - trade                                                            $     96,560             69,294
     Accounts payable - affiliate                                                              56,447             64,780
     Accrued gas payables                                                                     377,126            233,360
     Accrued expenses                                                                          20,579             16,148
     Other current liabilities                                                                 34,763             18,176
                                                                                  ---------------------------------------
               Total current liabilities                                                      585,475            530,758
Long-Term Debt                                                                                404,000            166,000
Other Long-Term Liabilities                                                                    15,613                296
Minority Interest                                                                               1,004              1,032
Commitments and Contingencies
Partners' Equity
     Limited Partner                                                                          937,829            791,279
     General Partner                                                                            9,569              8,074
     Parent's Units acquired by Trust                                                          (4,727)            (4,727)
                                                                                  ---------------------------------------
               Total Partners' Equity                                                         942,671            794,626
                                                                                  ---------------------------------------
               Total                                                                     $  1,948,763       $  1,492,712
                                                                                  =======================================
</TABLE>

                 See Notes to Consolidated Financial Statements












                                       F-3
<PAGE>

<TABLE>
<CAPTION>
                       Enterprise Products Operating L.P.
                      Statements of Consolidated Operations
                             (Amounts in Thousands)

                                                                          Years Ended December 31,
                                                             ----------------------------------------------------
                                                                   2000              1999             1998
                                                             ----------------------------------------------------
<S>                                                                <C>              <C>               <C>
REVENUES
Revenues from consolidated operations                              $ 3,049,020      $ 1,332,979       $  738,902
Equity income in unconsolidated affiliates                              24,119           13,477           15,671
                                                             ----------------------------------------------------
         Total                                                       3,073,139        1,346,456          754,573
COST AND EXPENSES
Operating costs and expenses                                         2,801,060        1,201,605          685,884
Selling, general and administrative                                     28,345           12,500           18,216
                                                             ----------------------------------------------------
         Total                                                       2,829,405        1,214,105          704,100
                                                             ----------------------------------------------------
OPERATING INCOME                                                       243,734          132,351           50,473
                                                             ----------------------------------------------------
OTHER INCOME (EXPENSE)
Interest expense                                                       (33,329)         (16,439)         (15,057)
Interest income from unconsolidated affiliates                           1,662            1,625              809
Dividend income from unconsolidated affiliates                           7,091            3,435
Interest income - other                                                  4,295            1,247              772
Other, net                                                                (272)            (379)             358
                                                             ----------------------------------------------------
          Other income  (expense)                                      (20,553)         (10,511)         (13,118)
                                                             ----------------------------------------------------
INCOME BEFORE EXTRAORDINARY ITEM
   AND MINORITY INTEREST                                               223,181          121,840           37,355
Extraordinary charge on early extinguishment of debt                                                     (27,176)
                                                             ----------------------------------------------------
INCOME BEFORE MINORITY INTEREST                                        223,181          121,840           10,179
MINORITY INTEREST                                                         (113)            (110)            (122)
                                                             ----------------------------------------------------
NET INCOME                                                         $   223,068      $   121,730       $   10,057
                                                             ====================================================
</TABLE>

                 See Notes to Consolidated Financial Statements

























                                       F-4
<PAGE>

<TABLE>
<CAPTION>
                       Enterprise Products Operating L.P.
                      Statements of Consolidated Cash Flows
                             (Amounts in Thousands)

                                                                                    Year Ended December 31,
                                                                         -----------------------------------------------
                                                                              2000            1999            1998
                                                                         -----------------------------------------------
<S>                                                                           <C>             <C>            <C>
OPERATING ACTIVITIES
Net income                                                                    $  223,068      $  121,730     $   10,057
Adjustments to reconcile net income to cash flows provided by
     (used for) operating activities:
     Extraordinary item - early extinguishment of debt                                                           27,176
     Depreciation and amortization                                                41,016          25,315         19,194
     Equity in income of unconsolidated affiliates                               (24,119)        (13,477)       (15,671)
     Distributions received from unconsolidated affiliates                        37,267           6,008          9,117
     Leases paid by EPCO                                                          10,644          10,665          4,010
     Minority interest                                                               113             110            122
     (Gain) loss on sale of assets                                                 2,270             123           (276)
     Net effect of changes in operating accounts                                  68,482          27,568        (63,171)
                                                                         -----------------------------------------------
Operating activities cash flows                                                  358,741         178,042         (9,442)
                                                                         -----------------------------------------------
INVESTING ACTIVITIES
Capital expenditures                                                            (243,913)        (21,235)        (8,360)
Proceeds from sale of assets                                                          92               8          1,887
Business acquisitions, net of cash acquired                                                     (208,095)
Participation in notes receivable from unconsolidated affiliates:
     Purchase of notes receivable                                                                               (33,725)
     Collection of notes receivable                                                6,519          19,978          7,228
Investments in and advances to unconsolidated affiliates                         (31,496)        (61,887)       (26,842)
                                                                         -----------------------------------------------
Investing activities cash flows                                                 (268,798)       (271,231)       (59,812)
                                                                         -----------------------------------------------
FINANCING ACTIVITIES
Cash contributions from limited partner                                                                         243,296
Cash contributions from minority interest                                              5               7
Long-term debt borrowings                                                        599,000         350,000         90,000
Long-term debt repayments                                                       (490,000)       (154,923)      (257,413)
Debt issuance costs                                                              ( 4,043)         (3,135)        (1,735)
Net decrease in restricted cash                                                                                   4,522
Cash distributions to partners                                                  (141,472)       (112,899)       (21,865)
Cash distributions to minority interest                                             (146)            (78)
Parent's Units acquired by consolidated Trust                                                     (4,727)
                                                                         -----------------------------------------------
Financing activities cash flows                                                  (36,656)         74,245         56,805
                                                                         -----------------------------------------------
CASH CONTRIBUTION FROM EPCO                                                                                      17,611
                                                                         -----------------------------------------------
NET CHANGE IN CASH AND CASH EQUIVALENTS                                           53,287         (18,944)         5,162
CASH AND CASH EQUIVALENTS, JANUARY 1                                               5,159          24,103         18,941
                                                                         -----------------------------------------------
CASH AND CASH EQUIVALENTS, DECEMBER 31                                        $   58,446      $    5,159     $   24,103
                                                                         ===============================================
</TABLE>

                 See Notes to Consolidated Financial Statements












                                       F-5
<PAGE>

<TABLE>
<CAPTION>
                       Enterprise Products Operating L.P.
                   Statements of Consolidated Partners' Equity
                             (Amounts in Thousands)

                                                                Limited        General        Parent's
                                                                Partner        Partner          Units          Total
                                                             -------------------------------------------------------------
<S>                <C> <C>                                        <C>             <C>           <C>             <C>
Balances, December 31, 1997                                       $ 310,991       $  3,173                      $ 314,164
       Net income                                                     9,955            102                         10,057
       Cash contributions by EPCO                                    17,433            178                         17,611
       Leases paid by EPCO                                            3,969             41                          4,010
       Cash contributions by partners                               240,839          2,457                        243,296
       Cash distributions to partners                               (21,644)          (221)                       (21,865)
                                                             -------------------------------------------------------------
Balances, December 31, 1998                                         561,543          5,730                        567,273
       Net income                                                   120,501          1,229                        121,730
       Leases paid by EPCO                                           10,557            108                         10,665
       Asset contributions by partners related to
          business acquisitions                                     210,436          2,147                        212,583
       Parent's Units acquired by consolidated Trust                                               (4,727)         (4,727)
       Cash distributions to partners                              (111,758)        (1,140)                      (112,898)
                                                             -------------------------------------------------------------
Balances, December 31, 1999                                         791,279          8,074         (4,727)        794,626
       Net income                                                   220,815          2,253                        223,068
       Leases paid by EPCO                                           10,537            107                         10,644
       Asset contributions by partners related to
          business acquisitions                                      55,241            564                         55,805
       Cash distributions to partners                              (140,043)        (1,429)                      (141,472)
                                                             -------------------------------------------------------------
Balances, December 31, 2000                                       $ 937,829       $  9,569      $  (4,727)      $ 942,671
                                                             =============================================================
</TABLE>

                 See Notes to Consolidated Financial Statements

























                                       F-6
<PAGE>

                       Enterprise Products Operating L.P.
                   Notes to Consolidated Financial Statements


1.  ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

ENTERPRISE  PRODUCTS  OPERATING L.P. (the "Company") was formed on April 9, 1998
as a Delaware  limited  partnership  to own and  operate the natural gas liquids
("NGL") business of Enterprise Products Company ("EPCO").  The Company's limited
partner,  Enterprise  Products  Partners  L.P.  (the  "Limited  Partner"),  owns
98.9899% of the Company.  Enterprise Products GP, LLC (the "General Partner") is
the general  partner and owns 1.0101% of the Company.  Both the Limited  Partner
and the General Partner are subsidiaries of EPCO.

Prior to their consolidation,  EPCO and its affiliated 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 the
Company,  EPCO contributed all of its NGL assets through the Limited Partner and
the General  Partner to the Company  and the Company  assumed  certain of EPCO's
debt. As a result,  the Company  became the  successor to the NGL  operations of
EPCO.

Effective  July 27, 1998,  the Limited  Partner filed a  registration  statement
pursuant to an initial public offering  ("IPO") of 12,000,000  Common Units. The
Common Units sold for $22 per unit. The Limited Partner contributed the proceeds
of the IPO of  approximately  $243.3 million after  underwriting  commissions of
$16.8 million and expenses of approximately $3.9 million to the Company.

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 the accounts of the Company
and  its  majority-owned   subsidiaries,   after  elimination  of  all  material
intercompany  accounts and  transactions.  In general,  investments in which the
Company owns 20% to 50% and exercises  significant  influence over operating and
financial  policies are accounted for using the equity  method.  Investments  in
which the  Company  owns less than 20% are  accounted  for using the cost method
unless the Company exercises  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,  the
Company  considers all highly liquid debt instruments with an original  maturity
of less than three months at the date of purchase to be cash equivalents.

DERIVATIVE 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. Prior to the implementation of
SFAS 133 in  January  2001 (see Note 10),  the  Company  deferred  the impact of
changes in the  market  value of these  contracts  until such time as the hedged
transaction  was settled.  At that time, the impact of the changes in fair value
of these contracts would be recognized in earnings.

Under SFAS 133, the Company is required to recognize in earnings changes in fair
value of these derivative instruments that are not offset by changes in the fair
value of the inventories, firm commitments and certain anticipated transactions.
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 the Company to  commodity  or interest
rate risk and the hedging  instrument  must reduce  that  exposure  and meet the


                                       F-7
<PAGE>

hedging  requirements of SFAS 133. Any contracts held or issued that do not meet
the  requirements  of a hedge (as  defined by SFAS 133) will be recorded at fair
value on the  balance  sheet and any  changes in that fair value  recognized  in
earnings.  If a contract  designated as a hedge of commodity risk is terminated,
the  associated  gain or loss is deferred and recognized in income when the firm
commitment or anticipated transaction affects earnings. A contract designated as
a hedge of an  anticipated  transaction  that is no  longer  likely  to occur is
immediately recognized in earnings.

DOLLAR AMOUNTS  presented in the  tabulations  within the notes to the Company's
financial  statements  are stated in  thousands  of  dollars,  unless  otherwise
indicated.

ENVIRONMENTAL  COSTS for  remediation  are accrued  based on  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,  2000  were  not  significant  to the  consolidated
financial   statements.   Costs  of  environmental   compliance  and  monitoring
aggregated  $1.1  million,  $0.9  million  and $1.4  million for the years ended
December  31,  2000,  1999 and  1998.  The  Company's  estimated  liability  for
environmental remediation is not discounted.

EXCESS COST OVER UNDERLYING  EQUITY IN NET ASSETS (or "excess cost") denotes the
excess of the Company's cost (purchase price) over the underlying  equity in net
assets  of K/D/S  Promix,  LLC and  Dixie  Pipeline  Company.  The  excess  cost
associated  with the  Company's  investment  in K/D/S Promix is being  amortized
using  the  straight-line  method  over a period of 20 years.  The  excess  cost
related to the Company's investment in Dixie Pipeline Company is being amortized
using  the  straight-line   method  over  a  period  of  35  years  due  to  its
classification  as a pipeline  asset.  The excess cost of K/D/S Promix,  LLC and
Dixie Pipeline Company is reflected in the Company's 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 products  between  parties to satisfy  timing and
logistical needs of the parties. NGLs and NGL products borrowed from the Company
under such  agreements  are included in  inventories,  and NGLs and NGL products
loaned to the  Company  under such  agreements  are  accrued as a  liability  in
accrued gas payables.

FEDERAL INCOME TAXES are not provided  because the Company and its  predecessors
either  had  elected  under  provisions  of the  Internal  Revenue  Code to be a
partnership  or  Subchapter S  Corporation  or were  organized as other types of
pass-through  entities for federal income tax purposes. As a result, for federal
income taxes purposes, the owners are individually  responsible for the taxes on
their allocable share of the consolidated  taxable income of the Company.  State
income taxes are not material to the Company.

INVENTORIES,  consisting of NGLs and NGL  products,  are carried at the lower of
average cost or market.

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,  both of which
were initially recorded in 1999. The $89.3 million in intangibles related to the
natural gas processing  agreement is being amortized over the contract term. The
$9.0 million excess cost of the purchase price over the fair market value of the
assets  acquired from Mont Belvieu  Associates is being amortized over 20 years.
See Note 2 for additional information regarding these assets.

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. The Company has 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.  Additions and
improvements  to and major  renewals  of  existing  assets are  capitalized  and


                                       F-8
<PAGE>

depreciated using the straight-line method over the estimated useful life of the
new equipment or  modifications.  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 recognized by the Company's five reportable  business  segments using
the  following  criteria:  (a)  persuasive  evidence of an exchange  arrangement
exists,  (b)  delivery  has  occurred or services  have been  rendered,  (c) the
buyer's  price is fixed or  determinable  and (d)  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  the  Fractionation  segment,  the  Company  enters  into  NGL  fractionation
contracts,  isomerization  contracts  and propylene  fractionation  and merchant
contracts.  Under the propylene merchant  contracts,  revenue is recognized once
the products have been effectively  delivered to the third party.  Regarding the
various NGL and propylene  fractionation and  isomerization  contracts whereby a
toll fee is  collected,  revenue is recognized  once the contract  services have
been performed.  Fractionation and isomerization  contracts  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 these
operations. The propylene merchant contracts are based upon market rates or spot
prices as determined in the individual contracts.

As part of its Pipeline operations,  the Company enters into pipeline contracts,
storage contracts and product loading contracts.  Under the pipeline  contracts,
revenue is recognized  once the products have been  physically  delivered to the
third party through the pipeline.  Under the storage  contracts whereby a fee is
collected  based upon the number of days in storage  multiplied  by the  storage
rate by product,  revenue is  recognized  ratably over the length of the storage
contract.  In the  absence  of a set period  under  contractual  terms,  storage
revenue is  recognized  based upon a daily rate as specified  in the  applicable
contract.  Revenues for product loading contracts  (applicable to the operations
of EPIK, an  unconsolidated  affiliate)  are recorded once the loading  services
have been performed.  Pipeline contracts  typically include a throughput fee per
gallon  as  stated  in  the  contract  or as  regulated  by the  Federal  Energy
Regulatory  Committee  ("FERC").  Storage  and  loading  rates are stated in the
individual contracts.

As part of its Processing  business,  the Company entered into a 20-year natural
gas processing agreement with Shell ("Shell Processing Agreement"),  whereby the
Company has 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. This includes natural gas production from the
developments  currently  referred to as deepwater.  This  contract  serves as an
arrangement  between the Company and Shell. In addition to the Shell  Processing
Agreement,  the Company  has  contracts  to process  natural gas for other third
parties.

Under  these  contracts,  the  price of the  Company's  services  is based  upon
contractual  terms with Shell or other  third  parties and may be  specified  as
either  (i) a cash  fee or  (ii)  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,  the  Company  records  revenue  once the natural gas has been
processed and sent back to Shell or the other third parties (i.e.,  delivery has
taken place).

If the contract  stipulates  that the Company  retains a percentage  of the NGLs
extracted  as  payment  for its  services,  the  Processing  segment's  merchant
business  records revenues when it sells and delivers such NGL products to third
parties.  The Processing  segment's merchant business may also buy and sell NGLs
in the open market.  The revenues  recorded for these  contracts are  recognized
upon delivery of the products  specified in each  individual  contract.  Pricing
under both types of arrangements is based upon market prices plus or minus other
determining   factors  specific  to  each  contract  such  as  location  pricing
differentials.

The Octane  Enhancement  segment  consists of the Company's  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 has agreed to purchase 100 percent of the MTBE
output at  market-related  negotiated  prices.  Under the contract with Sun, 100
percent of the MTBE  production is delivered to Sun and Sun is obligated to take
title to the product. Revenue is recognized once the product has been physically
delivered to Sun.



                                       F-9
<PAGE>

The Other segment is primarily comprised of fee-based  marketing  services.  The
Company  performs NGL  marketing  services  for a small number of customers  for
which it charges 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 marketing 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. Actual results could differ from these estimates.


2.  ACQUISITIONS

Acquisition  of Kinder  Morgan and EPCO  interest in Mont Belvieu  Fractionation
Facility in July 1999

Effective July 1, 1999, the Company  acquired  Kinder Morgan  Operating LP "A"'s
25%  interest  and  EPCO's  0.5%  interest  in a 210,000  BPD NGL  fractionation
facility located in Mont Belvieu,  Texas for  approximately  $42 million in cash
and the assumption of approximately $ 4 million of debt. The $42 million in cash
was  funded  with  borrowings  under the  Company's  $350  million  bank  credit
facility.

The  acquisition  was accounted for under the purchase method of accounting and,
accordingly,  the purchase price has been allocated to the assets  purchased and
liabilities  assumed  based on their  estimated  fair  value at July 1,  1999 as
follows (in millions):

Property                                     $   36.2
Intangible asset                                  9.0
Liabilities                                      (3.7)
                                      ----------------
Total purchase price                         $   41.5
                                      ================

The intangible  asset represents the excess cost of purchase price over the fair
market value of the assets  acquired and is being  amortized over 20 years.  For
the years ending  December  31, 2000 and 1999,  $0.5 million and $0.2 million of
such amortization was charged to operating costs and expenses.

Acquisition of Tejas Natural Gas Liquids, LLC in August 1999

Effective  August 1, 1999, the Company  acquired Tejas Natural Gas Liquids,  LLC
("TNGL")  from a  subsidiary  of Tejas  Energy,  LLC, an  affiliate of Shell Oil
Company.  All  references  hereafter  to "Shell",  unless the context  indicates
otherwise,  shall refer collectively to Shell Oil Company,  its subsidiaries and
affiliates.  TNGL  engages  in natural  gas  processing  and NGL  fractionation,
transportation,  storage and  marketing in Louisiana and  Mississippi.  TNGL has
varying   interests  in  eleven   natural  gas  processing   plants,   four  NGL
fractionation facilities, four NGL storage facilities, approximately 1,500 miles
of pipelines and is a party to the Shell Processing Agreement, a 20 year natural
gas processing agreement.

The TNGL  acquisition  was purchased  with a combination of $166 million in cash
and the issuance of 14.5 million non-distribution  bearing,  convertible Special
Units of the Limited  Partner.  The $166  million  cash  portion of the purchase
price was funded with  borrowings  under the Company's  $350 million bank credit
facility.  The  Limited  Partner's  Special  Units  were  valued  within a range
provided by an independent  investment banker using both present value and Black
Scholes Model  methodologies.  The value of the Special Units of $210.4  million
was contributed by the Limited Partner to the Company.

As part of the  agreements  to purchase the TNGL assets from Shell,  the Limited
Partner agreed to issue up to 6.0 million additional  non-distribution  bearing,
convertible  Special Units to Shell provided that certain  performance  criteria
were met in  calendar  years  2000  and  2001.  In  general,  if  Shell  met the
performance criteria for 2000, 3.0 million of the Special Units would be issued;
likewise,  if Shell met the 2001 goals,  the remaining 3.0 million Special Units


                                       F-10
<PAGE>

would be issued.  The Limited Partner issued 3.0 million Special Units in August
2000 due to Shell's  successful  completion of the 2000  performance  test.  The
$55.2  million  value of the new Special  Units was  contributed  by the Limited
Partner to the Company.

The  acquisition  was accounted for under the purchase method of accounting and,
accordingly,  the purchase price has been  allocated to the assets  acquired and
liabilities  assumed based on their  estimated fair value at August 1, 1999. The
following table reflects the allocation of the initial purchase price, the value
of the 3.0 million new Special  Units and purchase  accounting  adjustments  (in
millions):

Current Assets                               $  124.3
Investments                                     128.6
Property                                        216.9
Intangible asset                                 89.3
Liabilities                                    (147.4)
                                      ----------------
Total Purchase Price                         $  411.7
                                      ================

The $89.3 million intangible asset is the value assigned to the Shell Processing
Agreement and is being  amortized  over the contract  term. For the years ending
December 31, 2000 and 1999,  $3.6 million and $1.1 million of such  amortization
was charged to operating  costs and expenses.  Beginning in December 2000,  such
amortization  increased to $0.4 million per month.  The assets,  liabilities and
results of  operations  of TNGL are  included  with  those of the  Company as of
August 1, 1999.  If the remainder of the Special Units are issued in 2001 (or at
such later date as agreed to by the  parties),  the purchase  price and value of
the  Shell  Processing  Agreement  will  be  adjusted  accordingly.   Historical
information  for  periods  prior to  August 1, 1999 do not  reflect  any  impact
associated with the TNGL acquisition.

Pro Forma effect of Acquisitions

The following table presents unaudited pro forma information for the years ended
December  31, 1999 and 1998 as if the  acquisition  of TNGL and the Mont Belvieu
fractionator  facility  had  been  made  as of  the  beginning  of  the  periods
presented.  The pro  forma  information  is  based  upon  information  currently
available to and certain  estimates  and  assumptions  by  management  and, as a
result,  are not necessarily  indicative of the financial results of the Company
had the transactions actually occurred on these dates.  Likewise,  the unaudited
pro forma information is not necessarily  indicative of future financial results
of the Company.

                                                    1999          1998
                                               -----------------------------
Revenues                                           $1,726,516     $1,366,450
                                               =============================
Net income                                         $  136,598     $   14,680
                                               =============================
Allocation of net income to
     Limited partners                               $ 135,218     $   14,532
                                               =============================
     General Partner                                $   1,380     $     148
                                               =============================













                                       F-11
<PAGE>

Acadian Gas, LLC

On September 25, 2000,  the Company  announced that it had executed a definitive
agreement  to purchase  Acadian  Gas,  LLC  ("Acadian")  from Coral  Energy,  an
affiliate of Shell, for $226 million in cash, inclusive of working capital.

Acadian's  assets are comprised of the 438-mile  Acadian,  577-mile  Cypress and
27-mile  Evangeline  natural gas pipeline systems,  which together have over one
billion  cubic feet  ("Bcf") per day of  capacity.  These  natural gas  pipeline
systems are wholly-owned by Acadian with the exception of the Evangeline  system
in which Acadian holds an  approximate  49.5%  interest.  The system  includes a
leased natural gas storage facility at Napoleonville,  Louisiana.  Completion of
this  transaction  is  subject  to  certain  conditions,   including  regulatory
approvals.  The purchase is expected to be completed during the first quarter of
2001.


3.  PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment and accumulated depreciation are as follows:

<TABLE>
<CAPTION>
                                                      Estimated
                                                      Useful Life
                                                       in Years           2000             1999
                                                   ---------------------------------------------------
<S>                                                      <C>              <C>               <C>
Plants and pipelines                                     5-35             $1,108,519        $  875,773
Underground and other storage facilities                 5-35                109,760           103,578
Transportation equipment                                 3-35                  2,620             2,117
Land                                                                          14,805            14,748
Construction in progress                                                      34,358            32,810
                                                                     ----------------------------------
   Total                                                                   1,270,062         1,029,026
Less accumulated depreciation                                                294,740           261,957
                                                                    ----------------------------------
Property, plant and equipment, net                                        $  975,322        $  767,069
                                                                    ==================================
</TABLE>

Depreciation  expense for the years ended  December 31, 2000,  1999 and 1998 was
$33.3 million, $22.4 million and $18.6 million, respectively.


4.  INVESTMENTS IN AND ADVANCES TO UNCONSOLIDATED AFFILIATES

The Company owns interests in a number of related  businesses that are accounted
for under the equity method 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 the  Company's  business
segments, see Note 13.

At December 31, 2000, the Company's Fractionation operating segment included the
following unconsolidated affiliates (all accounted for using the equity method):

-    Baton Rouge Fractionators LLC ("BRF") - an approximate 32.25% interest in a
     natural gas liquid ("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 that became
     operational in July 2000.

-    K/D/S  Promix LLC  ("Promix")  - a 33.33%  interest in a NGL  fractionation
     facility and related storage  facilities  located in south  Louisiana.  The
     Company's investment includes excess cost over the underlying equity in the
     net assets of Promix of $8.0  million  which is being  amortized  using the
     straight-line  method over a period of 20 years.  The amortized  balance of
     excess cost over the underlying equity in the net assets of Promix was $7.4
     million at December 31, 2000.



                                       F-12
<PAGE>

The  combined  results  of  operations  for the last three  years and  financial
position for the last two years of the  Company's  Fractionation  equity  method
investments are summarized below:

<TABLE>
<CAPTION>
                                                                     As of or for the
                                                                  Year Ended December 31,
                                                          2000             1999              1998
                                                    ----------------------------------------------------
<S>                                                        <C>               <C>
BALANCE SHEET DATA:
     Current assets                                       $   31,168        $   47,235
     Property, plant and equipment, net                      264,618           245,855
     Other assets                                                 67               854
                                                    -----------------------------------
         Total assets                                     $  295,853        $  293,944
                                                    ===================================

     Current liabilities                                  $   13,661        $   32,646
     Combined equity                                         282,192           261,298
                                                    -----------------------------------
         Total liabilities and combined equity            $  295,853        $  293,944
                                                    ===================================
INCOME STATEMENT DATA:
     Revenues                                             $   71,287        $   36,293        $  31,881
     Gross operating margin                                   33,240            14,970           12,154
     Operating income                                         19,997             5,930            9,840
     Net income                                               20,661             4,200            9,271
</TABLE>


At December 31, 2000,  the Company's  Pipeline  operating  segment  included the
following unconsolidated affiliates (all 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.  The Company owns 50%
     of EPIK Gas Liquids, LLC which owns 1% of such facilities. The Company does
     not exercise control over these entities;  therefore,  it is precluded from
     consolidating such entities into its financial statements.

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

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

-    Belle Rose NGL  Pipeline  LLC  ("Belle  Rose") - a 41.7%  interest in a NGL
     pipeline system located in south Louisiana.

-    Dixie Pipeline Company ("Dixie") - a 19.9% interest in a corporation owning
     a 1,301-mile propane pipeline and associated facilities extending from Mont
     Belvieu, Texas to North Carolina. The Company acquired an 11.5% interest in
     Dixie as a result of the TNGL acquisition.  On October 6, 2000, the Company
     purchased  an  additional  8.4%  interest  in Dixie from  Conoco  Pipe Line
     Company  for  $19.4  million  in cash.  As a result of this  purchase,  the
     Company is able to exercise  significant  influence over Dixie's  operating
     and  financial  activities  and  changed its method of  accounting  for the
     investment in Dixie from the cost method to the equity method.  This change
     in accounting methods for Dixie resulted in a immaterial  cumulative effect
     of $0.2 million in expense being recorded in 2000 relating to the period in
     which the Company  held an ownership  interest in Dixie  during  1999.  The
     cumulative  effect is  recorded  as a  reduction  of  current  year  equity
     earnings from Dixie due to its immaterial nature.

     As a result of  changing  from the cost  method to the equity  method,  the
     Company's  investment  in Dixie  includes  excess cost over the  underlying
     equity in the net assets of $37.4  million which is being  amortized  using


                                       F-13
<PAGE>

     the   straight-line   method   over  a  period  of  35  years  due  to  its
     classification  as a pipeline  asset.  During  2000,  the Company  recorded
     amortization  expense  associated  with this  excess  cost of $0.9  million
     (including the cumulative  effect of $0.2 million related to 1999 mentioned
     previously),  which is  reflected  in the  equity  earnings  of Dixie.  The
     unamortized  balance of excess cost over the  underlying  equity in the net
     assets of Dixie was $36.3 million at December 31, 2000.

The  combined  results  of  operations  for the last three  years and  financial
position  for the  last  two  years  of the  Company's  Pipeline  equity  method
investments are summarized below:

<TABLE>
<CAPTION>
                                                                     As of or for the
                                                                  Year Ended December 31,
                                                    ----------------------------------------------------
                                                          2000             1999              1998
                                                    ----------------------------------------------------
<S>                                                        <C>               <C>              <C>
BALANCE SHEET DATA:
     Current assets                                       $   25,464        $   26,483
     Property, plant and equipment, net                      188,724           193,237
     Other assets                                              3,666             3,172
                                                    -----------------------------------
         Total assets                                     $  217,854        $  222,892
                                                    ===================================

     Current liabilities                                  $   31,085        $   32,873
     Other liabilities                                         4,018             4,317
     Combined equity                                         182,751           185,702
                                                    -----------------------------------
         Total liabilities and combined equity            $  217,854        $  222,892
                                                    ===================================
INCOME STATEMENT DATA:
     Revenues                                             $   96,270        $   52,385        $   3,982
     Gross operating margin                                   51,414            24,845            1,869
     Operating income                                         41,757            19,988            1,775
     Net income                                               31,241            15,637            1,777
</TABLE>

At December 31, 2000, the Octane Enhancement  operating segment included Belvieu
Environmental Fuels ("BEF") in which the Company owns a 33.33% interest.  BEF is
a  partnership  that owns a methyl  tertiary  butyl  ether  ("MTBE")  production
facility  located within the Company's Mont Belvieu  complex.  The production of
MTBE is driven by oxygenated  fuels programs enacted under the federal Clean Air
Act Amendments of 1990 and other legislation. Any changes to these programs that
enable  localities to elect not to  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 the
Company's 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 of
these  detections  have been well below levels of public health  concern,  there
have been actions calling for the phase-out of MTBE in motor gasoline in various
federal and state governmental agencies.

In light of these developments,  the owners of BEF are 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.  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 can range from $20 million
to $90  million,  with the  Company's  share of these  costs  ranging  from $6.7
million to $30 million.

BEF has a ten-year off-take agreement with Sun Company, Inc. ("Sun") under which
Sun is required to purchase all of the plant's MTBE production through September
2004.  Through  May 31,  2000,  Sun was  required  to pay for the MTBE using the
following pricing structure:

-    for the first  193,450,000  gallons of MTBE produced per contract year, the
     higher  of  (i)  a  contractual   floor  price  or  (ii)  a  toll  or  spot
     market-related price (as defined within the agreement); and,
-    a spot market-related price for all volumes in excess of this amount.



                                       F-14
<PAGE>

The  floor  price  was a price  sufficient  to  cover  essentially  all of BEF's
operating  costs plus principal and interest  payments on its bank term loan. In
general,  Sun paid the floor price during the periods in which it was in effect.
Beginning  June 1, 2000 through the remainder of the  agreement,  the pricing on
all MTBE  delivered to Sun changed to a  market-related  negotiated  price which
generally   approximates  Gulf  Coast  MTBE  spot  prices.   The  market-related
negotiated  price is subject to fluctuations in commodity  prices for MTBE. MTBE
spot prices are generally  higher  during the April to September  period of each
year which corresponds with the summer driving season.

The results of operations  for the last three years and  financial  position for
the last two years of the Company's investments in BEF are summarized below:

<TABLE>
<CAPTION>
                                                                        As of or for the
                                                                     Year Ended December 31,
                                                       ----------------------------------------------------
                                                             2000              1999             1998
                                                       ----------------------------------------------------
<S>                                                            <C>              <C>             <C>
     BALANCE SHEET DATA:
         Current assets                                       $   20,640       $   44,261
         Property, plant and equipment, net                      150,603          161,390
         Other assets                                             11,439            8,313
                                                       -----------------------------------
             Total assets                                     $  182,682       $  213,964
                                                       ===================================

         Current liabilities                                  $    8,042       $   41,317
         Other liabilities                                         5,779            4,323
         Combined equity                                         168,861          168,324
                                                       -----------------------------------
             Total liabilities and combined equity            $  182,682       $  213,964
                                                       ===================================
     INCOME STATEMENT DATA:
         Revenues                                             $  258,180       $  193,219       $  182,001
         Gross operating margin                                   43,328           43,479           47,262
         Operating income                                         30,529           30,025           33,930
         Income before accounting change                          31,220           29,029           29,401
         Net income                                               31,220           24,550           29,401
</TABLE>

The Company's  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 LLC owning a natural  gas  processing  plant,
fractionation  facilities,  storage,  and gas gathering  pipelines in Louisiana.
This investment is accounted for using the cost method.

During the third quarter of 1999, the Company  acquired the remaining  interests
in Mont Belvieu  Associates,  51%,  ("MBA") and Entell NGL  Services,  LLC, 50%,
("Entell").  After the acquisition of the remaining interests, MBA was dissolved
by the Company and Entell became a wholly owned subsidiary of the Company.


















                                       F-15
<PAGE>

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

                                                     December 31,
                                        ---------------------------------------
                                               2000                1999
                                        ---------------------------------------
Accounted for on equity basis:
    BEF                                         $   58,677          $   63,004
    Promix                                          48,670              50,496
    BRF                                             30,599              36,789
    Tri-States                                      27,138              28,887
    EPIK                                            15,998              15,258
    Belle Rose                                      11,653              12,064
    BRPC                                            25,925              11,825
    Wilprise                                         9,156               9,283
    Dixie                                           38,138              20,000
Accounted for  on cost basis:
    VESCO                                           33,000              33,000
                                        ---------------------------------------
Total                                          $   298,954         $   280,606
                                        =======================================

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

                            2000              1999               1998
                     --------------------------------------------------------
BEF                          $   10,407         $   8,183          $   9,801
MBA                                                 1,256              5,213
BRF                               1,369              (336)               (91)
BRPC                               (284)               16
EPIK                              3,273             1,173                748
Wilprise                            497               160
Tri-States                        2,499             1,035
Promix                            5,306               630
Belle Rose                          301               (29)
Dixie                               751
Other                                               1,389
                     --------------------------------------------------------
Total                        $   24,119        $   13,477         $   15,671
                     ========================================================

At  December  31,  2000,  the  Company's   share  of  accumulated   earnings  of
unconsolidated  affiliates  that  had  not  been  remitted  to the  Company  was
approximately $26.7 million.


5.       NOTES RECEIVABLE FROM UNCONSOLIDATED AFFILIATES

At December 31, 1999, the Company held a participation interest in the bank loan
of BEF for $6.5 million.  The BEF bank loan matured on May 31, 2000.  With BEF's
final payment, the Company's receivable relating to its participation in the BEF
note was extinguished.












                                       F-16
<PAGE>

6.  LONG-TERM DEBT

Long-term debt consisted of the following at:

<TABLE>
<CAPTION>
                                                                 December 31,
                                                    ---------------------------------------
                                                           2000                1999
                                                    ---------------------------------------
<S>                                                             <C>                <C>
Borrowings under:
     $200 Million Bank Credit Facility (1)                                     $   129,000
     $350 Million Bank Credit Facility (1)                                         166,000
     $350 Million Senior Notes (2)                          $   350,000
     $54 Million MBFC Loan (3)                                   54,000
                                                    ---------------------------------------
            Total                                               404,000            295,000
Less current maturities of long-term debt                                          129,000
                                                    ---------------------------------------
            Long-term debt (4)                              $   404,000        $   166,000
                                                    =======================================
                Notes to long-term debt table:
</TABLE>

(1)  Revolving credit facility closed as of December 31, 2000.
(2)  8.25% fixed-rate, due March 2005
(3)  8.70% fixed-rate, due March 2010
(4)  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, 2000.
     See below for a complete description of these new facilities.

During the first quarter of 2001,  the Company issued $450 Million in additional
Senior Notes and filed (in conjunction  with the Limited Partner) a $500 million
universal  registration  statement  with the  SEC.  For a  description  of these
subsequent events, see Note 14.

At December 31, 2000, the Company had a total of $50 million of standby  letters
of credit available under its $250 Million Multi-Year Credit Facility (described
below) of which none were outstanding.

$200 Million Bank Credit Facility.  On July 27, 1998, the Company entered into a
$200 million bank credit  facility that included a $50 million  working  capital
facility and a $150 million  revolving credit  facility.  On March 15, 2000, the
Company used $169 million of the proceeds  from the issuance of the $350 Million
Senior Notes to retire this credit  facility in  accordance  with its  agreement
with the banks.

During the period in which this bank credit  facility  was  active,  the Company
elected the basis of the interest rate at the time of each  borrowing.  Interest
rates ranged from 7.07% to 7.31% during 2000, with the weighted-average interest
rate charged during 2000 being 7.28%.

$350 Million Bank Credit Facility.  On July 28, 1999, the Company entered into a
$350 Million Bank Credit  Facility that included a $50 million  working  capital
facility, a $300 million revolving credit facility and a sublimit of $40 million
for letters of credit.  On November 17, 2000,  this  facility was retired  using
funds  available  under the Company's new $150 Million  364-Day Credit  Facility
(described below) in accordance with its agreement with the banks.

During the period in which this bank credit  facility  was  active,  the Company
elected the basis of the interest rate at the time of each  borrowing.  Interest
rates ranged from 7.07% to 7.31% during 2000, with the weighted-average interest
rate charged during 2000 being 7.28%.

$350 Million  Senior Notes.  On March 13, 2000,  the Company  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
Company received  proceeds,  net of underwriting  discounts and commissions,  of
approximately  $347.7  million.  The  proceeds  were used to pay the entire $169
million  outstanding  principal balance on the $200 Million Bank Credit Facility
and $179 million of the then $226 million  outstanding  principal balance on the
$350 Million Bank Credit Facility.



                                       F-17
<PAGE>

The $350 Million  Senior Notes are subject to a make-whole  redemption  right by
the  Company.  The notes are an  unsecured  obligation  of the  Company and rank
equally with its existing and future unsecured and  unsubordinated  indebtedness
and senior to any future subordinated indebtedness.  The notes are guaranteed by
the Limited Partner through an unsecured and  unsubordinated  guarantee and were
issued  under an  indenture  containing  certain  restrictive  covenants.  These
covenants  restrict  the ability of the Company  and the Limited  Partner,  with
certain  exceptions,  to incur  debt  secured  by liens  and  engage in sale and
leaseback transactions.  The Company and Limited Partner were in compliance with
the restrictive covenants at December 31, 2000.

The issuance of the $350 Million  Senior Notes was a takedown under the December
1999 Registration Statement;  therefore,  the amount of securities available was
reduced to $450 million.  The remaining amount available under the December 1999
Registration  Statement  was used to  issue  the $450  Million  Senior  Notes in
January 2001 (see Note 14 "Subsequent  Events" below for a brief  description of
the $450 Million Senior Notes).

After  including  the  effect  of  interest  rate  swaps  related  to this  debt
instrument,  interest  rates for the $350 Million Senior Notes ranged from 7.88%
to 8.05% during 2000,  and the  weighted-average  interest  rate at December 31,
2000 was 8.00%.

$54 Million  MBFC Loan.  On March 27, 2000,  the Company  executed a $54 million
loan  agreement  with the MBFC which was funded with  proceeds  from the sale of
Taxable  Industrial Revenue Bonds ("Bonds") by the MBFC. The Bonds issued by the
MBFC  are  10-year  bonds  with a  maturity  date of  March  1,  2010 and bear a
fixed-rate interest coupon of 8.70%. The Company received proceeds from the sale
of the Bonds, net of underwriting  discounts and  commissions,  of approximately
$53.6  million.  The proceeds were used to pay the then $47 million  outstanding
principal  balance on the $350  Million  Bank  Credit  Facility  and for working
capital and other general partnership  purposes. In general, the proceeds of the
Bonds were used to reimburse  the Company for costs  incurred in  acquiring  and
constructing the Pascagoula, Mississippi natural gas processing plant.

The Bonds were issued at par and are subject to a make-whole redemption right by
the  Company.  The  Bonds are  guaranteed  by the  Limited  Partner  through  an
unsecured and  unsubordinated  guarantee.  The loan agreement  contains  certain
covenants  including   maintaining   appropriate  levels  of  insurance  on  the
Pascagoula natural gas processing  facility and restrictions  regarding mergers.
The Company was in  compliance  with the  restrictive  covenants at December 31,
2000.

After  including  the  effect  of  interest  rate  swaps  related  to this  debt
instrument, interest rates for the Bonds ranged from 7.26% to 7.66% during 2000,
and the weighted-average interest rate at December 31, 2000 was 7.43%.

$250 Million  Multi-Year  Credit  Facility.  On November  17, 2000,  the Company
entered into a $250 million five-year  revolving credit facility that includes a
sublimit of $50 million for letters of credit.  The November  17, 2005  maturity
date may be extended  for one year at the  Company's  option with the consent of
the lenders,  subject to the extension provisions in the agreement.  The Company
can increase the amount borrowed under this facility, without the consent of the
lenders,  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 $150 Million 364-Day 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  Limited  Partner  through an  unsecured  and  unsubordinated
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, 2000.

The Company's  obligations under this bank credit facility are unsecured general
obligations and are non-recourse to the General  Partner.  Borrowings under this
bank credit  facility will  generally bear interest at either (a) the greater of
the Prime Rate or the Federal Funds Effective Rate plus one-half  percent or (b)
a Eurodollar rate plus an applicable  margin (as defined within the facility) or
(c) a competitively bid rate. The Company elects the basis for the interest rate
at the time of each borrowing.



                                       F-18
<PAGE>

This credit  agreement  contains  various  affirmative  and  negative  covenants
applicable to the Company to, among other things,  (i) incur certain  additional
indebtedness,  (ii) grant  certain  liens,  (iii) enter into  certain  merger or
consolidation  transactions and (iv) make certain investments.  In addition, the
Company may not directly or indirectly  make any  distribution in respect of its
partnership  interests,  except those  payments in  connection  with the Limited
Partner's  1,000,000  Unit  Buy-Back  Program  (not to exceed $30 million in the
aggregate) and distributions from Available Cash from Operating Surplus, both as
defined within the agreement. The bank credit facility requires that the Company
satisfy  certain  financial  covenants  at the end of each fiscal  quarter:  (i)
maintain  Consolidated  Net Worth of $750 million (as defined in the bank credit
facility) and (ii)  maintain a ratio of  Consolidated  Indebtedness  (as defined
within the bank credit  facility) to Consolidated  EBITDA (as defined within the
bank credit  facility) for the previous  four quarter  period of at least 4.0 to
1.0. The Company was in compliance with these restrictive  covenants at December
31, 2000.

$150 Million  364-Day  Credit  Facility.  Also on November 17, 2000, the Company
entered into a 364-day $150 million  revolving bank credit facility which may be
converted  into a one-year term loan at the end of the initial  364-day  period.
Should this facility be converted  into a one-year term loan,  the maturity date
would be November 16, 2002. Likewise,  this maturity date may be extended for an
additional one-year period at the option of the Company (with the consent of the
lenders),  subject to the extension provisions in the agreement;  therefore, the
ultimate  maturity date of this credit  facility could be November 16, 2003. The
Company  can  increase  the amount  borrowed  under this  facility,  without the
consent of the lenders,  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 $250 Million  Multi-Year  Credit Facility 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  Limited  Partner  through  an  unsecured  and
unsubordinated 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, 2000.  The Company used operating cash
flows to repay the  amount  borrowed  to retire  the $350  Million  Bank  Credit
Facility  in  November  2000.  For  the  period  in  which  the  Company  had an
outstanding principal balance under this credit facility,  the interest rate was
7.19%.

Limitations on certain actions by the Company and financial  condition covenants
of this bank credit  facility are  substantially  consistent with those existing
for the $250 Million Bank Credit Facility as described above. The Company was in
compliance with the restrictive covenants at December 31, 2000.

Extraordinary Item - Early Extinguishment of Debt

On July 31, 1998,  the Company  used $243.3  million in  contributions  from the
Limited  Partner and $13.3  million of  borrowings  from the $200  Million  Bank
Credit  Facility to retire $256.6 million of debt that was assumed from EPCO. In
connection  with the  repayment  of the debt,  the Company was required to pay a
"make-whole  payment" of $26.3  million to the lenders.  The $26.3 million (plus
$0.9  million  of  unamortized  debt  costs)  is  included  in the  consolidated
statement of operations for the year ended  December 31, 1998 as  "Extraordinary
item--early extinguishment of debt."


7.  CAPITAL STRUCTURE

The Limited Partner owns 98.9899% of the Company with the General Partner owning
the remaining 1.0101%. For purposes of maintaining partner capital accounts, the
partnership  agreement generally specifies that items of income or loss shall be
allocated  among the  partners in  accordance  with their  respective  ownership
percentages.  Net losses are first  allocated to the partners in accordance with
their respective percentages to the extent that the allocations do not cause the
Limited Partner to have a deficit balance in its capital  account.  Any net loss
not allocated to the Limited Partner is allocated to the General Partner. Normal
allocations  of net income  according  to  percentage  interests  are done only,
however,  after giving effect to any priority income  allocations to the General
Partner in an amount equal to any aggregate  net losses  incurred by the General
Partner for all previous years.  For the years ended December 31, 2000, 1999 and


                                       F-19
<PAGE>

1998,  the  allocation  of  earnings  has been  based  solely on the  respective
ownership  interests of the partners with no priority income  allocations  being
necessary.

The  partnership  agreement  requires  the  Company  to  distribute  100% of the
"Available  Cash" (as defined in the  partnership  agreements)  to the  partners
within 45 days  following  the end of each calendar  quarter in accordance  with
their respective ownership  interests.  Available Cash consists generally of all
cash receipts of the Company, less all of its cash disbursements, net of changes
in reserves. The Company's  distributions to its partners during the three years
ended December 31, 2000, 1999 and 1998 were $141.5  million,  $112.9 million and
$21.9 million, respectively.

Limited  Partner Units Acquired by Trust.  During the first quarter of 1999, the
Company  established  a  revocable  grantor  trust (the  "Trust") to fund future
liabilities of a long-term  incentive  plan. At December 31, 1999, the Trust had
purchased a total of 267,200  Common  Units of the Limited  Partner  (the "Trust
Units") which are accounted for in a manner  similar to treasury stock under the
cost method of  accounting.  The Trust Units receive  dividends from the Limited
Partner.


8.   RELATED PARTY TRANSACTIONS

The Company has no  employees.  All  management,  administrative  and  operating
functions  are  performed by employees  of EPCO  pursuant to the EPCO  Agreement
entered into by EPCO, the General Partner and the Company in July 1998.

Under the terms of the EPCO  agreement,  EPCO agreed to (i) manage the  business
and affairs of the Company;  (ii) employ the operating personnel involved in the
Company's  business for which EPCO is  reimbursed  by the Company at cost (based
upon EPCO's actual salary costs and related  fringe  benefits);  (iii) allow the
Company 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;  (iv)  grant an  irrevocable,  non-exclusive  worldwide
license to all of the  trademarks  and trade  names used in its  business to the
Company;  (v) indemnify the Company  against any losses  resulting  from certain
lawsuits;  and (vi)  sublease 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 to the Company for $1 per year
and  assigned  its purchase  options  under such leases to the Company.  EPCO is
liable for the lease payments associated with these assets.  Operating costs and
expenses (as shown on the audited Statements of Consolidated Operations) include
charges for EPCO's employees who operate the Company's various facilities.

Pursuant to the EPCO Agreement,  the charges for EPCO's employees who manage the
business  and  affairs  of  the  Company  are  reimbursed   only  under  certain
circumstances.  SG&A  charges to EPCO  resulting  from the hiring of  additional
management  personnel and other costs associated with the expansion and business
development   activities  of  the  Company  (through  the  construction  of  new
facilities or the completion of acquisitions) are reimbursed by the Company.

In lieu of  reimbursement  for all other SG&A costs  incurred  by EPCO,  EPCO is
entitled  to receive an annual  Administrative  Services  Fee (the "EPCO  Fees",
initially  set at $12.0  million).  The General  Partner,  with the approval and
consent of the Audit and Conflicts Committee, may agree to increases in the EPCO
Fees of up to 10% each contract year (defined as August 1 to July 31) during the
10-year term of the EPCO Agreement.  Since the initial contract year ending July
31, 1999,  the Audit and  Conflicts  Committee has approved two increases in the
EPCO Fees. The annual fee was increased to $13.2 million for the second contract
year and subsequently raised to $14.5 million for the third contract year.

EPCO also operates most of the plants owned by the unconsolidated affiliates and
charges them for actual salary costs and related fringe  benefits.  In addition,
EPCO charged the  unconsolidated  affiliates for management  services  provided;
such charges  aggregated  $0.9 million for 2000,  $0.8 million for 1999 and $1.7
million for 1998.  Since EPCO pays the rental  charges for the Retained  Leases,
such  payments  are  considered a  contribution  by EPCO for the benefit of each
partnership  interest  and  are  included  as such in  Partners'  Equity,  and a
corresponding  charge for the rental  expense is  included  in the  consolidated
statements  of  operations.  Rental  expense,  included in  operating  costs and


                                       F-20
<PAGE>

expenses,  for the Retained  Leases was $10.6 million for both 2000 and 1999 and
$11.3  million  for 1998 (of  which  $4.0  million  occurred  after  the  public
offering).

The Company  also has  transactions  in the normal  course of business  with the
unconsolidated  affiliates and other  subsidiaries  and divisions of EPCO.  Such
transactions  include  the buying and  selling of NGL  products,  loading of NGL
products, transportation of NGL products by truck and plant support services.

As a result of the TNGL acquisition, Shell acquired an ownership interest in the
Limited  Partner and the General  Partner.  At December  31,  2000,  Shell owned
approximately 20.5% of the Limited Partner and 30% of the General Partner. Shell
is a significant  customer of the gas processing assets.  Under the terms of the
Shell Processing  Agreement,  the Company has the right to process substantially
all of  Shell's  current  and future  natural  gas  production  from the Gulf of
Mexico.  This includes  natural gas production from the  developments  currently
referred to as deepwater.  Generally,  the Shell Processing Agreement grants the
Company 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 raw make extracted by the Company's
gas processing  facilities from Shell's natural gas production from such leases;
with the  obligation  to deliver to Shell the natural  gas stream  after the raw
make is extracted. Generally, the Company's revenues from Shell are derived from
the sale of NGL and petrochemical  products with its operating costs and expense
from Shell  primarily  due to the  purchase of natural  gas.  The Company has an
extensive and ongoing relationship with Shell as a customer, vendor and owner of
Limited Partner interests.

The following  table shows the related  party amounts by major income  statement
category for the last three years:

<TABLE>
<CAPTION>
                                                                            For the Years Ended
                                                                                December 31,
                                                             ---------------------------------------------------
                                                                   2000             1999             1998
                                                             ---------------------------------------------------
<S>                                                                 <C>              <C>              <C>
Revenues from consolidated operations
     Unconsolidated affiliates                                      $  61,988        $  40,352        $  36,474
     Shell                                                            292,741           56,301
     EPCO and subsidiaries                                              4,750            9,148           19,531
Operating costs and expenses
     Unconsolidated affiliates                                         58,202           20,696            9,270
     Shell                                                            736,655          188,570
     EPCO and subsidiaries                                              9,492           35,046            9,997
Selling, general and administrative expenses
     Base fees payable under EPCO Agreement                            13,750           12,500            5,129
</TABLE>


9.       COMMITMENTS AND CONTINGENCIES

Redelivery Commitments

From time to time,  the Company  stores NGL  products  for third  parties  under
various processing and similar agreements.  Under the terms of these agreements,
the Company is  generally  required to  redeliver  to the owner its NGL products
upon demand.  The Company is insured for any physical  loss of such NGL products
due to catastrophic  events. At December 31, 2000, NGL products  aggregating 235
million gallons were due to be redelivered to the owners.









                                       F-21
<PAGE>

Lease Commitments

The  Company  leases  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,  2000 are as
follows:

2001                                   $    7,228
2002                                        5,048
2003                                        4,797
2004                                        4,260
2005                                          214
Thereafter                                  1,225
                                      ------------
   Total minimum obligations           $   22,772
                                      ============

Lease expense charged to operations  (including  Retained  Leases) for the years
ended December 31, 2000, 1999 and 1998 was  approximately  $18.3 million , $20.2
million and $18.5 million, respectively.

Gas Purchase Commitments

The Company has annual renewable gas purchase contracts with four suppliers.  As
of  December  31,  2000,  the Company is  required  to make daily  purchases  as
follows:

     -    5,000 million British Thermal Units ("MMBtu") per day through February
          28, 2001,
     -    13,000 MMBtu per day through March 31, 2001,
     -    5,000 MMBtu per day through July 31, 2001,
     -    5,000 MMBtu per day through September 30, 2001, and
     -    5,000 MMBtu per day through October 31, 2001.

The cost of these natural gas purchase  commitments  approximate market value at
the time of delivery.

Capital Expenditure Commitments

As of  December  31,  2000,  the Company  had  capital  expenditure  commitments
totaling  approximately  $10.9  million,  of which $0.8  million  relates to the
construction of projects of unconsolidated affiliates.

Litigation

EPCO has indemnified  the Company against any litigation  pending as of the date
of its  formation.  The Company is sometimes  named as a defendant in litigation
relating to its normal business operations.  Although the Company insures itself
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 the Company against  liabilities  arising
from future legal  proceedings  as a result of its ordinary  business  activity.
Except as note below, management is aware of no significant litigation,  pending
or threatened,  that would have a significantly  adverse effect on the Company's
financial position or results of operations.

The  operations  of the Company 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 the pipelines,
processing and storage facilities.  For example, the 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.  One of the other  consequences of this  non-attainment
status 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 imposing more strict requirements on existing facilities were issued
in  December,  2000.  These  regulations  mandate  90%  reductions  in oxides of


                                       F-22
<PAGE>

nitrogen  emissions from point sources such as the gas turbines at the Company's
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 litigation  filed in the District  Court of
Travis County, Texas, on January 19, 2001, by the Company as part of a coalition
of major  Houston-Galveston  area  industries.  In addition to the Company,  the
plaintiffs  in this case are the BCCA  Appeal  Group,  Equistar  Chemicals,  LP,
Lyondell  Chemical  Company,  Lyondell-CITGO  Refining L.P. and Reliant  Energy,
Incorporated;  named as defendants are the Texas Natural  Resource  Conservation
Commission  and its chairman,  commissioners  and executive  director.  The suit
seeks a  ruling  that  these  regulations  are  invalid  and void and asks for a
temporary  injunction to stay their effectiveness  pending final judgment in the
case.  If these  regulations  stand as issued,  they would  require  substantial
redesign and modification of the Mont Belvieu facilities to achieve the mandated
reductions;  however,  the precise impact of these requirements on the Company's
operations cannot be determined until this litigation is resolved.


10.      FAIR VALUE OF FINANCIAL INSTRUMENTS

The following  disclosure of estimated fair value was determined by the Company,
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 the Company
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.

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 fair value of the Company's  fixed-rate long term
debt is estimated  based on the quoted  market  prices for debt of similar terms
and maturities. No variable rate long-term debt was outstanding at year end.

Interest  Rate  Swaps.  The  Company's   interest  rate  exposure  results  from
variable-rate   borrowings  from  commercial  banks  and  fixed-rate  borrowings
pursuant to the $350 Million  Senior  Notes and the $54 Million  MBFC Loan.  The
company  manages its exposure to changes in interest  rates in its  consolidated
debt  portfolio by utilizing  interest  rate swaps.  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.

In March 2000,  after the  issuance  of the $350  Million  Senior  Notes and the
execution of the $54 Million MBFC Loan, 100% of the Company's  consolidated debt
were fixed-rate  obligations.  To maintain a balance between  variable-rate  and
fixed-rate exposure, the Company entered into interest rate swap agreements with
a notional amount of $154 million by which the Company  receives  payments based
on a  fixed-rate  and pays an amount based on a  floating-rate.  At December 31,
2000, the Company's  consolidated  debt portfolio  interest rate exposure was 62
percent  fixed and 38  percent  floating,  after  considering  the effect of the
interest rate swap agreements.  The notional amount does not represent  exposure
to credit loss. The Company monitors its positions and the credit ratings of its
counterparties.  Management believes the risk of incurring a credit related loss
is remote, and that if incurred, such losses would be immaterial.

Cash flows related to interest rate swap agreements are classified as "Operating
activities  cash flows" in the Statements of  Consolidated  Cash Flows.  The net
cash differentials paid or received on interest rate swap agreements are accrued
and  recognized as adjustments  to interest  expense.  The effect of these swaps
(none of which are leveraged) was to decrease the Company's  interest expense by
$1.2 million  during 2000.  Following is selected  information  on the Company's
portfolio of interest rate swaps at December 31, 2000:








                                       F-23
<PAGE>

Interest Rate Swap Portfolio at December 31, 2000 (1) :
(Dollars in millions)
                                                 Early             Fixed /
  Notional                                    Termination         Floating
   Amount            Period Covered             Date (2)          Rate (3)
--------------------------------------------------------------------------------

      $ 50.0 March 2000 - March 2005        March 2001         8.25% / 7.3100%
      $ 50.0 March 2000 - March 2005        March 2001 (4)     8.25% / 7.3150%
      $ 54.0 March 2000 - March 2010        March 2003         8.70% / 7.6575%

Notes to Interest Rate Swap table:

(1)  All swaps  outstanding  at  December  31,  2000 were  entered  into for the
     purpose of managing a portion of the financing  costs  associated  with its
     fixed-rate debt.
(2)  In each case,  the  counterparty  has the option to terminate  the interest
     rate swap on the Early Termination Date.
(3)  In each case, the Company is the floating-rate payor. The floating rate was
     the rate in effect as of December 31, 2000.
(4)  Swap was terminated by the bank effective March 15, 2001.

The $2.0 million  fair value of interest  rate swap  agreements  at December 31,
2000 is based on market rates and the early termination  option being exercised.
The fair value  represents the estimated amount the Company would receive or pay
based on current interest rates.

Commodity-related   transactions.  The  Company  enters  into  swaps  and  other
contracts to hedge the price risks associated with inventories,  commitments and
certain  anticipated  transactions.  The  swaps  and  other  contracts  are with
established  energy  companies  and major  financial  institutions.  The Company
believes its credit risk is minimal on these transactions, as the counterparties
are required to meet stringent credit standards.  There is continuous day-to-day
involvement  by senior  management  in the hedging  decisions,  operating  under
resolutions adopted by the Board of Directors of the General Partner.

At December 31, 1999, the Company had open positions covering 24.0 billion cubic
feet of natural gas extending into December 2000 related to the swaps  described
above.  The fair value of these  financial  instruments at December 31, 1999 was
estimated at $0.5  million  payable by the  Company.  At December 31, 2000,  the
Company had open commodity positions covering 28.8 billion cubic feet of natural
gas and 1.2 million barrels of NGL futures,  primarily  propane,  extending into
December  2001.  The fair value of these  financial  instruments at December 31,
2000 was  estimated  at $38.6  million  payable by the  Company.  The fair value
estimates  at December  31, 2000 and 1999 are based on quoted  market  prices of
comparable  contracts  and  approximate  the gain or loss that  would  have been
realized if the  contracts  had been settled at the balance  sheet date.  To the
extent  that the  hedged  positions  are  effective,  gains or  losses  on these
derivative commodity instruments would be offset by a corresponding gain or loss
on the hedged commodity positions, which are not included in the table below.




















                                       F-24
<PAGE>

The  following  table  summarizes  the  estimated  fair values of the  Company's
financial instruments at December 31, 2000 and 1999:

<TABLE>
<CAPTION>
                                                         2000                          1999
                                              ----------------------------  ----------------------------
                                                Carrying        Fair          Carrying        Fair
            Financial Instruments                Amount         Value          Amount         Value
--------------------------------------------------------------------------  ----------------------------
<S>                                                <C>           <C>             <C>           <C>
Financial assets:
   Cash and cash equivalents                       $ 58,466      $ 58,466        $  5,159      $  5,159
   Accounts receivable                              414,823       414,823         316,254       316,254
   Accounts payable and accrued expenses            550,712       550,712         383,582       383,582

Financial liabilities:
   Variable-rate debt                                     -             -         295,000       295,000
   Fixed-rate debt                                  404,000       423,836           n/a           n/a
   Commodity futures                                    725           705           n/a           n/a

Off-balance sheet instruments:
   Interest rate swaps receivable                     2,030         2,030           n/a           n/a
   Commodity futures payable                         40,020        39,266             539           539
</TABLE>

Recent Accounting Developments

Effective January 1, 2001, the Company adopted Statement of Financial Accounting
Standards  No. 133 ("SFAS  133"),  Accounting  for  Derivative  Instruments  and
Hedging Activities, as amended and interpreted.  SFAS 133 establishes accounting
and reporting standards for derivative instruments, including certain derivative
instruments  embedded  in  other  contracts  and  for  hedging  activities.  All
derivatives,  whether  designated  in  hedging  relationships  or  not,  will be
required to be recorded on the balance sheet at fair value. If the derivative is
designated  as a fair value hedge,  the changes in fair value of the  derivative
and the  hedged  item will be  recognized  in  earnings.  If the  derivative  is
designated  as a cash flow  hedge,  changes in the fair value of the  derivative
will be recorded as a component of Partners' Equity entitled Other Comprehensive
Income (to the  extent the hedge is  effective)  and will be  recognized  in the
income statement when the hedged item affects earnings.  The ineffective portion
of the hedge is  required  to be  recorded  in  earnings.  SFAS 133  defines new
requirements for designation and documentation of hedging  relationships as well
as  ongoing  effectiveness  assessments  in order  to use  hedge  accounting.  A
derivative  that does not  qualify  as a hedge  will be  recorded  at fair value
through earnings.

The Company  expects  that at January 1, 2001,  it will record a $ 42.2  million
loss in Other  Comprehensive  Income as a cumulative  transition  adjustment for
derivatives  (commodity  contracts) designated in cash flow-type hedges prior to
adopting  SFAS 133. In  addition,  the Company  expects to record a $2.1 million
derivative asset and a corresponding  increase to its long term debt relating to
derivatives (interest rate swaps) designated in fair-value-type  hedges prior to
adopting  SFAS 133. The fair value  hedges will have no impact to earnings  upon
transition.

The Company will reclassify from Other  Comprehensive  Income $21.7 million as a
charge to  earnings  during  the first  quarter  of 2001 and $20.5  million as a
charge to earnings  during the remainder of 2001. The actual gain or loss amount
to be recognized in earnings  related to these commodity  contracts over time is
dependent upon the final settlement price associated with the commodity prices.









                                       F-25
<PAGE>

11.      SUPPLEMENTAL CASH FLOWS DISCLOSURE

The net effect of changes in operating assets and liabilities is as follows:

<TABLE>
<CAPTION>
                                                                  Year Ended December 31,
                                                         2000               1999              1998
                                                   -------------------------------------------------------
<S>                                                      <C>               <C>               <C>
(Increase) decrease in:
     Accounts receivable                                $   (95,647)       $  (152,335)      $     3,699
      Inventories                                           (21,453)             7,471             1,361
      Prepaid and other current assets                        2,315             (7,524)             (342)
      Intangible assets                                      (5,228)
      Other assets                                           (1,527)             1,164             1,781
Increase (decrease) in:
      Accounts payable                                       18,725             (6,277)          (40,005)
      Accrued gas payable                                   143,457            206,177           (19,463)
      Accrued expenses                                        4,430            (28,149)             (120)
      Other current liabilities                              15,287              6,745           (10,082)
      Other liabilities                                       8,123                296
                                                   -------------------------------------------------------
Net effect of changes in operating accounts              $   68,482        $    27,568       $   (63,171)
                                                   =======================================================

Cash payments for interest, net of $3,277,
      $153 and $180 capitalized in 2000, 1999
      and 1998, respectively                             $   17,774        $    15,780       $     6,971
                                                   =======================================================
</TABLE>


Capital  expenditures for 2000 were $243.9 million compared to $21.2 million for
the same period in 1999. Capital expenditures in 2000 included $99.5 million for
the  purchase of the Lou-Tex  Propylene  Pipeline  and related  assets and $83.7
million in construction costs for the Lou-Tex NGL Pipeline.

During 2000, the Company increased the gas processing  contract by $25.2 million
for non-cash purchase accounting  adjustments  relating to the TNGL acquisition.
The offset to such adjustment was various working capital accounts.

On August 1, 1999, the Company paid $166 million in cash and the Limited Partner
issued 14.5 million  non-distribution  bearing,  convertible special partnership
Units to Shell in connection  with the TNGL  acquisition.  The value of the 14.5
million  special  partnership  Units was $210.4 million at time of issuance.  On
August  1,  2000,   the  Limited   Partner  issued  an  additional  3.0  million
non-distribution  bearing,  convertible  special partnership Units to Shell. The
value of these  new  special  partnership  Units was  $55.2  million  at time of
issuance.  In both cases, the value of the special partnership Units at the time
of issuance was recorded as a non-cash  contribution  by the Limited  Partner to
the Company.  The General  Partner made  non-cash  contributions  to the Company
relating to the TNGL  acquisition  of $2.1  million in 1999 and $0.6  million in
2000.

On July 1, 1999,  the Company paid  approximately  $42 million in cash to Kinder
Morgan and EPCO and assumed  approximately $4 million of debt in connection with
the acquisition of an additional interest in MBA.

During 1998, the Company  contributed  $1.9 million (at net book value) of plant
equipment to an unconsolidated affiliate as part of its investment therein.


12.      CONCENTRATION OF CREDIT RISK

A  substantial  portion of the  Company's  revenues are derived from natural gas
processing  and  the   fractionation,   isomerization,   propylene   production,
marketing,  storage and  transportation  of NGLs to various companies in the NGL
industry, located in the United States. Although this concentration could affect
the Company's  overall  exposure to credit risk since these  customers  might be
affected  by similar  economic  or other  conditions,  management  believes  the


                                       F-26
<PAGE>

Company is exposed to minimal credit risk, since the majority of its business is
conducted with major  companies  within the industry and much of the business is
conducted with companies with whom the Company has joint operations. The Company
generally does not require collateral for its accounts receivable.

The Company is subject to a number of risks inherent in the industry in which it
operates,  primarily  fluctuating  gas and liquids  prices and gas  supply.  The
Company's   financial   condition   and  results  of   operations   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 and a variety of additional
factors  that are beyond the control of the Company.  In  addition,  the Company
must continually connect new wells through  third-party  gathering systems which
serve the gas  plants in order to  maintain  or  increase  throughput  levels to
offset  natural  declines in dedicated  volumes.  The number of wells drilled by
third parties will depend on, 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 the Company's control.


13.      SEGMENT INFORMATION

Operating  segments are components of a business about which separate  financial
information  is  available  that is evaluated  regularly 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.

The Company has five reportable  operating  segments:  Fractionation,  Pipeline,
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
includes NGL fractionation,  butane isomerization (converting normal butane into
high purity  isobutane)  and polymer  grade  propylene  fractionation  services.
Pipeline  consists of pipeline,  storage and  import/export  terminal  services.
Processing  includes  the natural gas  processing  business  and its related NGL
merchant  activities.   Octane  Enhancement   represents  the  Company's  33.33%
ownership  interest in 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.

The  Company  evaluates  segment  performance  on the  basis of 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.  The Company's  equity earnings from
unconsolidated affiliates are included in segment gross operating margin.

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-27
<PAGE>

Information  by  operating  segment,   together  with   reconciliations  to  the
consolidated totals, is presented in the following table:

<TABLE>
<CAPTION>
                                                       Operating Segments                             Adjustments
                             ------------------------------------------------------------------------
                                                                            Octane                        and       Consolidated
                             Fractionation   Pipelines     Processing    Enhancement       Other     Eliminations      Totals
                             -----------------------------------------------------------------------------------------------------
<S>   <C>                       <C>            <C>          <C>             <C>           <C>         <C>             <C>
Revenues from
   external customers
      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
      1998                         213,966         18,306       506,630                                                   738,902

Intersegment revenues
      2000                      $  177,963     $   55,690    $  630,155                   $      375  $  (864,183)
      1999                         118,103         43,688       216,720                          444     (378,955)
      1998                         162,379         37,574            90                          383     (200,426)

Equity income in
   unconsolidated affiliates
      2000                      $    6,391     $    7,321                   $   10,407                                $    24,119
      1999                           1,566          3,728                        8,183                                     13,477
      1998                           5,122            748                        9,801                                     15,671

Total revenues
      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
      1998                         381,467         56,628       506,720          9,801           383     (200,426)        754,573

Gross operating margin
   by segment
      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
      1998                          66,627         27,334          (652)         9,801        (3,483)                      99,627

Segment property, net
      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
      2000                      $  105,194     $  102,083    $   33,000     $   58,677                                $   298,954
      1999                          99,110         85,492        33,000         63,004                                    280,606
</TABLE>


One  Fractionation  third-party  customer  in 1998  provided  more  than  10% of
consolidated  revenues. No single third-party customer provided more than 10% of
consolidated revenues in 2000 or 1999.

All  consolidated  revenues were earned in the United States.  The operations of
the Company are centered along the Texas,  Louisiana and Mississippi  Gulf Coast
areas.

Certain reclassifications have been made to the 1999 and 1998 amounts to conform
to the 2000 presentation.  Gross operating margin for both the Fractionation and
Pipeline  segments  in  1999  was  increased  by  $4.1  million  each  due  to a
reclassification  of margins  for the Tebone  and Venice NGL  fractionation  and
pipeline assets from the Processing  segment.  Revenues from external  customers
for both 1998 and 1999 was  adjusted  to  reflect  (i) the  reclassification  of


                                       F-28
<PAGE>

equity income in unconsolidated  affiliates to a separate line item in the above
table and (ii) the reclassification of certain revenue items that had previously
been classified as adjustments to consolidated revenues to the segments to which
they relate.  The effect of the  reclassification  of amounts in item (ii) above
was to reduce  revenues  from  external  customers  for  Fractionation  by $30.7
million in 1999 and $54.7  million in 1998 and Pipelines by $5.1 million in 1999
and $0.3 million in 1998.

The Venice  NGL  fractionation  and  pipeline  assets are part of the  Company's
investment  in VESCO  which is  classified  under the  Processing  segment.  The
Company views both Tebone and Venice  pipeline assets as an integral part of its
Louisiana Pipeline System.

A reconciliation of segment gross operating margin to consolidated income before
minority interest follows:

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

<S>                                                         <C>               <C>               <C>
Gross Operating Margin by segment:
     Fractionation                                          $  129,376        $  110,424        $   66,627
     Pipeline                                                   56,099            31,195            27,334
     Processing                                                122,240            28,485              (652)
     Octane enhancement                                         10,407             8,183             9,801
     Other                                                       2,493               908            (3,483)
                                                    -------------------------------------------------------
Gross Operating Margin total                                   320,615           179,195            99,627
     Depreciation and amortization                              35,622            23,664            18,579
     Retained lease expense, net                                10,644            10,557            12,635
     Loss (gain) on sale of assets                               2,270               123              (276)
     Selling, general and administrative expenses               28,345            12,500            18,216
                                                    -------------------------------------------------------
Consolidated operating income                               $  243,734        $  132,351        $   50,473
                                                    =======================================================
</TABLE>


14.      SUBSEQUENT EVENTS (UNAUDITED)

Manta Ray, Nautilus and Nemo Pipeline Systems

On January 29, 2001, the Company 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 $88.1  million in
cash.  These  systems  total  approximately  362 miles of pipeline.  The Company
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
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, the Company 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 $50.2 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.





                                       F-29
<PAGE>

$450 Million Senior Notes

On January 24, 2001, the Company  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  "$450  Million  Senior
Notes").  The Company  received  proceeds,  net of  underwriting  discounts  and
commissions,  of approximately  $446.8 million.  The proceeds from this offering
were or will be used to acquire the Acadian and EPE natural gas pipeline systems
for $339.2  million and to finance the cost to construct  certain NGL  pipelines
and related  projects  and for working  capital  and other  general  partnership
purposes.

February 2001 Registration Statement

On February 23, 2001,  the Company and the Limited  Partner filed a $500 million
universal  shelf  registration  (the  "February  2001  Registration  Statement")
covering the issuance of an unspecified amount of equity or debt securities or a
combination  thereof.  The Company expects 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 of the Limited Partner 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
the Company's funding  requirements and the availability of alternative  funding
sources. The Company routinely reviews acquisition opportunities.


15.      SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

<TABLE>
<CAPTION>
                                                            First             Second             Third             Fourth
                                                           Quarter            Quarter           Quarter            Quarter
                                                      --------------------------------------------------------------------------
<S>                                                           <C>               <C>                <C>               <C>
For the Year Ended December 31, 1999:
    Revenues                                                  $  148,877        $  177,479         $  445,028        $  575,072
    Operating income                                              12,068            21,069             40,070            59,144
    Income before minority interest                               10,561            19,350             36,716            55,213
    Minority interest                                                (27)              (24)               (21)              (38)
    Net income                                                    10,534            19,326             36,695            55,175

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                               70,254            46,127             50,884            55,916
    Minority interest                                                (37)              (33)               (18)              (25)
    Net income                                                    70,217            46,094             50,866            55,891
</TABLE>


As a result of the TNGL and MBA acquisitions,  the Company's  earnings increased
significantly  in the third quarter of 1999 over the second quarter of 1999. The
TNGL  acquisition  was  effective  August  1,  1999 and the MBA  acquisition  as
effective July 1, 1999.


                                       F-30
<PAGE>


Enterprise Products Operating L.P.                                   SCHEDULE II
Valuation and Qualifying Accounts
(amounts in millions of dollars)

<TABLE>
<CAPTION>
                                                                         Year Ended December 31,
                                                                       ----------------------------
                                                                         1998     1999     2000
                                                                       ----------------------------
<S>                                                                      <C>      <C>       <C>
Accounts Receivable - trade
     Allowance for doubtful accounts (a)
           Balance at beginning of period                                                   $ 15.9
           Reserve increases charged to earnings                                  $  3.0
           Reserve increases charged to other balance sheet accounts                12.9
           Amounts charged against reserve (deductions)                                       (5.0)
                                                                                -------------------
           Balance at end of period                                               $ 15.9    $ 10.9
                                                                                ===================

Other current liabilities
     Reserve for inventory losses (b)
           Balance at beginning of period                                $  0.8   $  0.8    $  2.9
           Reserve increases charged to earnings                           10.0      7.3       5.1
           Reserve  increases  charged to other balance sheet  accounts
           Amounts charged against reserve (deductions)                   (10.0)    (5.2)     (2.3)
                                                                       ----------------------------
           Balance at end of period                                      $  0.8   $  2.9    $  5.7
                                                                       ============================
</TABLE>


(a)  As a result of the TNGL  acquisition in 1999, the Company  acquired a $12.9
     million allowance for doubtful accounts.  Historically, the Company did not
     experience  any  significant  losses from bad debts and  therefore  did not
     require an allowance account.
(b)  Generally denotes net underground NGL storage well product losses.


























<PAGE>

                                   SIGNATURES


         Pursuant to the  requirements  of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned thereunto duly authorized, in the City of Houston,
State of Texas, on March 22, 2001.

                             ENTERPRISE PRODUCTS OPERATING L.P.
                             (A Delaware Limited Partnership)

                             By:      Enterprise Products GP, LLC,
                                      as General Partner

                             By:      /s/  Michael J. Knesek
                                      -----------------------------------------
                             Name:    Michael J. Knesek
                             Title:   Vice President,  Controller and Principal
                                      Accounting Officer of Enterprise Products
                                      GP, LLC

         Pursuant to the  requirements  of the Securities  Exchange Act of 1934,
this  report has been  signed  below by the  following  persons on behalf of the
registrant and in the capacities indicated below on March 22, 2001.

          Signature                                           Title
          ---------                                           -----

/s/  Dan L. Duncan                                   Chairman of the Board and
---------------------------------                    Director
Dan L. Duncan

/s/  O.S. Andras                                     President, Chief Executive
---------------------------------                    Officer and Director
O.S. Andras

/s/  Randa L. Duncan                                 Director
---------------------------------
Randa L. Duncan

/s/  Richard H. Bachmann                             Executive Vice President,
---------------------------------                    Chief Legal Officer,
Richard H. Bachmann                                  Secretary and Director

/s/  J. A. Berget                                    Director
---------------------------------
J. A. Berget

/s/  Dr. Ralph S. Cunningham                         Director
---------------------------------
Dr. Ralph S. Cunningham

/s/  J. R. Eagan                                     Director
---------------------------------
J. R. Eagan

/s/  Curtis R. Frasier                               Director
---------------------------------
Curtis R. Frasier

/s/  Lee W. Marshall, Sr.                            Director
---------------------------------
Lee W. Marshall, Sr.

/s/  Richard S. Snell                                Director
---------------------------------
Richard S. Snell
<PAGE>

                                                                    EXHIBIT 12.1




<TABLE>
<CAPTION>
                                     ENTERPRISE PRODUCTS OPERATING L.P.
                             COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
                                          (amounts in millions $)

                                                                For the Year Ended December 31,
                                                       2000       1999       1998        1997       1996
                                                    ---------------------------------------------------------
<S>                                                     <C>        <C>        <C>         <C>         <C>
Income (loss) before minority interest
        and equity investments                          $199.1     $108.4     $  (5.5)    $ 37.0      $ 45.7
Add:
        Fixed charges                                     42.6       23.3        21.5       37.6        36.7
        Amortization of capitalized interest               0.2        0.1         0.1        0.1         0.1
        Distributed income of equity investees            37.3        6.0         9.1        7.3         7.2
Less:
        Capitalized interest                              (3.3)      (0.2)       (0.2)      (0.2)       (1.6)
        Minority interest                                 (0.1)      (0.1)       (0.1)      (0.1)       (0.1)
                                                    ---------------------------------------------------------
Total Earnings                                          $275.8     $137.5     $  24.9     $ 81.7      $ 88.0
                                                    =========================================================

Fixed charges:
        Interest expense                                  33.3       16.4        15.1       25.7        26.3
        Capitalized interest                               3.3        0.2         0.2        2.0         1.6
        Interest portion of rental expense                 6.0        6.7         6.2        9.9         8.8
                                                    ---------------------------------------------------------
        Total                                           $ 42.6     $ 23.3     $  21.5     $ 37.6      $ 36.7
                                                    =========================================================

Ratio of Earnings to Fixed charges                       6.47x      5.90x       1.16x      2.17x       2.40x
                                                    =========================================================
</TABLE>

These  computations  include the Company and its  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, as applicable:

-    consolidated  pre-tax  income before  minority  interest and income or loss
     from equity investees;
-    fixed charges;
-    amortization of capitalized interest;
-    distributed income of equity investees; and
-    the Company's 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,  as
          applicable:

-    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 interest  within  rental  expenses  (equal to  one-third  of
     rental expense); and
-    preference security dividend requirements of consolidated subsidiaries.


<PAGE>

                                                                    EXHIBIT 21.1
Enterprise Products Operating L.P.
List of Subsidiaries of the Company


     Sorrento Pipeline Company, LLC, a Texas limited liability company
     Chunchula Pipeline Company, LLC, a Texas limited liability company
     Cajun Pipeline Company, LLC, a Texas limited liability company
     HSC Pipeline Partnership, L.P., a Texas limited partnership
     Propylene Pipeline Partnership, L.P., a Texas limited partnership
     Enterprise Products Texas Operating, L.P., a Texas limited partnership
     Entell NGL Services, LLC, a Delaware limited liability company
     Enterprise Lou-Tex Propylene Pipeline L.P., a Texas limited partnership
     Enterprise Lou-Tex NGL Pipeline L.P., a Texas limited partnership
     Enterprise NGL Private Lines & Storage LLC, a Delaware limited
      liability company
     Enterprise NGL Pipelines, LLC, a Delaware limited liability company
     Enterprise Gas Processing LLC, a Delaware limited liability company
     Enterprise Norco LLC, a Delaware limited liability company
     Enterprise Fractionation LLC, a Delaware limited liability company
     Sabine Propylene Pipeline L.P., a Texas limited partnership
     EPOLP 1999 Grantor Trust