EXPLANATORY NOTE

ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

1. GENERAL

2. RECENTLY ISSUED ACCOUNTING STANDARDS

3. BUSINESS ACQUISITIONS

4. INVENTORIES

5. PROPERTY, PLANT AND EQUIPMENT

6. INVESTMENTS IN AND ADVANCES TO UNCONSOLIDATED AFFILIATES

7. INTANGIBLE ASSETS AND GOODWILL

Intangible assets

Goodwill

8. DEBT OBLIGATIONS

9. CAPITAL STRUCTURE

10. SUPPLEMENTAL CASH FLOWS DISCLOSURE

11. FINANCIAL INSTRUMENTS

12. SEGMENT INFORMATION

13. PROVISION FOR INCOME TAXES

14. UNIT OPTION PLAN ACCOUNTING

15. EARNINGS PER UNIT

ENTERPRISE PRODUCTS OPERATING L.P.
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

1. GENERAL

2. RECENTLY ISSUED ACCOUNTING STANDARDS

3. BUSINESS ACQUISITIONS

4. INVENTORIES

5. PROPERTY, PLANT AND EQUIPMENT

6. INVESTMENTS IN AND ADVANCES TO UNCONSOLIDATED AFFILIATES

7. INTANGIBLE ASSETS AND GOODWILL

Intangible assets

Goodwill

8. DEBT OBLIGATIONS

9. CAPITAL STRUCTURE

10. SUPPLEMENTAL CASH FLOWS DISCLOSURE

11. FINANCIAL INSTRUMENTS

12. SEGMENT INFORMATION

13. PROVISION FOR INCOME TAXES

14. UNIT OPTION PLAN ACCOUNTING

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS.

For the three months ended March 31, 2003 and 2002.

Our results of operations

Our liquidity and capital resources

Material contractual obligations

Recent accounting developments

Our critical accounting policies

Other items

Cautionary Statement regarding Forward-Looking Information and Risk Factors

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Item 4. CONTROLS AND PROCEDURES

PART II. OTHER INFORMATION.

Item 6. EXHIBITS AND REPORTS ON FORM 8-K.

SIGNATURES

SARBANES-OXLEY SECTION 302 CERTIFICATIONS

EXPLANATORY NOTE

ENTERPRISE PRODUCTS PARTNERS L.P.NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

1. GENERAL

2. RECENTLY ISSUED ACCOUNTING STANDARDS

3. BUSINESS ACQUISITIONS

4. INVENTORIES

5. PROPERTY, PLANT AND EQUIPMENT

6. INVESTMENTS IN AND ADVANCES TO UNCONSOLIDATED AFFILIATES

7. INTANGIBLE ASSETS AND GOODWILL

Intangible assets

Goodwill

8. DEBT OBLIGATIONS

9. CAPITAL STRUCTURE

10. SUPPLEMENTAL CASH FLOWS DISCLOSURE

11. FINANCIAL INSTRUMENTS

12. SEGMENT INFORMATION

13. PROVISION FOR INCOME TAXES

14. UNIT OPTION PLAN ACCOUNTING

15. EARNINGS PER UNIT

ENTERPRISE PRODUCTS OPERATING L.P.NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

1. GENERAL

2. RECENTLY ISSUED ACCOUNTING STANDARDS

3. BUSINESS ACQUISITIONS

4. INVENTORIES

5. PROPERTY, PLANT AND EQUIPMENT

6. INVESTMENTS IN AND ADVANCES TO UNCONSOLIDATED AFFILIATES

7. INTANGIBLE ASSETS AND GOODWILL

Intangible assets

Goodwill

8. DEBT OBLIGATIONS

9. CAPITAL STRUCTURE

10. SUPPLEMENTAL CASH FLOWS DISCLOSURE

11. FINANCIAL INSTRUMENTS

12. SEGMENT INFORMATION

13. PROVISION FOR INCOME TAXES

14. UNIT OPTION PLAN ACCOUNTING

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

For the three months ended March 31, 2003 and 2002.

Our results of operations

Our liquidity and capital resources

Material contractual obligations

Related party transactions

Recent accounting developments

Our critical accounting policies

Other items

Cautionary Statement regarding Forward-Looking Information and Risk Factors

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Item 4. CONTROLS AND PROCEDURES

PART II. OTHER INFORMATION.

Item 6. EXHIBITS AND REPORTS ON FORM 8-K.

SIGNATURES

SARBANES-OXLEY SECTION 302 CERTIFICATIONS

ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

ENTERPRISE PRODUCTS OPERATING L.P.
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS.

                                                     FORM 10-Q

                                        SECURITIES AND EXCHANGE COMMISSION

                                              Washington, D.C. 20549


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

                                 For the quarterly period ended September 30, 2001

                                                        OR

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

                                 For the transition period from _______ to _______


                                       Commission file number: 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
              incorporation or organization)                                   Identification No.)

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


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 ___


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 and Limited Partner, Enterprise Products Partners L.P.
(a publicly-traded master limited partnership under New York Stock Exchange ("NYSE") symbol "EPD" (SEC File No.
1-14323)), and 1.0101% by its General Partner, Enterprise Products GP, LLC.














                                Enterprise Products Operating L.P. and Subsidiaries

                                                 TABLE OF CONTENTS


                                                                                                 Page
                                                                                                  No.
                                                                                                 ----
Part I.  Financial Information

Item 1.  Consolidated Financial Statements

Enterprise Products Operating L.P. Unaudited Consolidated Financial Statements:

         Consolidated Balance Sheets, September 30, 2001 and December 31, 2000                   1

         Statements of Consolidated Operations
                  for the three and nine months ended September 30, 2001 and 2000                2

         Statements of Consolidated Cash Flows
                  for the nine months ended September 30, 2001 and 2000                          3

         Statements of Consolidated Partners' Equity and Comprehensive Income
                  for the nine months ended September 30, 2001 and 2000                          4

         Notes to Unaudited Consolidated Financial Statements                                    5

Item 2.  Management's Discussion and Analysis of Financial Condition and
                  Results of Operation                                                           19

Item 3.  Quantitative and Qualitative Disclosures about Market Risk                              35

Part II. Other Information

Item 2.  Use of Proceeds                                                                         39

Item 6.  Exhibits and Reports on Form 8-K                                                        39

         Signature Page




                                                     Glossary


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

Acadian Gas                    Acadian Gas, LLC
BBtu/d                         Billion British thermal units per day, a measure of heating value
Bcf                            Billion cubic feet
Bcf/d                          Billion cubic feet per day
BPD                            Barrels per day
Btu                            British thermal unit, a measure of heating value
Company                        Enterprise Products Partners L.P. and subsidiaries
EPCO                           Enterprise Products Company, an affiliate of the Company
EPE                            El Paso Corporation, its subsidiaries and affiliates
FASB                           Financial Accounting Standards Board
FERC                           Federal Energy Regulatory Commission
General Partner                Enterprise Products GP, LLC, the general partner of the Company and Limited Partner
Limited Partner               Enterprise Products Partners L.P., the parent of the Company
Manta Ray                      A Gulf of Mexico offshore Louisiana natural gas pipeline system owned by Manta Ray
                               Offshore Gathering Company, LLC
MBFC                           Mississippi Business Finance Corporation
MBPD                           Thousand barrels per day
MMBbls                         Millions of barrels
MMBtus                         Million British thermal units, a measure of heating value
MMcf                           Million cubic feet
MMcf/d                         Million cubic feet per day
MTBE                           Methyl tertiary butyl ether
Nautilus                       A Gulf of Mexico offshore Louisiana natural gas pipeline system owned by Nautilus
                               Pipeline Company, LLC
NGL or NGLs                    Natural gas liquid(s)
NYSE                           New York Stock Exchange
PTR                            Plant thermal reduction
SEC                            Securities and Exchange Commission
SFAS                           Statement of Financial Accounting Standards
Shell                          Shell Oil Company, its subsidiaries and affiliates





                                          PART 1. FINANCIAL INFORMATION.
                                    Item 1. CONSOLIDATED FINANCIAL STATEMENTS.
                                           Enterprise Products Operating L.P.
                                              Consolidated Balance Sheets
                                             (Dollar amounts in thousands)
                                                                                      September 30,
                                                                                          2001           December 31,
                                      ASSETS                                           (Unaudited)           2000
                                                                                    -------------------------------------
Current Assets
     Cash and cash equivalents  (includes restricted cash of
        $9,032 at September 30, 2001)                                                     $   62,952         $   58,446
     Accounts receivable - trade, net of allowance for doubtful accounts of
        $17,007 at September 30, 2001 and $10,916 at December 31, 2000                       322,519            409,085
     Accounts receivable - affiliates                                                         16,184              5,738
     Inventories                                                                             152,058             93,222
     Prepaid and other current assets                                                         68,109             12,107
                                                                                    -------------------------------------
               Total current assets                                                          621,822            578,598
Property, Plant and Equipment, Net                                                         1,261,155            975,322
Investments in and Advances to Unconsolidated Affiliates                                     408,290            298,954
Intangible assets, net of accumulated amortization of $10,208 at
     September 30, 2001 and $5,374 at December 31, 2000                                      205,102             92,869
Other Assets                                                                                   9,505              2,867
                                                                                    -------------------------------------
               Total                                                                      $2,505,874         $1,948,610
                                                                                    =====================================

                         LIABILITIES AND PARTNERS' EQUITY
Current Liabilities
     Accounts payable - trade                                                                $53,670            $96,560
     Accounts payable - affiliate                                                             33,135             56,447
     Accrued gas payables                                                                    285,411            377,126
     Accrued expenses                                                                         17,309             20,579
     Other current liabilities                                                                81,581             34,763
                                                                                    -------------------------------------
               Total current liabilities                                                     471,106            585,475
Long-Term Debt                                                                               855,443            403,847
Other Long-Term Liabilities                                                                   17,197             15,613
Minority Interest                                                                              1,193              1,004
Commitments and Contingencies
Partners' Equity
     Limited Partner                                                                       1,164,935            937,829
     General Partner                                                                          11,887              9,569
     Accumulated other comprehensive income                                                   (2,321)
     Parent's Units acquired by Trust                                                        (13,566)            (4,727)
                                                                                   -------------------------------------
               Total Partners' Equity                                                      1,160,935            942,671
                                                                                    -------------------------------------
               Total                                                                      $2,505,874         $1,948,610
                                                                                    =====================================

                                See Notes to Unaudited Consolidated Financial Statements


Page 1



                                           Enterprise Products Operating L.P.
                                          Statements of Consolidated Operations
                                                       (Unaudited)
                                              (Dollar amounts in thousands)

                                                                  Three Months                      Nine Months
                                                               Ended September 30,              Ended September 30,
                                                        --------------------------------  -------------------------------
                                                              2001            2000              2001            2000
                                                         --------------------------------  -------------------------------
REVENUES
Revenues from consolidated operations                          $723,329        $717,113        $2,519,041     $2,056,307
Equity income in unconsolidated affiliates                        6,289           4,750            17,350         23,290
                                                         --------------------------------  -------------------------------
         Total                                                  729,618         721,863         2,536,391      2,079,597
                                                         --------------------------------  -------------------------------
COST AND EXPENSES
Operating costs and expenses                                    634,496         659,021         2,263,876      1,878,233
Selling, general and administrative                               7,644           6,978            22,230         20,020
                                                         --------------------------------  -------------------------------
         Total                                                  642,140         665,999         2,286,106      1,898,253
                                                         --------------------------------  -------------------------------
OPERATING INCOME                                                 87,478          55,864           250,285        181,344
OTHER INCOME (EXPENSE)
Interest expense                                                (12,610)         (7,486)          (35,928)       (23,330)
Interest income from unconsolidated affiliates                                     (122)               15             80
Dividend income from unconsolidated affiliates                      392           2,241             2,024          6,236
Interest income - other                                           1,018             458             6,789          3,431
Other, net                                                         (275)            (71)             (806)          (496)
                                                         --------------------------------  -------------------------------
          Other income  (expense)                               (11,475)         (4,980)          (27,906)       (14,079)
                                                        --------------------------------  -------------------------------
INCOME BEFORE MINORITY INTEREST                                  76,003          50,884           222,379        167,265
MINORITY INTEREST                                                   (46)            (18)             (113)           (88)
                                                         --------------------------------  -------------------------------
NET INCOME                                                     $ 75,957        $ 50,866        $  222,266     $  167,177
                                                         ================================  ===============================

                                See Notes to Unaudited Consolidated Financial Statements





Page 2



                                          Enterprise Products Operating L.P.
                                         Statements of Consolidated Cash Flows
                                                      (Unaudited)
                                             (Dollar amounts in Thousands)

                                                                                            Nine Months Ended
                                                                                              September 30,
                                                                                   -------------------------------------
                                                                                          2001              2000
                                                                                   -------------------------------------
OPERATING ACTIVITIES
Net income                                                                                  $222,266          $167,177
Adjustments to reconcile net income to cash flows provided by
      (used for) operating activities:
      Depreciation and amortization                                                           37,245            27,952
      Equity in income of unconsolidated affiliates                                          (17,350)          (23,290)
      Distributions received from unconsolidated affiliates                                   30,602            25,997
      Leases paid by EPCO                                                                      7,980             7,984
      Minority interest                                                                          113                88
      Loss (gain) on sale of assets                                                             (392)            2,276
      Changes in fair market value of financial instruments (See Note 7)                     (39,429)
      Net effect of changes in operating accounts                                           (117,669)          (29,189)
                                                                                   -------------------------------------
Operating activities cash flows                                                              123,366           178,995
                                                                                   -------------------------------------
INVESTING ACTIVITIES
Capital expenditures                                                                         (92,641)         (200,157)
Proceeds from sale of assets                                                                     567                85
Business acquisitions, net of cash acquired                                                 (225,665)
Collection of notes receivable from unconsolidated affiliates                                                    6,519
Investments in and advances to unconsolidated affiliates                                    (119,865)           (2,307)
                                                                                   -------------------------------------
Investing activities cash flows                                                             (437,604)         (195,860)
                                                                                   -------------------------------------
FINANCING ACTIVITIES
Long-term debt borrowings                                                                    449,716           513,818
Long-term debt repayments                                                                                     (355,000)
Debt issuance costs                                                                           (3,126)           (2,759)
Cash distributions to partners                                                              (119,084)         (104,401)
Cash distributions to minority interest                                                          (58)
Cash contributions from minority interest                                                        134
Limited Partner Units acquired by Trust                                                       (8,838)
Increase in restricted cash associated with commodity hedging activities                      (9,032)
                                                                                   -------------------------------------
Financing activities cash flows                                                              309,712            51,658
                                                                                   -------------------------------------
NET CHANGE IN CASH AND CASH EQUIVALENTS                                                       (4,526)           34,793
CASH AND CASH EQUIVALENTS, JANUARY 1                                                          58,446             5,159
                                                                                   -------------------------------------
CASH AND CASH EQUIVALENTS, SEPTEMBER 30                                                     $ 53,920          $ 39,952
                                                                                   =====================================


                               See Notes to Unaudited Consolidated Financial Statements





Page 3



                                     Enterprise Products Operating L.P.
                    Statements of Consolidated Partners' Equity and Comprehensive Income
                                  (Unaudited, dollar amounts in thousands)

                                                                                  Partners' Equity
                                                                       ---------------------------------------
                                                                             For the Nine Month Periods
                                                                                Ended September 30,
                                                                       ------------------  -------------------
                                                                             2001                 2000
                                                                       ------------------  -------------------
Limited Partner
        Balance, beginning of year                                           $  937,829             $791,279
        Net income                                                              220,021              165,489
        Leases paid by EPCO                                                       7,899                7,902
        Asset contributions by partner related to
           business                                                             117,067               55,241
        acquisitions
        Cash distributions                                                     (117,881)            (103,346)
                                                                       ------------------  -------------------
        Balance, end of period                                                1,164,935              916,565
                                                                       ------------------  -------------------
Parent's Units acquired by Trust
        Balance, beginning of year                                               (4,727)              (4,727)
        Limited Partner Units purchased by Trust                                 (8,839)
                                                                       ------------------  -------------------
        Balance, end of period                                                  (13,566)              (4,727)
                                                                       ------------------  -------------------
General Partner
        Balance, beginning of year                                                9,570                8,074
        Net income                                                                2,245                1,689
        Leases paid by EPCO                                                          81                   81
        Asset contributions by partners related to
           business acquisitions                                                  1,194                  564
        Cash distributions                                                       (1,203)              (1,055)
                                                                       ------------------  -------------------
        Balance, end of period                                                   11,887                9,353
                                                                       ------------------  -------------------
Accumulated Other Comprehensive Loss
        Balance, beginning of year
        Cumulative transition adjustment recorded on
           January 1, 2001 upon adoption of SFAS 133                            (42,190)
        Reclassification of cumulative transition adjustment
           transition adjustment to earnings                                     39,869
                                                                       ------------------
        Balance, end of period                                                   (2,321)
                                                                       ------------------  -------------------
        Total Partners' Equity                                               $1,160,935             $921,191
                                                                       ==================  ===================

                                                                             Other Comprehensive Income
                                                                       ---------------------------------------
                                                                                For the Nine Months
                                                                                Ended September 30,
                                                                       ------------------  -------------------
                                                                             2001                 2000
                                                                       ------------------  -------------------
Net Income                                                                   $  222,266             $167,178
Less:   Reclassification of cumulative transition adjustment
           from Accumulated Other Comprehensive Loss                             (2,321)
                                                                       ------------------  -------------------
Comprehensive Income                                                         $  219,945             $167,178
                                                                       ==================  ===================


                          See Notes to Unaudited Consolidated Financial Statements

Page 4


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

1.    GENERAL

In the opinion of Enterprise Products Operating L.P.  (the "Company"), the accompanying unaudited consolidated
financial statements include all adjustments consisting of normal recurring accruals necessary for a fair
presentation of the Company's consolidated financial position as of September 30, 2001, consolidated results of
operations for the three and nine month periods ended September 30, 2001 and 2000, and cash flows, partners'
equity and comprehensive income for the nine month periods ended September 30, 2001 and 2000.  Although the
Company believes the disclosures in these financial statements are adequate to make the information presented not
misleading, certain information and footnote disclosures normally included in annual financial statements
prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to
the rules and regulations of the Securities and Exchange Commission.  These unaudited financial statements should
be read in conjunction with the Company's Annual Report on Form 10-K (File No. 333-93239-01) for the year ended
December 31, 2000.

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

The results of operations for the three and nine month periods ended September 30, 2001 are not necessarily
indicative of the results to be expected for the full year due to the effects of, among other things, (a)
seasonal variations in NGL and natural gas prices, (b) timing of maintenance and other expenditures and (c)
acquisitions of assets and other interests.

Certain reclassifications have been made to prior years' financial statements to conform to the presentation of
the current period financial statements.  These reclassifications do not affect historical net income of the
Company.

Dollar amounts presented in the tabulations within the notes to the consolidated financial statements are stated
in thousands of dollars, unless otherwise indicated.


2.    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
8.

At September 30, 2001, the Company's equity method investments (grouped by operating segment) included:

     Fractionation segment:

o    Baton Rouge Fractionators LLC ("BRF") - an approximate 32.25% interest in a natural gas liquid ("NGL")
     fractionation facility located in southeastern Louisiana.
o    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.
o    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 excess cost is attributable to the fair market value of the plant assets).
     The unamortized balance of excess cost over the underlying equity in the net assets of Promix was $7.1
     million at September 30, 2001.


Page 5


     Pipeline segment:

o    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.
o    Wilprise Pipeline Company, LLC ("Wilprise") - a 37.35% interest in a NGL pipeline system located in
     southeastern Louisiana.
o    Tri-States NGL Pipeline LLC  ("Tri-States") - an aggregate 33.33% interest in a NGL pipeline system
     located in Louisiana, Mississippi, and Alabama.
o    Belle Rose NGL Pipeline LLC  ("Belle Rose") - a 41.67% interest in a NGL pipeline system located in
     south Louisiana.
o    Dixie Pipeline Company ("Dixie") -  an aggregate 19.9% interest in a 1,301-mile propane pipeline and
     associated facilities extending from Mont Belvieu, Texas to North Carolina.  The Company's investment
     includes excess cost over the underlying equity in the net assets of Dixie of $37.4 million which is being
     amortized using the straight-line method over a period of 35 years (the excess cost is attributable to the
     fair market value of the pipeline assets).  The unamortized balance of excess cost over the underlying
     equity in the net assets of Dixie was $36.0 million at September 30, 2001.
o    Starfish Pipeline Company LLC ("Starfish") - a 50% interest in a natural gas gathering system and
     related dehydration and other facilities located in south Louisiana and the Gulf of Mexico offshore
     Louisiana.
o    Ocean Breeze Pipeline Company LLC ("Ocean Breeze") - a 25.67% interest in a limited liability company
     owning a 1% interest in the natural gas gathering and transmission systems owned by Manta Ray Offshore
     Gathering Company, LLC ("Manta Ray") and Nautilus Pipeline Company LLC ("Nautilus") located in the Gulf of
     Mexico offshore Louisiana.
o    Neptune Pipeline Company LLC ("Neptune") - a 25.67% interest in a limited liability company owning a 99%
     interest in the Manta Ray and Nautilus natural gas gathering and transmission systems.
o    Nemo Gathering Company, LLC ("Nemo") - a 33.92% interest in a natural gas gathering system located in
     the Gulf of Mexico offshore Louisiana that became operational in August 2001.
o    Evangeline Gas Pipeline Company, L.P. and Evangeline Gas Corp. (collectively, "Evangeline") - an
     approximate 49.5% aggregate interest in a natural gas pipeline system located in south Louisiana.  The
     Company acquired its interests in these entities as a result of the Acadian Gas, LLC acquisition (see Note 3
     for a description of this acquisition).

     2001 Gulf of Mexico natural gas pipeline equity investments

     The Company acquired its equity interests in Ocean Breeze, Neptune, Nemo and Starfish and their underlying
     investments on January 29, 2001 from EPE using proceeds from the issuance of the $450 Million Senior Notes
     (see Note 5 for discussion of long-term debt).  The cash purchase price of the Ocean Breeze, Neptune and
     Nemo interests was $86.9 million with the purchase price of the Starfish interests being $25.1 million.

     As a result of its investment in Ocean Breeze and Neptune, the Company acquired a 25.67% interest in each of
     the Manta Ray and Nautilus systems and a 33.92% interest in the Nemo 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  225 miles of pipeline with a capacity
     of 750 MMcf/d and related equipment, the Nautilus system comprises approximately 101 miles of pipeline with
     a capacity of 600 MMcf/d, and the Nemo system comprises approximately 24 miles of pipeline with a capacity
     of 300 MMcf/d.   Shell is responsible for the commercial and physical operations of these pipeline systems.

     The Company's investment in Ocean Breeze, Neptune and Nemo includes excess cost over the underlying equity
     in the net assets of these entities of $23.7 million which is being amortized using the straight-line method
     over a period of 35 years (the excess cost amounts are attributable to the fair market value of the pipeline
     assets).    The unamortized balance of excess cost over the underlying equity in the net assets of Ocean
     Breeze, Neptune and Nemo was $23.1 million at September 30, 2001.

     As a result of its investment in Starfish, the Company acquired a 50% interest in the Stingray system and a
     related onshore natural gas dehydration facility.  The Company's sole partner in Starfish is an affiliate of
     Shell.  The Stingray system comprises approximately 375 miles of pipeline with a capacity of 1.2 Bcf/d and


Page 6

     is located offshore Louisiana in the Gulf of Mexico.  Shell is responsible for the commercial and physical
     operations of the Stingray system and related facilities.

     Historical information for periods prior to January 1, 2001 do not reflect any impact associated with the
     Company's equity investments in Ocean Breeze, Neptune, Nemo and Starfish.   See Note 3 for combined pro
     forma impact of these investments on selected financial information of the Company.

     Octane Enhancement segment:

o    Belvieu Environmental Fuels ("BEF") - a 33.33% interest in a MTBE production facility located in
     southeast Texas.  The production of MTBE is driven by oxygenated fuels programs enacted under the federal
     Clean Air Act Amendments of 1990 and other legislation and as an additive to increase octane in motor
     gasoline.  Any changes to these 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 have been well below levels of public health concern, there have been  calls
     for the phase-out of MTBE in motor gasoline in various federal and state governmental agencies and advisory
     bodies.


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

At September 30, 2001, 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 company
owning a natural gas processing plant, fractionation facilities, storage, and gas gathering pipelines in
Louisiana. This investment is accounted for using the cost method under the Processing segment.






Page 7


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


                                               September 30,      December 31,
                                                    2001               2000
                                             -------------------------------------
Accounted for on equity basis:
     Fractionation:
        BRF                                            $ 29,664          $ 30,599
        BRPC                                             19,069            25,925
        Promix                                           45,497            48,670
     Pipeline:
        EPIK                                             17,691            15,998
        Wilprise                                          8,950             9,156
        Tri-States                                       27,277            27,138
        Belle Rose                                       11,655            11,653
        Dixie                                            37,585            38,138
        Starfish                                         25,875
        Ocean Breeze                                        967
        Neptune                                          75,046
        Nemo                                             11,745
        Evangeline                                        2,697
     Octane Enhancement:
        BEF                                              61,572            58,677
Accounted for on cost basis:
     Processing:
        VESCO                                            33,000            33,000
                                             -------------------------------------
     Total                                             $408,290          $298,954
                                             =====================================

The following table shows equity in income (loss) of unconsolidated affiliates for the periods indicated:

                                       For Three Months Ended                 For Nine Months Ended
                                           September 30,                          September 30,
                                -------------------------------------  -------------------------------------
                                      2001               2000                 2001              2000
                                ----------------------------------------------------------------------------
Fractionation:
      BRF                                 $  672             $  434              $   732           $ 1,171
      BRPC                                   221                134                  625               115
      Promix                               1,055              1,170                2,844             4,378
Pipeline:
      EPIK                                   150               (124)                (944)            1,846
      Wilprise                               370                135                  233               297
      Tri-States                             789                694                  889             2,215
      Belle Rose                              62                117                    2               266
      Dixie                                  240                                   1,200
      Starfish                               789                                   2,762
      Ocean Breeze                             8                                      22
      Neptune                              1,035                                   2,824
      Nemo                                   (52)                                    (42)
      Evangeline                              41                                    (108)
Octane Enhancement:
      BEF                                    909              2,190                6,311            13,002
                                -------------------------------------  -------------------------------------
      Total                               $6,289             $4,750              $17,350           $23,290
                                =====================================  =====================================


Page 8


The following table presents summarized income statement information for the unconsolidated affiliates accounted
for by the equity method for the periods indicated (on a 100% basis):

                                              Summarized Income Statement data for the Three Months ended
                             -----------------------------------------------------------------------------------------------
                                          September 30, 2001                               September 30, 2000
                             ----------------------------------------------  -----------------------------------------------
                                               Operating         Net                           Operating          Net
                                Revenues        Income          Income          Revenues         Income         Income
                             ----------------------------------------------  -----------------------------------------------
Fractionation:
       BRF                         $  5,827        $ 2,057        $ 2,084           $  4,774       $ 1,282         $ 1,347
       BRPC                           2,414            717            738              2,333           398             448
       Promix                        11,122          3,439          3,461             12,242         3,956           4,019
Pipeline:
       EPIK                           2,583            272            302              1,817          (323)           (282)
       Wilprise                       1,057            989            992                726           397             406
       Tri-States                     3,632          2,328          2,365              3,430         2,060           2,088
       Belle Rose                       489            144            149                536           279             279
       Dixie (a)                     14,534          6,860          4,138
       Starfish (b)                   3,916          1,649          2,227
       Ocean Breeze (b)                  34              4             26
       Neptune (b)                    7,940          3,354          3,363
       Nemo (b)                         213            (44)           (38)
       Evangeline (c)                43,486          1,287             32
Octane Enhancement:
       BEF                           54,955          2,060          2,725             77,331         6,202           6,570
                             ----------------------------------------------  -----------------------------------------------
Total                              $152,202        $25,116        $22,564           $103,189       $14,251         $14,875
                             ==============================================  ===============================================


                                               Summarized Income Statement data for the Nine Months ended
                             -----------------------------------------------------------------------------------------------
                                          September 30, 2001                               September 30, 2000
                             ----------------------------------------------  -----------------------------------------------
                                               Operating         Net                           Operating          Net
                                Revenues        Income          Income          Revenues         Income         Income
                             ----------------------------------------------  -----------------------------------------------
Fractionation:
       BRF                         $ 13,652        $ 2,357        $ 2,434           $ 13,989        $ 3,504         $ 3,631
       BRPC                           9,247          1,949          2,085              2,333            211             383
       Promix                        32,465          9,327          9,425             36,968         14,097          14,274
Pipeline:
       EPIK                           4,550         (1,510)        (1,423)            14,789          3,561           3,699
       Wilprise                       1,950            611            625              2,149            867             891
       Tri-States                     7,585          2,590          2,664             10,677          6,530           6,650
       Belle Rose                     1,043            (61)           (43)             1,802            645             645
       Dixie (a)                     38,570         15,161          8,967
       Starfish (b)                  17,383          6,039          6,143
       Ocean Breeze (b)                 121             91             91
       Neptune (b)                   24,687         12,002         11,944
       Nemo (b)                         213            (86)            (2)
       Evangeline (c)                91,095          2,297           (112)
Octane Enhancement:
       BEF                          168,873         17,982         18,932            214,761         38,575          39,007
                             ----------------------------------------------  -----------------------------------------------
Total                              $411,434        $68,749        $61,730           $297,468        $67,990         $69,180
                             ==============================================  ===============================================


Page 9


Notes to Summarized Income Statement data tables:
(a)  Dixie became an equity method investment in October 2000.
(b)  These entities became equity method investments of the Company beginning in January 2001.
(c ) This entity became an equity method investment of the Company in April 2000 as a result of the Acadian Gas
acquisition (see Note 3).


3.    ACQUISITIONS

Since January 1, 2001, the Company has invested approximately $338 million (net of cash acquired) in natural gas
pipeline businesses.   These include:

     o    a combined $112 million in Ocean Breeze, Neptune, Nemo and Starfish
          (see Note 2 for a discussion of these equity investments); and,
     o    an initial $226 million for the purchase of Acadian Gas, LLC ("Acadian
          Gas").

Acquisition of Acadian Gas

On April 2, 2001, the Company acquired Acadian Gas from Shell US Gas and Power LLC, an affiliate of Shell, for
approximately $226 million in cash using proceeds from the issuance of the $450 Million Senior Notes (see Note 5
for a discussion of long-term debt).   The cash purchase price is subject to certain post-closing adjustments
expected to be completed during the fourth quarter of 2001.   The effective date of the transaction was April 1,
2001.

Acadian Gas is involved in the purchase, sale, transportation and storage of natural gas in Louisiana.   Acadian
Gas' assets are comprised of the 438-mile Acadian, 577-mile Cypress and 27-mile Evangeline natural gas pipeline
systems, which together have over 1.1 Bcf/d of capacity.   These natural gas pipeline systems are wholly-owned by
Acadian Gas with the exception of the Evangeline system in which Acadian Gas owns an aggregate 49.5% interest.
The assets acquired include a leased natural gas storage facility located in Napoleonville, Louisiana.

The Acadian, Cypress and Evangeline systems link supplies of natural gas from onshore developments and, through
connections with offshore pipelines, Gulf of Mexico production to local gas distribution companies, electric
generation and industrial customers, including those in the Baton Rouge-New Orleans-Mississippi River corridor.
In addition, these systems have interconnects with 12 interstate and four intrastate pipelines and a
bi-directional interconnect with the U.S. natural gas marketplace at Henry Hub.

The Acadian Gas acquisition was accounted for under the purchase method of accounting and, accordingly, the
initial purchase price has been allocated to the assets acquired and liabilities assumed based on their estimated
fair values at April 1, 2001, as follows:

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

The balances related to the Acadian Gas acquisition included in the consolidated balance sheet dated September
30, 2001 are based upon preliminary information and are subject to change as additional information is obtained.
As noted earlier, the initial purchase price is subject to certain post-closing adjustments attributable to
working capital items expected to be finalized during the fourth quarter of 2001.

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


Page 10


Pro Forma effect of Acadian Gas acquisition and recently acquired equity investments

The following table presents selected unaudited pro forma information for the three month period ended September
30, 2000 and nine month periods ended September 30, 2001 and 2000 as if the acquisition of the Acadian Gas
natural gas pipeline systems had been made as of the beginning of the years presented.  This table also
incorporates selected unaudited pro forma information for the three and nine month periods ended September 30,
2000 relating to the Company's equity investments in Starfish, Ocean Breeze and Neptune.

The pro forma information is based upon data currently available to and certain estimates and assumptions by
management and, as a result, are not necessarily indicative of 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.

                                                      Three
                                                   Months Ended             Nine Months Ended
                                                  September 30,               September 30,
                                                                   -------------------------------------
                                                       2000              2001               2000
                                                --------------------------------------------------------

Revenues                                                  $875,197        $2,748,318         $2,483,449

Income before extraordinary item
   and minority interest                                  $ 51,201        $  226,663         $  166,388

Net income                                                $ 50,683        $  226,550         $  164,705


4.       RECENTLY ISSUED ACCOUNTING STANDARDS

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

At present, the Company's intangible assets include the values assigned to the 20-year Shell 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 value of the Shell Processing
Agreement is being amortized over its contract term and the 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.  Based upon
initial interpretations of the new accounting standards, the Company anticipates that the Shell Processing
Agreement will continue to be amortized over its contract term; however, the excess cost attributable to Mont
Belvieu Associates will be reclassified to goodwill in accordance with the new standard and its amortization will
cease (currently, $0.5 million in amortization expense annually).  This goodwill would then be subject to
impairment testing as prescribed in SFAS No. 142.

The Company is continuing to evaluate the complex provisions of SFAS No. 141 and SFAS No. 142 and has not adopted
such provisions in its September 30, 2001 financial statements.

In addition to SFAS No. 141 and No. 142, the FASB also issued SFAS No. 143, "Accounting for Asset Retirement
Obligations", in June 2001.   This statement establishes accounting standards for the recognition and
measurement of a liability for an asset retirement obligation and the associated asset retirement cost.   This
statement is effective for the Company's fiscal year beginning January 1, 2003.   In August 2001, the FASB issued

Page 11


SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets".  This statement addresses
financial accounting and reporting for the impairment of long-lived assets and for long-lived assets to be
disposed of.   This statement is effective for the Company's fiscal year beginning January 1, 2002.   Management
is currently studying both SFAS No. 143 and No. 144 for  their possible impact, if any, on the consolidated
financial statements when they are adopted.


5.    LONG-TERM DEBT

Long-term debt consisted of the following at:

                                                                              September 30,       December 31,
                                                                                   2001               2000
                                                                            ---------------------------------------
Borrowings under:
     $350 Million Senior Notes, 8.25% fixed rate, due March 2005                      350,000             350,000
     $54 Million MBFC Loan, 8.70% fixed rate, due March 2010                           54,000              54,000
     $450 Million Senior Notes, 7.50% fixed rate, due February 2011                   450,000
                                                                            ---------------------------------------
            Total principal amount                                                    854,000             404,000
Unamortized balance of increase in fair value related to
     hedging a portion of fixed-rate debt (see Note 7)                                  1,833
Less unamortized discount on:
     $350 Million Senior Notes                                                           (126)               (153)
     $450 Million Senior Notes                                                           (264)
Less current maturities of long-term debt
                                                                            ---------------------------------------
            Long-term debt                                                           $855,443            $403,847
                                                                            =======================================

The Company has the ability to borrow under the terms of its $250 Million Multi-Year Credit Facility  and $150
Million 364-Day Credit Facility.   The $150 Million 364-Day Credit Facility has an original maturity date of
November 16, 2001.   An amendment to the 364-Day Credit Facility to extend this date through November 15, 2002
was consented to by the lenders in early November 2001.   No amount was outstanding under either of these two
revolving credit facilities at September 30, 2001 or December 31, 2000.

At September 30, 2001, the Company had a total of $75 million of standby letters of credit capacity under its
$250 Million Multi-Year Credit Facility of which $14.9 million was outstanding.

$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 used to acquire the Acadian
Gas, Ocean Breeze, Neptune, Nemo and Starfish natural gas pipeline systems for $338 million and to finance the
cost to construct certain NGL pipelines and related projects and for working capital and other general
partnership purposes.

The $450 Million Senior Notes were issued under the indenture agreement dated March 15, 2000 which is also
applicable to the $350 Million Senior Notes and therefore are subject to similar covenants and terms.   As with
the $350 Million Senior Notes, the $450 Million Senior Notes:

     |X|  are subject to a make-whole redemption right;
     |X|  are an unsecured  obligation and rank equally with existing and future
          unsecured  and  unsubordinated  indebtedness  and senior to any future
          subordinated indebtedness; and,
     |X|  are  guaranteed  by the  Limited  Partner  through  an  unsecured  and
          unsubordinated guarantee.

The issuance of the $450 Million Senior Notes was a final takedown under the December 1999 $800 million universal
registration statement; therefore, the amount of securities available under this registration statement was


Page 12


reduced to zero. On February 23, 2001, the Company filed a $500 million universal shelf registration statement
(the "February 2001 Registration Statement") covering the issuance of an unspecified amount of equity or debt
securities or a combination thereof.

The Company was in compliance with the restrictive covenants associated with all of its fixed-rate and
variable-rate debt instruments at September 30, 2001.

Increase in fair value of fixed-rate debt.  Upon adoption of SFAS No. 133, Accounting for Derivative Instruments
and Hedging Activities (as amended and interpreted) on January 1, 2001, the Company recorded a $2.3 million
non-cash increase in the fair value of its fixed-rate debt.  SFAS No. 133 required that the Company's interest
rate swaps and their associated hedged fixed-rate debt be recorded at fair value upon adoption of the standard.
After adoption of the standard, the interest rate swaps were dedesignated due to differences in the estimated
maturity dates of the interest rate swaps versus the fixed-rate debt.  As a result, the fair value of the hedged
fixed-rate debt will not be adjusted for future changes in fair value and the $2.3 million increase in the fair
value of the debt will be amortized to earnings over the remaining life of the fixed-rate debt to which it
applies, which approximates 10 years.  The fair value adjustment of $2.3 million is not a cash obligation of the
Company and does not alter the amount of the Company's indebtedness.    See Note 7 for additional information
concerning the Company's financial instruments.


6.    SUPPLEMENTAL CASH FLOW DISCLOSURE

                                                                         Nine Months Ended
                                                                           September 30,
                                                             ------------------------------------------
                                                                     2001                 2000
                                                             ------------------------------------------
(Increase) decrease in:
          Accounts receivable                                          $ 151,246             $(17,194)
          Inventories                                                    (51,753)             (66,270)
          Prepaid and other current assets                                (8,732)               1,841
          Intangible assets                                                                    (4,805)
          Other assets                                                      (121)              (3,022)
Increase (decrease) in:
          Accounts payable                                               (79,424)               7,109
          Accrued gas payable                                           (146,041)              47,517
          Accrued expenses                                                (5,818)              (6,721)
          Other current liabilities                                       22,850               12,753
          Other liabilities                                                  124                 (397)
                                                             ------------------------------------------
Net effect of changes in operating accounts                            $(117,669)            $(29,189)
                                                             ==========================================

Business acquisitions (net of cash received) for the 2001 period reflects a net $226 million paid to an affiliate
of Shell for Acadian Gas.   Investments in and advances to unconsolidated affiliates for the 2001 period reflects
$112 million paid to EPE for equity interests in various Gulf of Mexico natural gas pipeline systems.  Capital
expenditures for 2000 included $99.5 million for the purchase of the Lou-Tex Propylene Pipeline and related
assets.

As a result of the Company's adoption of SFAS 133 on January 1, 2001, the Company records various financial
instruments relating to interest rate and commodity positions at their respective fair values.   For the nine
months ended September 30, 2001, the Company recognized a net $39.4 million in non-cash mark-to-market gains
related to increases in the fair value of these  financial instruments ($34.6 million of this amount was
attributable to financial instruments used in the Company's Processing segment with the remainder resulting from
interest rate hedging activities).  See Note 7 below for a further description of the Company's  financial
instruments.

Cash and cash equivalents at September 30, 2001 per the Statements of Consolidated Cash Flows excludes $9.0
million of restricted cash associated with hedging activities.


Page 13



7. FINANCIAL INSTRUMENTS

The Company holds and issues financial instruments for the purpose of hedging the risks of certain identifiable
and anticipated transactions primarily in its Processing segment.    In general, the types of risks hedged are
those relating to the variability of future earnings and cash flows caused by changes in commodity prices and
interest rates.

Commodity Financial Instruments

In its Processing segment, the Company's margin is directly exposed to commodity price risk.  In order to manage
this risk, the Company may enter into swaps, forwards, commodity futures, options and other commodity financial
instruments with similar characteristics that are permitted by contract or business custom to be settled in cash
or with another financial instrument.   The 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.

The Company has adopted a commercial policy to manage its exposure to the risks associated with its Processing
segment.   The objective of this policy is to assist the Company in achieving its profitability goals while
maintaining a portfolio with an acceptable level of risk, defined as remaining within the position limits
established by the General Partner.  The Company enters into risk management transactions to manage price risk,
basis risk, physical risk, or other risks related to the energy commodities 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 (such as those mentioned previously), 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.

On January 1, 2001, the Company adopted SFAS No. 133 which required the Company to record the fair market value
of the commodity  financial instruments on the balance sheet based upon then current market conditions.   The
fair market value of the then outstanding commodity financial instruments was a net liability of $42.2 million
(the "cumulative transition adjustment") with an offsetting equal amount recorded in Other Comprehensive
Income.   The amounts in Other Comprehensive Income are reclassified to earnings in the accounting period
associated with the hedged transaction (e.g. production month).   The $42.2 million cumulative transition
adjustment was or will be reclassified to earnings as follows:

     o    $21.7 million during the first quarter of 2001;
     o    $10.7 million during the second quarter of 2001;
     o    $7.3 million during the third quarter of 2001; with the remaining
     o    $2.5 million reclassified during the fourth quarter of 2001.

The cumulative transition adjustment recorded in Other Comprehensive Income at adoption of SFAS No. 133 will not
be adjusted for changes in fair value; rather, any change in the fair value of these commodity financial
instruments will be recorded in earnings (i.e., mark-to-market accounting treatment).    The decision to record
changes in the fair value of these commodity  financial instruments directly to earnings rather than Other
Comprehensive Income is based upon the determination by management that on an ongoing basis these commodity
financial instruments would be ineffective under the guidelines of SFAS No. 133.

The Company has entered into commodity financial instruments for time periods extending through December 2002.
These commodity  financial instruments may not qualify for hedge accounting treatment under the specific
guidelines of SFAS No. 133.  The Company continues to refer to these financial instruments as hedges inasmuch as
this was the intent when such contracts were executed. This characterization is consistent with the actual
economic performance of the contracts to date and the Company expects these financial instruments should continue
to mitigate commodity price risk in the future.   The specific accounting for these contracts, however, is
consistent with the requirements of SFAS No. 133.    As such, since these contracts do not qualify for hedge
accounting under the specific guidelines of SFAS No. 133, the change in fair value of these  commodity financial
instruments are reflected on the balance sheet and in earnings (i.e., mark-to-market accounting treatment).  The
Company recognized income associated with its commodity financial instruments of $48.2 million and $118.5 million
for the three and nine months ended September 30, 2001, respectively.

Page 14


Other Financial Instruments - Interest rate swaps

The objective of holding interest rate swaps is to manage debt service costs by converting a portion of
fixed-rate debt into variable-rate debt or a portion of variable-rate debt into fixed-rate debt.   An interest
rate swap, in general, requires one party to pay a fixed-rate on the notional amount while the other party pays a
floating-rate based on the notional amount.   Management believes that it is prudent to maintain an appropriate
mixture of variable-rate and fixed-rate debt.

The Company assesses interest rate cash flow risk by identifying and measuring changes in interest rate exposure
that impact future cash flows and evaluating hedging opportunities.  The Company uses analytical techniques to
measure its exposure to fluctuations in interest rates, including cash flow sensitivity analysis to estimate the
expected impact of changes in interest rates on the Company's future cash flows.  The General Partner oversees
the strategies of the Company associated with financial risks and approves instruments that are appropriate for
the Company's requirements.

On January 1, 2001, the Company adopted SFAS No. 133 which required the Company to record the fair market value
of the interest rate swaps on the balance sheet since the swaps were considered fair value hedges.  SFAS No. 133
required that management determine  (at the standard's adoption date) (a) the fair value of the swaps based upon
then current market conditions and (b) the estimated maturity date of the swaps (including an estimate of the
impact of any early termination clauses).  The recording of the fair market value of the swaps was offset by an
equal increase in the fair value of the associated hedged debt instruments and, therefore, had no impact on
earnings upon transition.   See Note 5 for further information regarding the impact of SFAS No. 133 on the
Company's fixed-rate long-term debt.

After adoption, the interest rate swaps were dedesignated as hedging instruments due to differences between the
maturity dates of the swaps and the associated hedged debt instruments.  Dedesignation means that the financial
instrument (in this case, the interest rate swaps) will not be accounted for using hedge accounting under SFAS
No. 133.   Upon dedesignation, any future changes in the fair value of the interest rate swap agreements will be
recorded on the balance sheet through earnings.    Dedesignation also entails that the previously associated
hedged item (in this case, the debt instrument) will not be adjusted for future changes in its fair value.   As a
result, the $2.3 million change in fair value of the debt instrument recorded at the adoption date of SFAS No.
133 will be amortized to earnings over the life of the previously associated debt instrument of approximately 10
years.

The Company recognized income associated with its interest rate swaps of $4.0 million and $9.4 million for the
three and nine months ended September 30, 2001.   In October 2001, the Company realized $4.7 million of
incremental cash flow through the early termination of a swap agreement.

Future issues

Due to the complexity of SFAS No. 133, the FASB is continuing to provide guidance about implementation issues.
Since this guidance is still continuing, the initial conclusions reached by the Company regarding the application
of SFAS No. 133 upon adoption may be altered.  As a result, additional SFAS No. 133 transition adjustments may be
recorded in future periods as the Company adopts new FASB interpretations.



Page 15



8.    SEGMENT INFORMATION

Operating segments are components of a business about which separate financial information is available and that
are regularly evaluated by the chief operating decision maker in deciding how to allocate resources and in
assessing performance.  Generally, financial information is required to be reported on the basis that it is used
internally for evaluating segment performance and deciding how to allocate resources to segments.

The Company has five reportable operating segments:  Fractionation, Pipelines, Processing, Octane Enhancement and
Other.  The reportable segments are generally organized according to the type of services rendered (or process
employed) and products produced and/or sold, as applicable. The segments are regularly evaluated by the Chief
Executive Officer of the General Partner.  Fractionation primarily includes NGL fractionation, butane
isomerization (converting normal butane into high purity isobutane) and polymer grade propylene fractionation
services.  Pipelines consists of  both liquids and natural gas pipeline systems, storage and import/export
terminal services.   Processing includes the natural gas processing business and its related 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 based on gross operating margin.  Gross operating margin reported for
each segment represents operating income before depreciation and amortization, lease expense obligations retained
by EPCO, gains and losses on the sale of assets and general and administrative expenses.   In addition, segment
gross operating margin is exclusive of interest expense, interest income (from unconsolidated affiliates or
others), dividend income from unconsolidated affiliates, minority interest, extraordinary charges and other
income and expense transactions.  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.






Page 16



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


                                                      Operating Segments                            Adjs.
                               ------------------------------------------------------------------
                                                                          Octane                     and         Consol.
                               Fractionation  Pipelines    Processing  Enhancement     Other        Elims.       Totals
                               ---------------------------------------------------------------------------------------------
Revenues from
   external customers
   for three months ended:
     September 30, 2001            $ 75,842     $127,687    $  519,165                    $  635                 $  723,329
     September 30, 2000             113,180       (2,735)      605,875                       793                    717,113
   for nine months ended:
     September 30, 2001             252,087      313,832     1,951,176                     1,946                  2,519,041
     September 30, 2000             302,081       21,191     1,730,976                     2,059                  2,056,307

Intersegment revenues
   for three months ended:
     September 30, 2001              41,273       22,464       244,145                        99   $(307,981)
     September 30, 2000              46,538       12,083       165,761                        93    (224,475)
   for nine months ended:
     September 30, 2001             127,058       67,874       486,111                       290    (681,333)
     September 30, 2000             129,266       40,108       447,646                       282    (617,302)

Equity income in
   unconsolidated affiliates:
   for three months ended:
     September 30, 2001               1,948        3,432                    $   909                                   6,289
     September 30, 2000               1,738          822                      2,190                                   4,750
   for nine months ended:
     September 30, 2001               4,201        6,838                      6,311                                  17,350
     September 30, 2000               5,664        4,624                     13,002                                  23,290

Total revenues
   for three months ended:
     September 30, 2001             119,063      153,583       763,310          909          734    (307,981)       729,618
     September 30, 2000             161,456       10,170       771,636        2,190          886    (224,475)       721,863
   for nine months ended:
     September 30, 2001             383,346      388,544     2,437,287        6,311        2,236    (681,333)     2,536,391
     September 30, 2000             437,011       65,923     2,178,622       13,002        2,341    (617,302)     2,079,597

Gross operating margin
   by segment
   for three months ended:
     September 30, 2001              35,189       22,415        52,026          909          310                    110,849
     September 30, 2000              32,510       10,292        29,083        2,190          429                     74,504
   for nine months ended:
     September 30, 2001              93,660       65,234       148,536        6,311        1,256                    314,997
     September 30, 2000              96,432       39,120        87,123       13,002        1,854                    237,531

Segment assets at:
     September 30, 2001             354,012      698,766       125,071                     9,572       73,734     1,261,155
     December 31, 2000              356,207      448,920       126,895                     8,942       34,358       975,322

Investments in and advances
   to unconsolidated
   affiliates at:
     September 30, 2001              94,230      219,488        33,000       61,572                                 408,290
     December 31, 2000              105,194      102,083        33,000       58,677                                 298,954



Page 17


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.

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

                                                           For Three Months Ended              For Nine Months Ended
                                                               September 30,                       September 30,
                                                      ---------------------------------   ---------------------------------
                                                            2001            2000               2001             2000
                                                      ---------------------------------   ---------------------------------
Total segment gross operating margin                         $110,849         $74,504           $314,997         $237,531
    Depreciation and amortization                             (13,072)         (9,029)           (34,894)         (25,907)
    Retained lease expense, net                                (2,660)         (2,660)            (7,980)          (7,984)
    Loss on sale of assets                                          5              27                392           (2,276)
    Selling, general and administrative                        (7,644)         (6,978)           (22,230)         (20,020)
                                                      ---------------------------------   ---------------------------------
 Consolidated operating income                                 87,478          55,864            250,285          181,344
    Interest expense                                          (12,610)         (7,486)           (35,928)         (23,330)
    Interest income from unconsolidated affiliates                               (122)                15               80
    Dividend income from unconsolidated affiliates                392           2,241              2,024            6,236
    Interest income - other                                     1,018             458              6,789            3,431
    Other expense, net                                           (275)            (71)              (806)            (496)
                                                      ---------------------------------   ---------------------------------
Consolidated income before minority interest                 $ 76,003         $50,884           $222,379         $167,265
                                                      =================================   =================================


Page 18


                        Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
                                              AND RESULTS OF OPERATIONS.

                             For the Interim Periods ended September 30, 2001 and 2000

         The following discussion and analysis should be read in conjunction with the unaudited consolidated
financial statements and notes thereto of Enterprise Products Operating L.P. (the "Company") included elsewhere
herein.

Cautionary Statements regarding Forward-Looking Information and Risk Factors

         This quarterly report on Form 10-Q 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," "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.

         Risk Factors.  An investment in the Company's securities involves a degree of risk.  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
natural gas liquid ("NGL") prices and production due to weather and other natural and economic 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, (g) the use of financial instruments to hedge commodity and interest rate risks which prove to be
economically ineffective and (h) failure to complete one or more new projects on time or within budget.

         The prices of natural gas and NGLs are subject to fluctuations in response to changes in supply, market
uncertainty and a variety of additional factors that are beyond the Company's control.   These factors include
the level of domestic oil, natural gas and NGL production and development, the availability of imported oil and
natural gas, actions taken by foreign oil and natural gas producing nations, the availability of transportation
systems with adequate capacity, the availability of competitive fuels and products, fluctuating and seasonal
demand for oil, natural gas and NGLs and conservation and the extent of governmental regulation of production and
the overall economic environment.

         The products that the Company processes, sells or transports are principally used as feedstocks in
petrochemical manufacturing and in the production of motor gasoline and as fuel for residential and commercial
heating.  A reduction in demand for the Company's products or processing or transportation services by the
petrochemical, refining or heating industries, whether because of general economic conditions, reduced demand by
consumers for the end products made with NGL products, increased competition from petroleum-based products due to
pricing differences, adverse weather conditions, governmental regulations affecting prices and production levels
of natural gas or the content of motor gasoline or other reasons, could have a negative impact on the Company's
results of operations.   A material decrease in natural gas production or crude oil refining, as a result of
depressed commodity prices or otherwise, or a decrease in imports of mixed butanes, could result in a decline in
the volumes of NGLs processed or sold by the Company, thereby reducing revenue and operating income.

         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 various uncertainties including the following key factors:
(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,


Page 19


(d) changes in the strategic direction of the Company and (e) unanticipated legal, regulatory and contractual
impediments with regards to its construction projects.

         For a further description of the risks of owning the Company's securities, see the Limited Partner's
registration documents  filed with the SEC on Form S-1/A dated July 21,1998 and the Company's Form S-3 dated
December 21, 1999 and Form S-3 dated February 23, 2001 (altogether with any amendments thereto).

Company Overview

         The Company was formed on April 9, 1998 as a Delaware limited partnership to acquire, own and operate
the NGL processing and distribution assets of Enterprise Products Company ("EPCO").   The Company conducts
substantially all of the business of its publicly-traded (NYSE, symbol "EPD") 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 is a leading North American provider of a wide range of midstream energy services to its
customers along the central and western Gulf Coast.   The Company's services include the:

o        gathering, transmission and storage of natural gas from both onshore and offshore Louisiana developments;
o        purchase and sale of natural gas in south Louisiana;
o        processing of natural gas into a merchantable and transportable form of energy that meets industry
         quality specifications by removing NGLs and impurities;
o        fractionating 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;
o        converting normal butane to isobutane through the process of isomerization;
o        producing MTBE from isobutane and methanol;
o        transporting NGL products to end users by pipeline and railcar;
o        separating high purity propylene from refinery-sourced propane/propylene mix; and
o        transporting high purity propylene to plastics manufacturers by pipeline.

Natural gas transported, processed and/or sold by the Company generally is consumed as fuel by residential,
electric and industrial centers.  NGL and petrochemical 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.

         Company Operations and Assets

         The Company's operations are concentrated in the Texas, Louisiana, and Mississippi Gulf Coast area.  A
large portion of these operations take place 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.


Page 20


         The Company's operations in Louisiana and Mississippi include varying interests in twelve natural gas
processing plants with a combined capacity of 11.6 Bcf/d and net capacity of 3.2 Bcf/d, 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 NGL and
petrochemical 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 and petrochemical pipelines.

         Beginning in January 2001, the Company owns varying equity interests in four Gulf of Mexico offshore
Louisiana natural gas pipeline systems totaling 725  miles of pipeline (with an aggregate gross throughput
capacity of 2.85 Bcf/d) and related assets.   These equity interests were purchased from EPE at a cost of
approximately $112 million.   With the completion of the Acadian Gas, LLC ("Acadian Gas") acquisition in April
2001, the Company now owns varying interests in an additional 1,042 miles of natural gas pipeline systems (with
an aggregate gross throughput capacity of over 1.1 Bcf/d) and related facilities located in south Louisiana.  For
additional information regarding these recent investments and business acquisitions, see "Recent acquisitions and
other investments" below.

         The Company's operating margins are primarily derived from services provided to its tolling customers
and from merchant activities.  In its tolling operations, the Company is paid a fee based on volumes processed,
transported, stored or handled.  The Company generally does not take title to products as part of its tolling
operations; however, in those instances where title to products does transfer to the Company, the Company
generally matches the timing and purchase price of the products with those of the sale of the products so as to
reduce or eliminate exposure to fluctuations in  commodity prices.  Examples of the Company's tolling operations
include  isomerization tolling arrangements, propylene fractionation, liquids pipeline transportation services,
fee-based marketing services and most NGL fractionation services.   In addition, the Company's newly acquired
natural gas pipeline businesses are viewed as fee-based operations.  See "Recent acquisitions and other
investments" below for a further discussion of the impact of commodity price risk on these operations.

         In its merchant activities which are primarily reported in the Processing and Octane Enhancement
segments, the Company is directly exposed to fluctuations in certain commodity prices.  In the Company's
isobutane merchant business (and to a certain extent its propylene fractionation activities), the Company takes
title to feedstock products and sells processed end products.  The Company's profitability from this type of
merchant activity is dependent upon the prices of feedstocks and end products, which may vary on a seasonal
basis.  In order to limit the exposure to commodity price fluctuations in these business areas, the company
attempts to match the timing and price of its feedstock purchases with those of the sales of end products.
Operating margins from the company's natural gas processing (and related merchant businesses) are generally
derived from the price spread earned on the sale of purity NGL products extracted from natural gas streams.  To
the extent the Company 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 operating margins are affected by the prices of NGLs and natural gas.  As part of its natural gas
processing and related merchant activities, the Company uses commodity financial instruments to reduce its
exposure to the market risks associated with changes in natural gas and NGL prices.

Recent acquisitions and other investments

         Natural gas pipelines

         General.  Since January 1, 2001, the Company has invested approximately $338 million (net of cash
acquired) in natural gas pipeline businesses.   These include an initial $226 million paid to Shell for the
purchase of Acadian Gas (an onshore Louisiana system) and a combined $112 million paid to EPE for equity
interests in four Gulf of Mexico natural gas pipelines (primarily offshore Louisiana systems).  The acquisition
of these natural gas pipeline businesses from EPE and Shell represent strategic investments for the Company.
Management believes that these assets have attractive growth attributes given the expected long-term increase in


Page 21


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 provide opportunities for enhanced services to customers as well as generating additional
fee-based cash flows.  These businesses are accounted for as part of the Company's Pipelines operating segment.

         Natural gas pipeline systems receive natural gas from producers, other pipelines or shippers through
system interconnects and redeliver the natural gas at other points.   Generally, natural gas transportation
agreements provide these systems with a fee per unit of volume (generally in MMBtus) transported.  Natural gas
pipeline businesses (such as those of Acadian Gas) may also involve gathering and purchasing natural gas from
producers and suppliers and transporting and reselling such natural gas to electric utility companies, local
distribution companies, industrial customers, and affiliates of other pipeline and gas marketing companies as
well as transporting and gathering natural gas for shippers on a fee basis.    Overall, the Company's Gulf of
Mexico systems do not take title to the natural gas that they transport; the shipper retains title and the
associated commodity price risk.   In the Company's Acadian Gas operations, it does take title to certain natural
gas streams and is exposed to commodity price risk through its natural gas inventories and certain of its
contracts.

         The results of operation for the nine months ended September 30, 2001 include six month's impact of the
Acadian Gas acquisition and nine month's impact of the Gulf of Mexico natural gas pipelines.   See Note 3 of the
Notes to Unaudited Consolidated Financial Statements for selected pro forma financial data regarding these
transactions as if they had both occurred on January 1, 2001 and 2000.

         Acadian Gas.  On April 2, 2001, the Company acquired Acadian Gas from Shell US Gas and Power LLC, an
affiliate of Shell, for approximately $226 million in cash using proceeds from the issuance of the $450 Million
Senior Notes.   The cash purchase price is subject to certain post-closing adjustments expected to be completed
during the fourth quarter of 2001.   The effective date of the transaction was April 1, 2001.

         Acadian Gas is involved in the purchase, sale, transportation and storage of natural gas in Louisiana.
Acadian Gas' assets are comprised of the 438-mile Acadian, 577-mile Cypress and 27-mile Evangeline natural gas
pipeline systems, which together have over 1.1 Bcf/d of capacity.   These natural gas pipeline systems are
wholly-owned by Acadian Gas with the exception of the Evangeline system in which Acadian Gas holds an approximate
49.5% interest. The assets acquired include a leased natural gas storage facility located in Napoleonville,
Louisiana.

         The Acadian, Cypress and Evangeline systems link supplies of natural gas from onshore developments and,
through connections with offshore pipelines, Gulf of Mexico production to local gas distribution companies,
electric generation and industrial customers, including those in the Baton Rouge-New Orleans-Mississippi River
corridor.  In addition, these systems have interconnects with 12 interstate and four intrastate pipelines and a
bi-directional interconnect with the U.S. natural gas marketplace at Henry Hub.

         Interests in four Gulf of Mexico natural gas pipeline systems.  On January 29, 2001, the Company
purchased equity interests in four Gulf of Mexico natural gas pipeline systems and related assets from EPE for
$112 million, after taking into account certain post-closing adjustments.

         The Company acquired a 50% equity interest in Starfish Pipeline Company LLC ("Starfish") which owns the
Stingray natural gas pipeline system and a related natural gas dehydration facility.    The Stingray system is a
375-mile FERC-regulated natural gas pipeline system that transports natural gas and injected condensate from
certain production areas located in the Gulf of Mexico offshore Louisiana to onshore transmission systems located
in south Louisiana.   The natural gas dehydration facility is connected to the onshore terminal of the Stingray
system in south Louisiana.

         In addition to Starfish, the Company acquired a 25.67% equity interest in Ocean Breeze Pipeline Company
LLC ("Ocean Breeze") and Neptune Pipeline Company LLC ("Neptune") as well as a 33.92% equity interest in Nemo
Gathering Company, LLC ("Nemo").   Ocean Breeze and Neptune collectively own the Manta Ray and Nautilus natural
gas gathering and transmission systems located in the Gulf of Mexico offshore Louisiana.  The Manta Ray system
comprises approximately 225 miles of unregulated pipelines with a capacity of 750 MMcf/d and related equipment,
the Nautilus system comprises approximately 101 miles of FERC-regulated pipelines with a capacity of 600 MMcf/d,
and the Nemo system comprises approximately 24 miles of pipeline with a capacity of 300 MMcf/d.


Page 22


         Affiliates of Shell own the remaining equity interests in Starfish and varying interests in Ocean
Breeze, Neptune and Nemo.   An affiliate of Marathon Oil Company owns an interest in Ocean Breeze and Neptune.
In addition, Shell is the operator of the assets held by Starfish, Ocean Breeze, Neptune and Nemo.

         These natural gas pipeline systems and related assets are strategically located to serve continental
shelf and deepwater developments in the central Gulf of Mexico.  Management believes that the equity interests
acquired from EPE complement and integrate well with those of the Acadian Gas acquisition.  These investments are
expected to benefit the Company's midstream focus by:

     o    broadening its midstream business by providing  additional services to
          customers; and by
     o    contributing to the Company's ability to obtain anticipated  increases
          in natural gas production from deepwater Gulf of Mexico development.

Management believes that these assets have a significant upside potential, since Shell and Marathon have
dedicated production from over 1,000 square miles of Gulf of Mexico offshore Louisiana natural gas leases to
these systems and only a small portion of this total has been developed to date.

         Regulatory environment of natural gas systems.  The Stingray and Nautilus natural gas pipeline systems
are regulated by the FERC under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978.  Each system
operates under separate FERC approved tariffs that establish rates, terms and conditions under which each system
provides services to its customers.  Generally, the FERC's authority extends to:

     o    transportation of natural gas, rates and charges;
     o    certification and construction of new facilities;
     o    extension or abandonment of services and facilities;
     o    maintenance of accounts and records;
     o    depreciation and amortization policies;
     o    acquisition and disposition of facilities;
     o    initiation and discontinuation of services; and
     o    various other matters.

As noted above, the Stingray and Nautilus systems have tariffs established through filings with the FERC that
have a variety of terms and conditions, each of which affect the operations of each system and their ability to
recover fees for the services they provide.   Generally, changes to these fees or terms can only be implemented
upon approval by the FERC.

         Collectively, the Acadian Gas and Gulf of Mexico pipeline systems acquired by the Company are subject to
various governmental and environmental legislation.   Each of these systems has a continuing program of
inspection designed to ensure compliance with such legislation including pollution control and pipeline safety
requirements. The Company believes that these systems are in substantial compliance with the applicable
requirements.

         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.

         Diamond-Koch Storage Assets

         On October 29, 2001, the Company announced that it had executed a letter of intent to acquire storage
facilities from affiliates of Ultramar Diamond Shamrock Corporation and Koch Industries, Inc.   The storage
facilities consist of 30 salt dome storage caverns with a permitted capacity of 77 million barrels located near

Page 23

the Company's Mont Belvieu complex.   These caverns provide storage services for mixed NGLs, ethane, propane,
butanes, natural gasoline and olefins, such as ethylene, polymer grade propylene, chemical grade propylene and
refinery grade propylene.   The completion of this transaction is subject to the execution of a definitive
agreement and regulatory approvals.   The parties anticipate the transaction to be completed by the end of 2001.

Current Business Environment

         During the third quarter of 2001, the U.S. NGL industry continued to recover from the first quarter of
2001 as a result of declining energy prices, particularly that of natural gas.   The lower energy costs have
contributed to increased volumes and profitability across  many of the Company's business operations.   The
decline in natural gas prices from the record levels of the first quarter of 2001 resulted in increased NGL
extraction rates throughout the gas processing industry.  Consequently, the Company is continuing to see an
increase in NGL volumes available for fractionation and/or transportation.

         Natural gas prices continued to decline in the third quarter of 2001 compared to the first six months of
2001.  After peaking at near $10 per MMBtu in January 2001, natural gas prices decreased to less than $3 per
MMBtu in October 2001 which is within the historical norm in terms of relative value to other forms of energy.
Industry expectations are that natural gas prices will remain within the historical norm relative to other forms
of energy for most of the upcoming winter due to the weak domestic economy and a strong supply picture.
Although the lower prices have led some  producers to scale back their gas exploration and production projects,
the industry expects that the current short-term imbalance of excess supply is temporary.

         In the third quarter of 2001, NGL prices declined along with those of other forms of energy.   The
resultant loss of value has been mitigated (or in some cases, reversed) by the Company's hedging activities.
During the fourth quarter of 2001, the Company expects that natural gas and NGL prices will be within the
historical range in terms of relative value with other forms of energy.

         The Company's recently acquired natural gas pipeline businesses have benefited from increased drilling
activities associated with expected long-term demand growth for natural gas.  The expected long-term outlook for
natural gas is positive as new gas-fired electric generation facilities commence operations and the domestic
economy rebounds.     Also, the Company's Nemo natural gas pipeline started operations in August 2001.   This
system is currently transporting approximately 50,000 MMBtu/d of natural gas from the Shell Brutus field, which
began production during the third quarter of 2001.    When fully developed in early 2002, the Shell Brutus field
is expected to produce up to 150,000 MMBtu/d of natural gas which will be transported through Nemo.    This
additional volume will flow from Nemo into the Manta Ray/Nautilus pipeline systems and ultimately be processed at
the Company's Neptune gas processing plant (at full extraction rates in 2002, the Brutus field production is
expected to increase the Company's equity NGL production by up to 10 MBPD).

         At the Company's gas processing facilities, equity NGL production volumes were 62 MBPD in the third
quarter of 2001, little changed from the second quarter of 2001 but significantly improved from the 46 MBPD of
the first quarter of 2001.   The equity NGL production rate seen in the first quarter was the result of minimal
NGL extraction rates caused by the abnormally high cost of natural gas.  As natural gas prices moderated in the
second and third quarters, NGL extraction rates at the Company's gas processing facilities and those of other
industry participants increased resulting in additional volumes throughout the NGL value chain; however, many gas
processing plants were still not operating at full extraction rates due to below average processing margins.
With the current natural gas price environment, management anticipates that the Company's natural gas processing
facilities will operate at full NGL extraction rates during the fourth quarter.   Overall, the Company expects
equity NGL production to average approximately 80 MBPD during the fourth quarter of 2001.

         During the third quarter, the Company's isomerization and related merchant businesses experienced
margins and volumes consistent with refinery demand associated with the end of the summer driving season.
Isomerization volumes are expected to remain near 80 MBPD during the fourth quarter of 2001.    Propylene
fractionation margins are expected to remain flat during the fourth quarter due to the weak economy and
additional supplies coming to the market from new third party facilities.  Once domestic economic conditions
improve, the Company expects that demand for propylene fractionation services will increase as the market absorbs
the added supplies.


Page 24


         NGL fractionation services at Mont Belvieu are competitive due to continued excess NGL fractionation
capacity at this industry hub.  With newly contracted volumes such as those from the Sea Robin gas processing
facility in Louisiana, the Company has raised the utilization rates of its Mont Belvieu NGL fractionator to near
capacity.   The BRF NGL fractionation facility, an equity investment of the Company, is projected to run at or
near full capacity during the fourth quarter and the Promix NGL fractionation facility, another equity investment
of the Company, is expected to run at 110 MBPD, both on strong demand.   Management anticipates that its Norco
NGL fractionation facility will process at rates near its capacity of 50 MBPD during the fourth quarter of 2001
and show margin improvement as in-kind fees increase with the expected rise in overall NGL pricing.

         With regards to its major liquids pipelines, the Company expects its Louisiana Pipeline System to
benefit from the seasonal rise in propane shipments that are carried on the Dixie Pipeline with the strongest
movements anticipated during the fourth quarter of 2001.   In addition, the Company expects that the projected
November 2001 completion of its Napoleonville to Sorrento pipeline (which is an expansion of its Louisiana
Pipeline System capacity) will result in increased shipments of natural gasoline to refineries along the
Mississippi River and transport of refinery grade propylene from Mississippi River refineries west to the Mont
Belvieu market.  This increase in pipeline volumes is expected to be obtained by attracting volumes that have
historically been transported by barge which is a more costly means of transportation versus by pipeline.   The
Company's Lou-Tex NGL Pipeline is expected to benefit from the addition of new customer volumes that will add
approximately  6 MBPD of throughput volume in November 2001.

         EPIK's financial performance is expected to seasonally improve during the fourth quarter of  2001.
Exports of butane and propane are expected to increase as a result of moderating domestic prices for both
products relative to foreign markets.   This situation should make these products more competitive on the world
market and EPIK should benefit from a higher utilization of the export terminal.  Activity at the Company's
Houston Ship Channel import facility is expected to be consistent with the fourth quarters of previous years.

         The Company's MTBE business is encountering the normal seasonal decline in spot MTBE prices.    MTBE
spot prices are generally stronger during the April to September period of each year which corresponds with the
summer driving season.    Management anticipates that equity earnings from its investment in BEF will be near
breakeven during the fourth quarter of 2001 as a result of this pricing environment.








Page 25



         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:

                                                                                                     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)
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)         $7.00       $28.81        $0.43        $0.55       $0.63        $0.69        $0.23
   Second quarter            $4.61       $27.88        $0.33        $0.46       $0.53        $0.63        $0.19
   Third quarter             $2.84       $26.65        $0.25        $0.41       $0.50        $0.49        $0.16

----------------------------------------------------------------------------------------------------------------
   (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 peaked at approximately $10 per MMBtu in January 2001


Results of Operation of the Company

         The Company has five reportable operating segments: Fractionation, Pipelines, Processing, Octane
Enhancement and Other.  Fractionation primarily includes NGL fractionation, butane isomerization (converting
normal butane into high purity isobutane) and polymer grade propylene fractionation services. Pipelines consists
of  liquids and natural gas pipeline systems, 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 based on 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.




Page 26



         The Company's gross operating margin by segment (in thousands of dollars) along with a reconciliation to
consolidated operating income for the three and nine month periods ended September 30, 2001 and 2000 were as
follows:

                                                           For Three Months Ended                 For Nine Months Ended
                                                               September 30,                          September 30,
                                                    -------------------------------------  -------------------------------------
                                                          2001               2000                2001               2000
                                                    -------------------------------------  -------------------------------------

Gross operating margin by segment:
     Fractionation                                           $35,189            $32,510            $ 93,660           $ 96,432
     Pipelines                                                22,415             10,292              65,234             39,119
     Processing                                               52,026             29,083             148,536             87,123
     Octane enhancement                                          909              2,190               6,311             13,002
     Other                                                       310                429               1,256              1,855
                                                    -------------------------------------  -------------------------------------
Gross operating margin total                                 110,849             74,504             314,997            237,531
     Depreciation and amortization                            13,072              9,029              34,894             25,907
     Retained lease expense, net                               2,660              2,660               7,980              7,984
     Loss (gain) on sale of assets                                (5)               (27)               (392)             2,276
     Selling, general and administrative expenses              7,716              6,978              21,621             20,020
                                                    -------------------------------------  -------------------------------------
Consolidated operating income                                $87,406            $55,864            $250,894           $181,344
                                                    =====================================  =====================================

         The Company's significant production and other volumetric data (on a net basis) for the three and nine
month periods ended September 30, 2001 and 2000 were as follows:

                                                     For the three months ended           For the nine months ended
                                                           September 30,                        September 30,
                                                 -----------------------------------  -----------------------------------
                                                       2001              2000               2001              2000
                                                 -----------------------------------  -----------------------------------
MBPD, Net
---------
Equity NGL Production                                           62               73                  57               72
NGL Fractionation                                              224              214                 198              216
Isomerization                                                   81               84                  82               77
Propylene Fractionation                                         34               34                  31               34
Octane Enhancement                                               5                6                   4                5
Major NGL and  Petrochemical Pipelines                         479              289                 452              334

MMBtu/D, Net
------------
Natural Gas Pipelines                                    1,426,463                            1,342,104


Three Months Ended September 30, 2001 compared with Three Months Ended September 30, 2000

         Revenues, Costs and Expenses and Operating Income.   The Company's revenues increased to $729.6 million
in 2001 compared to $721.9 million in 2000.    The Company's operating costs and expenses decreased to $634.5
million versus $659.0 million in 2000.   Operating income increased to $87.4 million in 2001 from $55.9 million
in 2000.  Third quarter 2001 revenues and expenses for Fractionation, Processing, Octane Enhancement and Other
decreased relative to third quarter 2000 amounts primarily due to falling NGL prices and energy cost-related fees
and expenses.  Offsetting these declines was an increase in revenues and expenses in the Pipelines segment
attributable to the acquisition of Acadian Gas and the Gulf of Mexico natural gas pipeline systems in 2001.   The
majority of the increase in operating income for 2001 is attributable to $48.2 million in income relating to the
Company's commodity hedging activities.

         Fractionation.  The Company's gross operating margin for the Fractionation segment increased to $35.2
million in 2001 from $32.5 million in 2000.  NGL fractionation margin declined $0.3 million quarter-to-quarter


Page 27


while net processing volumes increased to 224 MBPD in 2001 from 214 MBPD in 2000.   The slight decline in margin
is attributable to lower processing fees at Norco which are tied to NGL prices which were lower
quarter-to-quarter.  The increase in NGL fractionation volumes is primarily due to the receipt of Sea Robin mixed
NGL volumes at the Company's Mont Belvieu fractionation facilities via the Lou-Tex NGL pipeline.    The Company's
isomerization business posted a slight $0.1 million decrease primarily due to a decline in volumes from 84 MBPD
in 2000 to 81 MBPD in 2001.  The impact of lower isomerization volumes was offset by a decrease in energy-related
costs and other expenses.   Gross operating margin from propylene fractionation increased $2.2 million on volumes
of 34 MBPD for both periods.   The increase in propylene fractionation margin is attributable to lower energy costs
and other expenses.

         Pipelines.  The Company's gross operating margin for the Pipelines segment was $22.4 million in 2001
compared to $10.3 million in 2000.  Of the $12.1 million increase, $4.2 million is attributable to natural gas
pipelines acquired in 2001 (i.e., Acadian Gas and the Gulf of Mexico systems).  Natural gas pipeline volumes
averaged 1,426 BBtu/d on a net basis.   Margin from the recently completed Lou-Tex NGL Pipeline increased $4.2
million quarter-to-quarter on volumes of 34 MBPD.    The Lou-Tex NGL Pipeline was completed during the fourth
quarter of 2000.  Overall, net liquids throughput volumes increased to 479 MBPD in 2001 compared with 289 MBPD in
2000.  The majority of the 190 MBPD increase in liquids throughput volumes is attributable to (i) a 60 MBPD
increase on the Louisiana Pipeline System due to strong demand for services, (ii) a 78 MBPD combined increase at
the Houston Ship Channel import facility and on its related pipeline system related to seasonal butane import
activity and (iii) the 34 MBPD from the Lou-Tex NGL Pipeline mentioned previously.    The volume increases on the
Louisiana Pipeline System and the import dock and its related pipeline system contributed to a combined $2.5
million increase in margin quarter-to-quarter.

         Processing.  For the third quarter of 2001, the Processing segment generated gross operating margin of
$52.0 million compared to $29.1 million during the same period in 2000.   The Processing segment includes the
Company's natural gas processing business and related merchant activities.   The Company's equity NGL production
was 62 MBPD for the 2001 quarter versus 73 MBPD for the same quarter in 2000.   The decline in volume is related
to the 2000 period reflecting near maximized NGL recoveries supported by strong NGL economics.  The 2001 equity
NGL production rate reflects slightly less favorable extraction economics but is greatly improved relative to the
first quarter of 2001's 46 MBPD when natural gas prices (a major expense of gas processing operations) peaked at
nearly $10 per MMBtu.

         Gross operating margin for the Processing segment includes the results of the Company's commodity
hedging activities.    The 2001 period includes $48.2 million of income from commodity financial instruments
compared to $5.4 million for the 2000 period.   The Company employs various hedging strategies to mitigate the
effects of fluctuating commodity prices (primarily NGL prices) on its natural gas processing business and related
merchant activities.

         A large number of the Company's commodity financial instruments are based on the historical relationship
between natural gas prices and NGL prices.  This type of hedging strategy utilizes the forward sale of natural
gas at a fixed-price with the expected margin on the settlement of the position offsetting or mitigating changes
in the anticipated margins on NGL merchant activities and the value of the Company's equity NGL production.
During the third quarter of 2001, the Company benefited from a decline in natural gas prices relative to its
fixed positions.   The decline in natural gas prices allowed the Company to realize net cash gains on the
settlement and early closeout of certain positions of approximately $66.1 million.    The $17.9 million
difference between the realized amount and the $48.2 million in income from commodity financial instruments is
related to changes in non-cash mark-to-market amounts.   The non-cash mark-to-market income on positions open at
September 30, 2001 was $34.6 million (based on market prices at that date).

         If natural gas prices had not declined to the degree seen during the quarter, less income or a loss
on hedging activities may have resulted offset somewhat by correlative higher NGL prices which would have
increased the value of the Company's equity NGL production.  A variety of factors influence whether or not the
Company's hedging strategy is successful.  For additional information regarding the Company's commodity financial
instruments, see Item 3 "Quantitative and Qualitative Disclosures about Market Risk" on page 35.

         Octane Enhancement.  The Company's gross operating margin for Octane Enhancement decreased $1.2 million
in the third quarter of 2001 compared to 2000 levels.   MTBE production, on a net basis, was 5 MBPD for the 2001


Page 28


quarter versus 6 MBPD for the 2000 quarter.    The decline in margin is primarily due to the lower MTBE volumes
and a decrease in by-product revenues offset by lower energy-related costs quarter-to-quarter.

         Interest expense.  Interest expense for the third quarter of 2001 increased $5.1 million over the same
period in 2000.  The increase is attributable higher average debt levels in 2001 of $854.0 million compared with
$437.0 million in 2000.  The higher debt levels are associated with the issuance of the $450 Million Senior Notes
in January 2001 of which the proceeds were used to acquire Acadian Gas and interests in the Gulf of Mexico
natural gas pipeline systems.


Nine Months Ended September 30, 2001 compared with Nine Months Ended September 30, 2000

         Revenues, Costs and Expenses and Operating Income.   The Company's revenues increased to $2.5 billion in
2001 compared to $2.1 billion in 2000.   The Company's operating costs and expenses increased to $2.3 billion in
2001 from $1.9 billion in 2000.   Operating income increased to $250.9 million in 2001 from $181.3 million in
2000.  The rise in year-to-date revenues is primarily due to the addition of Acadian Gas' revenues and increased
merchant business activities.   The Acadian Gas acquisition was effective April 1, 2001.   The rise in
year-to-date expenses is attributable to expenses of Acadian Gas, higher than normal natural gas prices during
the first half of 2001 which affected energy-related operating costs at the Company's facilities offset by
significant income from the Company's commodity hedging activities.  As a result, operating income was positively
influenced by the above noted factors.

         Fractionation.   The Company's gross operating margin for the Fractionation segment decreased to $93.7
million in 2001 from $96.4 million in 2000.   NGL fractionation margin decreased $14.9 million primarily due to
lower processing volumes and higher energy-related operating costs.   NGL fractionation net volumes decreased to
198 MBPD for the first nine months of 2001 compared to 216 MBPD during the same period in 2000.   The decrease is
the result of lower NGL extraction rates at gas processing facilities in early 2001 (due to the high cost of
natural gas) versus 2000 when the industry was maximizing NGL production.   For the first nine months of 2001,
gross operating margin from isomerization services increased $11.1 million compared to 2000 primarily due to an
increase in volumes and toll processing fees.   Isomerization volumes increased to 82 MBPD during the first nine
months of 2001 versus 77 MBPD during the same period in 2000 due to increased demand for the Company's
services.   Gross operating margin from propylene fractionation decreased $0.5 million compared to the first nine
months of 2000 primarily due to higher energy costs, moderating prices and lower volumes.   Net propylene
fractionation volumes were 31 MBPD in 2001 versus 34 MBPD in 2000.

         Pipelines.   The Company's gross operating margin for the Pipelines segment was $65.2 million in 2001
compared to $39.1 million in 2000.   Of the $26.1 million increase, $11.0 million is attributable to natural gas
transportation investments acquired in 2001 (i.e., Acadian Gas and the Gulf of Mexico systems).  The Company's
Lou-Tex NGL Pipeline (completed in the fourth quarter of 2000) added $9.3 million on volumes of 26 MBPD.  In
addition, margin on the Company's Lou-Tex Propylene Pipeline for 2001 was $3.4 million higher than 2000
(primarily due to this asset being purchased in March 2000).   Demand for imported mixed NGLs (particularly
commercial butanes) resulted in a $5.1 million increase in margins for the Houston Ship Channel import facility
and related pipeline system.   The increase in commercial butane imports was related to the seasonal demand for
isobutane which occurred between February and May 2001.

         Processing.   For the first nine months of 2001, the Processing segment generated gross operating margin
of $148.5 million compared to $87.1 million during the same period in 2000.    The $61.4 million increase in
margin is attributable to the Company's commodity hedging activities and merchant business offset by lower equity
NGL production and prices and higher energy-related costs.

         As discussed earlier under the Processing segment's quarter-to-quarter variance explanation (see page
28), the Company employs various hedging strategies in an effort to mitigate the effects of fluctuating commodity
prices (primarily NGL prices) on its natural gas processing business and related merchant activities.  Gross
operating margin for the first nine months of 2001 reflects $118.5 million in income from commodity financial
instruments compared with $8.4 million for the same period in 2000.  Of the $118.5 million in hedging income
recognized during 2001, $83.9 million has been realized with the difference of $34.6 million attributable to


Page 29


non-cash mark-to-market income on positions that were open at September 30, 2001.   The September 30, 2001 $34.6
million in mark-to-market income is based on market prices at that date. The change in hedging income between the
2001 and 2000 periods more than offset the effects of the lower equity NGL volumes and prices and higher
energy-related costs.   A variety of factors  influence whether or not the Company's hedging strategy is
successful.  For additional information regarding the Company's commodity financial instruments, see Item 3
"Quantitative and Qualitative Disclosures about Market Risk" on page 35.

         Processing's merchant business benefited from strong demand for propane in the first quarter of 2001 for
heating and isobutane in the second quarter of 2001 for refining.   Equity NGL production averaged 57 MBPD during
the 2001 period versus 72 MBPD during the 2000 period.    The 2001 rate of 57 MBPD reflects the very low 46 MBPD
NGL extraction rates of the first quarter of 2001 when natural gas prices (a major expense of gas processing
operations) were at their peak.   As natural gas prices have declined since January 2001, equity NGL production
has returned to higher levels.   The 2000 equity NGL production rate reflects a period in which gas processors
were operating facilities at near full NGL extraction rates.

         Octane Enhancement.   The Company's gross operating margin for Octane Enhancement decreased $6.7 million
in the first nine months of 2001 compared with the same period in 2000.  MTBE production, on a net basis, was 4
MBPD in 2001 and 5 MBPD in 2000.  The decrease in volumes is attributable to a prolonged maintenance outage which
lasted from December 2000 until February 2001.   The decline in margin is primarily due to the lower MTBE
volumes, a decrease by-product revenues and an increase in energy-related and other expenses period-to-period.

         Interest expense.   Interest expense for the first nine months of 2001 increased $12.6 million over the
first nine months of 2000.   The increase is primarily due to additional interest expense associated with the
$450 Million Senior Notes issued in January 2001 of which the proceeds were used to acquire Acadian Gas and
interests in the Gulf of Mexico natural gas pipeline systems.

Liquidity and Capital Resources

         General.   The Company's primary cash requirements, in addition to normal operating expenses and debt
service, are for capital expenditures (both maintenance and expansion-related), business acquisitions and
distributions to its partners.   The Company expects to fund its short-term needs for such items as maintenance
capital expenditures and quarterly distributions to its 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 September 30, 2001, 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 revolving
bank credit facilities, the Company issued $450 million of public debt in January 2001 (the "$450 Million Senior
Notes") 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 used to acquire the Acadian
Gas and Gulf of Mexico natural gas pipeline, to finance the cost to construct certain NGL pipelines and related
projects and for working capital and other general partnership purposes.  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.


Page 30


         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, Baa2 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.

         Consolidated Cash Flows for the nine months ended September 30, 2001 and 2000.  Cash inflows from
operating activities were $123.4 million for the first nine months of 2001 compared to $179.0 million for the
same period in 2000.   Cash flows from operating activities primarily reflect the effects of net income,
depreciation and amortization, equity income and distributions from unconsolidated affiliates, fluctuations in
fair values of financial instruments and changes in operating accounts.  Net income increased $55.1 million for
2001 compared to 2000 primarily due to reasons mentioned previously under Results of Operation of the Company.
Depreciation and amortization increased a combined $9.3 million in 2001 over 2000 totals primarily due to
additional capital expenditures and business acquisitions.

         Equity in income of unconsolidated affiliates decreased $5.9 million in 2001 compared with 2000 levels.
The decrease is attributable to (i) lower earnings from NGL fractionation and pipeline investments in 2001
relative to 2000 primarily due to a decrease in available NGL volumes resulting from the low extraction rates in
early 2001 and (ii) a decline in BEF margins (see Octane Enhancement discussion under Results of Operation of the
Company) offset by equity earnings from the newly acquired Gulf of Mexico natural gas pipeline systems.  The
Company received $30.6 million in distributions from its equity method investments in 2001 compared to $26.0
million in 2000.   The $4.6 million increase is primarily related to distributions received from the Company's
newly acquired Gulf of Mexico natural gas pipeline systems.  Of the operating accounts, changes in 2001
receivable and payable balances have been influenced by the decline in natural gas and NGL prices since the
beginning of the year.  Overall, the net effect of changes in operating accounts from period to period is
generally the result of timing of NGL sales and purchases near the end of the period and changes in inventory
values related to pricing or volumes or a combination thereof.

         Operating cash flows also includes an adjustment for the $39.4 million in non-cash mark-to-market income
related to commodity and interest rate hedging activities.  Of this amount, $34.6 million is attributable to the
commodity financial instrument portfolio with the balance pertaining to interest rate swaps.  For a more complete
description of the Company's risk management policies and potential exposures, see  "Item 3. Quantitative and
Qualitative Disclosures about Market Risk" and Note 7 of the Notes to Unaudited Consolidated Financial Statements.

         Cash used for investing activities was $437.6 million in 2001 compared to $195.9 million in 2000.   Cash
outflows included capital expenditures of $92.6 million in 2001 versus $200.2 million in 2000.  Capital
expenditures for 2000 include $99.5 million for the purchase of the Lou-Tex Propylene Pipeline and related
assets.  In addition, capital expenditures include maintenance capital project costs of $3.8 million in 2001 and
$2.3 million in 2000.   The Company's completion of the Acadian Gas business acquisition resulted in an initial
payment to Shell of $225.7 million in April 2001, subject to certain post-closing purchase price adjustments.
The 2000 period also includes $6.5 million in cash receipts related to the Company's participation in the BEF
note, which was extinguished in May 2000 with BEF's final principal payment.  Lastly, investing cash outflows in
2001 includes $119.9 million in investments in and advances to unconsolidated affiliates compared to $2.3 million
in 2000.   The increase is due to the purchase of the Gulf of Mexico natural gas pipeline systems in January
2001.

         Cash receipts from financing activities were $309.7 million during 2001 compared to $51.7 million in
2000.  Cash flows from financing activities are primarily affected by repayments of debt, borrowings under debt
agreements and distributions to partners.   The 2001 period includes proceeds from the $450 Million Senior Notes
issued in January 2001 whereas the 2000 period includes proceeds from the $350 Million Senior Notes and $54
Million MBFC Loan and the associated repayments on various bank credit facilities.    Cash outlays for financing
activities also include $8.8 million paid by a consolidated trust to purchase Common Units of the Limited Partner
to fund a long-term incentive plan (see "Limited Partner Units acquired by Trust" below).    Distributions to
partners and the minority interest increased to $119.1 million in 2001 from $104.4 million in 2000 primarily due
to an increase in the quarterly distribution requirements of the Limited Partner.  In October 2001, the Limited


Page 31


Partner announced that it had again increased its quarterly distribution rate from $0.5875 per Common Unit to
$0.625 per Common Unit beginning with the distribution payable in November 2001.

         During the first nine months of 2001, the Company has invested $338 million in business acquisitions and
the purchase of equity interests in other companies.   These investments include the acquisition of Acadian Gas
and interests in four natural gas pipelines in the Gulf of Mexico.   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.    In addition, management believes that the Company is well positioned to continue to grow through
acquisitions that will expand its platform of assets and through internal growth.    The Company anticipates that
it will achieve its conservative annual growth objective for 2001:   investing $400 million in energy
infrastructure projects and acquisitions while allowing for the Limited Partner to increase its cash distribution
rate by at least 10% for the full year.

         The Company and its Limited Partner have adopted a cash distribution policy (at the direction and
discretion of the General Partner) that retains a significant amount of cash flow for reinvestment in the growth
of the business.  Over the last two years, the Company has reinvested approximately $323.2 million to fund
expansions and business acquisitions.  Management believes the cash distribution policy provides financial
flexibility in executing the Company's growth strategy.

         Future Capital Expenditures. The Company forecasts that $72.1 million will be spent during the remainder
of 2001 on currently approved capital projects that will be recorded as property, plant and equipment  (the
majority of which relate to various pipeline projects).  In addition, the Company estimates that its share of
currently approved capital expenditures in the projects of its unconsolidated affiliates will be approximately
$0.5 million for the remainder of  2001.

         As of September 30, 2001, the Company had $8.2 million in outstanding purchase commitments attributable
to its capital projects.   Of this amount, $7.7 million is related to the construction of assets that will be
recorded as property, plant and equipment and $0.5 million is associated with capital projects which will be
recorded as additional investments in unconsolidated affiliates.


         New environmental regulations in the state of Texas 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.  The technical practicality and economic reasonableness of these
regulations have been challenged under state law in litigation filed on January 19, 2001, against the Texas
Natural Resource Conservation Commission and its principal officials in the District Court of Travis County,
Texas,  by  a coalition of major Houston-Galveston area industries including the Company.  Until the litigation
is resolved, the precise level of technology to be employed and the cost for modifying the facilities to achieve
the required amount of reductions cannot be determined.  The litigation has been stayed by agreement of the
parties pending the outcome of expanded, cooperative scientific research to more precisely define sources and
mechanisms of air pollution in the Houston-Galveston area.  Completion of this research is anticipated in
mid-2002. Regardless of the results of the research and the outcome of the 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.  Capital funds have been budgeted  for work in 2002 that will
begin making emissions  reduction modifications on certain Mont Belvieu facilities.  The methods employed to
achieve these reductions will be compatible with whatever regulatory requirements are eventually put in place.
For additional information about this litigation, see the discussion under the topic Clean Air Act--General on
page 22 of the Company's Form 10-K for fiscal 2000.


Page 32






         Long-term Debt. Long-term debt consisted of the following at:

                                                                               September 30,       December 31,
                                                                                   2001               2000
                                                                            ---------------------------------------
Borrowings under:
     $350 Million Senior Notes, 8.25% fixed rate, due March 2005                      350,000             350,000
     $54 Million MBFC Loan, 8.70% fixed rate, due March 2010                           54,000              54,000
     $450 Million Senior Notes, 7.50% fixed rate, due February 2011                   450,000
                                                                            ---------------------------------------
            Total principal amount                                                    854,000             404,000
Unamortized balance of increase in fair value related to
     hedging a portion of fixed-rate debt (see Note 7)                                  1,833
Less unamortized discount on:
     $350 Million Senior Notes                                                           (126)               (153)
     $450 Million Senior Notes                                                           (264)
Less current maturities of long-term debt
                                                                            ---------------------------------------
            Long-term debt                                                           $855,443            $403,847
                                                                            =======================================

         The Company has the ability to borrow under the terms of its $250 Million Multi-Year Credit Facility
and $150 Million 364-Day Credit Facility.   The $150 Million 364-Day Credit Facility has an original maturity
date of November 16, 2001.   An amendment to the 364-Day Credit Facility to extend this date through November 15,
2002 was consented to by the lenders in early November 2001.   No amount was outstanding under either of these
two revolving credit facilities at September 30, 2001 or December 31, 2000.

         At September 30, 2001, the Company had a total of $75 million of standby letters of credit capacity
under its $250 Million Multi-Year Credit Facility of which $14.9 million was outstanding.

         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 used to acquire the Acadian Gas, Ocean
Breeze, Neptune, Nemo and Starfish natural gas pipeline systems for $336 million and to finance the cost to
construct certain NGL pipelines and related projects and for working capital and other general partnership
purposes.

         The $450 Million Senior Notes were issued under the indenture agreement dated March 15, 2000 which is
also applicable to the $350 Million Senior Notes and therefore are subject to similar covenants and terms.   As
with the $350 Million Senior Notes, the $450 Million Senior Notes:

     o    are subject to a make-whole redemption right;
     o    are an unsecured obligation and rank equally with existing and future
          unsecured  and  unsubordinated indebtedness and senior to any future
          subordinated indebtedness; and,
     o    are guaranteed by the Limited Partner through an unsecured and
          unsubordinated guarantee.

The issuance of the $450 Million Senior Notes was a final takedown under the December 1999 $800 million universal
registration statement; therefore, the amount of securities available under this registration statement was
reduced to zero. On February 23, 2001, the Company filed a $500 million universal shelf registration statement
(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
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 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.


Page 33


         The Company was in compliance with the restrictive covenants associated with all of its fixed-rate and
variable-rate debt instruments at September 30, 2001.

         Upon adoption of Statement of Financial Accounting Standards ("SFAS") No. 133, Accounting for Derivative
Instruments and Hedging Activities (as amended and interpreted) on January 1, 2001, the Company recorded a $2.3
million non-cash increase in the fair value of its fixed-rate debt.  SFAS No. 133 required that the Company's
interest rate swaps and their associated hedged fixed-rate debt be recorded at fair value upon adoption of the
standard.   After adoption of the standard, the interest rate swaps were dedesignated due to differences in the
estimated maturity dates of the interest rate swaps versus the fixed-rate debt.  As a result, the fair value of
the hedged fixed-rate debt will not be adjusted for future changes in fair value and the $2.3 million increase in
the fair value of the debt will be amortized to earnings over the remaining life of the fixed-rate debt to which
it applies, which approximates 10 years.  The fair value adjustment of $2.3 million is not a cash obligation of
the Company and does not alter the amount of the Company's indebtedness.    See Note 7 for additional information
concerning the Company's financial instruments.

Recently Issued Accounting Standards

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

         At present, the Company's intangible assets include the values assigned to the 20-year Shell 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 value of the Shell Processing
Agreement is being amortized over its contract term and the 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.  Based upon
initial interpretations of the new accounting standards, the Company anticipates that the Shell Processing
Agreement will continue to be amortized over its contract term; however, the excess cost attributable to Mont
Belvieu Associates will be reclassified to goodwill in accordance with the new standard and its amortization will
cease (currently, $0.5 million in amortization expense annually).  This goodwill would then be subject to
impairment testing as prescribed in SFAS No. 142.

         The Company is continuing to evaluate the complex provisions of SFAS No. 141 and SFAS No. 142 and has
not adopted such provisions in its September 30, 2001 financial statements.

         In addition to SFAS No. 141 and No. 142, the FASB also issued SFAS No. 143, "Accounting for Asset
Retirement Obligations", in June 2001.   This statement establishes accounting standards for the recognition and
measurement of a liability for an asset retirement obligation and the associated asset retirement cost.   This
statement is effective for the Company's fiscal year beginning January 1, 2003.   In August 2001, the FASB issued
SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets".  This statement addresses
financial accounting and reporting for the impairment of long-lived assets and for long-lived assets to be
disposed of.   This statement is effective for the Company's fiscal year beginning January 1, 2002.   Management
is currently studying both SFAS No. 143 and No. 144 for  their possible impact on the consolidated financial
statements when they are adopted.

Issuance of last installment of Limited Partner Special Units to Shell

         On or about June 30, 2001, Shell met certain year 2001 performance criteria for the issuance of the last
installment of 3.0 million non-distribution bearing, convertible Contingency Units of the Limited Partner
(referred to as Special Units once they are issued).  Under a contingent unit agreement with Shell executed as
part of the 1999 TNGL acquisition, the Limited Partner issued these Special Units on August 2, 2001.  The value


Page 34


of these Special Units was determined to be $117.1 million using present value techniques.    This amount
increased  the purchase price of the TNGL acquisition and the value of the Shell Processing Agreement when the
issue was recorded in August 2001.

         This amount also increased the equity position of the Limited Partner by $117.1 million with the General
Partner contributing $1.2 million to maintain its respective ownership in the Company.  The $117.1 million
increase in value of the Shell Processing Agreement will be amortized over the remaining life of the contract.
As a result, amortization expense will increase by approximately $1.6 million per quarter ($6.5 million
annually).

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, 2000, this consolidated 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.   During September 2001, the Trust
purchased an additional 201,600 Common Units at a cost of $8.8 million.   The Trust Units are considered
outstanding and will receive distributions from the Limited Partner.

         In September 2001, the Board of Directors of the General Partner approved a modification to the Limited
Partners' 1,000,000 Unit buy-back program.  This two-year program, announced in July 2000, originally allowed the
Limited Partner to repurchase and retire up to 1,000,000 of its publicly-owned Common Units.   As of December 31,
2000,  the Limited Partner had repurchased and retired 28,400 of these Common Units.   The Board of Directors
approved a modification to the plan that allows both the Limited Partner and the Trust to repurchase Common Units
under the buy-back program.   Under the terms of the modification, purchases made by the Limited Partner will
continue to be retired whereas purchases made by the Trust will remain outstanding and not be retired.

         As of September 30, 2001, 770,000 publicly-owned Common Units of the Limited Partner could be
repurchased under the buy-back program.   Purchases made by the Limited Partner will be funded by increased cash
distributions from the Company's operating cash flows and borrowings under its bank credit facilities.
Purchases made by the Trust will be funded by cash contributions from the Company arising from similar sources.

Response to September 11, 2001 Terrorist Attacks

         Following the recent terrorist attacks in the United States, the Company's management instituted a
review of security measures and practices and emergency response capabilities for all facilities and sensitive
infrastructure.  In connection with this activity, the Company has participated in security coordination efforts
with law enforcement and public safety authorities, industry mutual-aid groups and regulatory agencies.  As a
result of these steps, security measures, techniques and equipment have been enhanced as appropriate on a
location-by-location basis.  Further evaluation will be ongoing, with additional measures to be taken as specific
governmental alerts, additional information about improving security and new facts come to the Company's
attention.


Item 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

         The Company is exposed to financial market risks, including changes in commodity prices in its natural
gas and NGL businesses and in interest rates with respect to a portion of its debt obligations.  The Company may
use 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 financial instruments for
speculative (or trading) purposes.

Commodity Price Risk

         The Company's Processing and Octane Enhancement segments are directly exposed to commodity price risk
through their respective business operations. The prices of natural gas, NGLs and MTBE are subject to
fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are
beyond the Company's control.   These factors include the level of domestic oil, natural gas and NGL production


Page 35


and development, the availability of imported oil and natural gas, actions taken by foreign oil and natural gas
producing nations, the availability of transportation systems with adequate capacity, the availability of
alternative fuels and products, seasonal demand for oil, natural gas and NGLs, conservation, the extent of
governmental regulation of production and the overall economic environment.

         In order to manage this risk, the Company may enter into swaps, forwards, commodity futures, options and
other commodity financial instruments with similar characteristics that are permitted by contract or business
custom to be settled in cash or with another financial instrument.  The primary purpose of these risk management
activities is to hedge exposure to price risks associated with natural gas, NGL production and inventories, firm
commitments and certain anticipated transactions in the Company's Processing segment.  As an ancillary service,
Acadian Gas utilizes commodity financial instruments to manage the sales/purchase price of natural gas for certain
of its customers.

         The Company has adopted a commercial policy to manage its exposure to the risks generated by its gas
processing and related NGL and natural gas businesses.   The objective of this policy is to assist the Company in
achieving its profitability goals while maintaining a portfolio with an acceptable level of risk, defined as
remaining within the position limits established by the General Partner.  The Company enters into risk management
transactions to manage price risk, basis risk, physical risk, or other risks related to the energy commodities 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.

         The Company assesses the risk of its commodity financial instrument portfolio using a sensitivity
analysis model.   The sensitivity analysis performed on this portfolio measures the potential gain or loss in
earnings (i.e., the change in fair value of the portfolio) based on a hypothetical 10% movement in the underlying
quoted market prices of the commodity financial instruments outstanding at the dates noted within the table.
The sensitivity analysis model takes into account the following primary factors and assumptions:

     o    the current quoted market price of natural gas;
     o    the current quoted market price of NGLs;
     o    changes in the composition of commodities hedged (i.e., the mix
          between natural gas and related NGL hedges outstanding);
     o    fluctuations in the overall volume of commodities hedged (for both
          natural gas and related NGL hedges outstanding);
     o    market interest rates, which are used in determining the present
          value; and,
     o    a liquid market for such financial instruments.

         An increase in fair value of the commodity financial instruments (based upon the factors and assumptions
noted above) approximates the income/gain that would be recognized in earnings if all of the commodity financial
instruments were settled at the respective balance sheet dates.  Conversely, a decrease in fair value of the
commodity financial  instruments would result in the recording of a loss at the respective balance sheet date.

         The sensitivity analysis model does not include the impact that the same hypothetical price movement
would have on the hedged commodity positions to which they relate.   Therefore, the impact on the fair value of
the commodity financial instruments of a change in commodity prices would be offset by a corresponding gain or
loss on the hedged commodity positions, assuming:

     o    the commodity financial instruments are not closed out in advance of
          their expected term,
     o    the commodity financial instruments function effectively as hedges of
          the underlying risk, and
     o    as applicable, anticipated underlying transactions settle as expected.

         The Company routinely reviews its open commodity financial instruments in light of current market
conditions.   If market conditions warrant, some instruments may be closed out in advance of their contractual
settlement dates thus realizing income or loss depending on the specific exposure.   When this occurs, the
Company may enter into new commodity financial instruments to reestablish the hedge of the commodity position to
which the closed instrument relates.



Page 36


         Under the guidelines of SFAS No. 133, as amended and interpreted, a hedge is normally regarded as
effective if, among other things, at inception and throughout the life of the hedge, the Company could expect
changes in the fair value of the hedged item to be almost fully offset by the changes in the fair value of the
hedging instrument.  Currently, the Company's commodity financial instruments do not qualify as effective hedges
under the guidelines of SFAS No. 133, with the result being that changes in the fair value of these financial
instruments are recorded on the balance sheet and in earnings through mark-to-market accounting.   The use of
mark-to-market accounting for the commodity financial instruments portfolio results in a degree of  non-cash
earnings volatility that is dependent upon changes in the underlying commodity prices.  Even though the commodity
financial instruments do not qualify for hedge accounting treatment under the specific guidelines of SFAS No.
133, the Company views these financial instruments as hedges inasmuch as this was the intent when such
contracts are executed.   This characterization is consistent with the actual economic performance of the
contracts to date and the Company expects these financial instruments to continue to mitigate commodity price
risk in the future.  For additional information regarding commodity financial instruments, see Note 7 of the
Notes to Unaudited Consolidated Financial Statements.

                         Sensitivity Analysis for Commodity Financial Instruments Portfolio
                             Estimates of Fair Value ("FV") and Earnings Impact ("EI")
                         due to selected changes in quoted market prices at dates selected

                                                                             December      September     November
                                                                             31, 2000      30, 2001       9, 2001
                                                                           ------------------------------------------
                                                                                   (in millions of dollars)
                                                                           ------------------------------------------

FV assuming no change in quoted market prices,           Asset (Liability)       $(38.6)       $ 32.2           $ 13.6

FV assuming 10% increase in quoted market prices,        Asset (Liability)       $(56.3)       $ 13.0           $  1.5
EI assuming 10% increase in quoted market prices,        Income (Loss)           $(17.7)       $(19.2)          $(12.1)

FV assuming 10% decrease in quoted market prices,        Asset (Liability)       $(20.9)       $ 51.5           $ 25.7
EI assuming 10% decrease in quoted market prices,        Income (Loss)           $ 17.7        $ 19.3           $ 12.1


         The fair value of the commodity financial instruments at December 31, 2000 was estimated at $38.6
million payable.  On September 30, 2001, the fair value of the commodity financial instruments outstanding was
estimated at $32.2 million receivable.  The change in fair value between December 31, 2000 and September 30, 2001
was primarily due to to lower natural gas prices, settlement of certain open positions and a change in the
composition of commodities hedged.  On November 9, 2001, the fair value of the commodity financial instruments
was $13.6 million receivable primarily due to an increase in quoted market prices since September 30, 2001.

         Historical gains or losses resulting from these hedging activities are a component of the Company's
operating costs and expenses as reflected in its Statements of Consolidated Operations.

Interest rate risk

         Variable-rate Debt.  At September 30, 2001 and 2000, the Company had no variable rate debt outstanding
and as such had no financial instruments in place to cover any potential interest rate risk on its variable-rate
debt obligations.   Variable-rate debt obligations do expose the Company to possible increases in interest
expense and decreases in earnings if interest rates were to rise.

         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").    The objective of holding
interest rate swaps is to manage debt service costs by effectively converting a portion of the fixed-rate debt
into variable-rate debt.   An interest rate swap, in general, requires one party to pay a fixed-rate on the


Page 37


notional amount while the other party pays a floating-rate based on the notional amount.  Management believes
that it is prudent to maintain a balance between variable-rate and fixed-rate debt.

         The Company assesses interest rate cash flow risk by identifying and measuring changes in interest rate
exposure that impact future cash flows any by evaluating hedging opportunities.  The Company uses analytical
techniques to measure its exposure to fluctuations in interest rates, including cash flow sensitivity analysis to
estimate the expected impact of changes in interest rates on the Company's future cash flows.  The General
Partner oversees the strategies of the Company associated with financial risks and approves instruments that are
appropriate for the Company's requirements.

         The interest rate swaps outstanding at December 31, 2000 reflected a notional amount of $154 million of
fixed-rate debt with the fair value of swaps estimated at $2.5 million.   By September  30, 2001, the notional
amount had been reduced to $104 million due to the early termination of one of the swaps by a counterparty with
the aggregate fair value of the remaining swaps estimated at $9.5 million.   The change in fair value between
December 31, 2000 and September  30, 2001 is  related to lower interest rates and the decision by one
counterparty not to exercise its early termination right.

         In October 2001, the Company and the counterparty to the swap related to the $350 Million Senior Notes
executed the early settlement of this swap.   As a result, the Company realized $4.7 million of the $7.3 million
in non-cash mark-to-market income recognized through September 30, 2001 relating to its interest rate swaps.
Primarily due to this early termination, the fair value of the interest rate swap portfolio was $4.1 million receivable
on November 5, 2001.

         The Company's interest rate swap agreements were dedesignated as hedging instruments after the adoption
of SFAS No. 133; therefore, the interest rate swap agreements are accounted for on a mark-to-market basis.
However, these financial instruments continue to be effective in achieving the risk management activities for
which they were intended.  As a result, the change in fair value of these instruments will be reflected on the
balance sheet and in earnings (interest expense) using mark-to-market accounting.  For additional information
regarding the interest rate swaps, see Note 7 of the Notes to Unaudited Consolidated Financial Statements that
are part of this Form 10-Q quarterly report.

         Other.  At September 30, 2001 and December 31, 2000, the Company had $62.9 million and $58.4 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.

Counterparty risk

         The Company has credit risk from its extension of credit for sales of products and services, and has
credit risk with its counterparties in terms of settlement risk associated with its financial instruments.   On
all transactions where the Company is exposed to credit risk, the Company analyzes the counterparty's financial
condition prior to entering into an agreement, establishes credit limits and monitors the appropriateness of
these limits on an ongoing basis.   The counterparty to a majority of the Company's commodity financial
instruments is a major Houston, Texas-based energy company.  The credit risk to this party is somewhat mitigated
by cash or letters of credit held by the Company in an amount dependent upon the exposure with the counterparty.

Related Accounting Developments

         Due to the complexity of SFAS No. 133, the FASB is continuing to provide guidance about implementation
issues.  Since this guidance is still continuing, the initial conclusions reached by the Company regarding the
application of SFAS No. 133 upon adoption may be altered.  As a result, additional SFAS No. 133 transition
adjustments may be recorded in future periods as the Company adopts new FASB interpretations.   For additional
information regarding SFAS No. 133, see Note 10 of the Notes to Unaudited Consolidated Financial Statements.


Page 38


PART II.    OTHER INFORMATION

Item 2.  Use of Proceeds

         The following table shows the Use of Proceeds from the $450 Million Senior Notes offering completed on
January 29, 2001.   The $450 Million Senior Notes represented a takedown of the remaining shelf availability
under the Company's and the Limited Partner's December 1999 Registration Statement filed with the Securities and
Exchange Commission (File Nos. 333-93239 and 333-93239-01, effective January 14, 2000).

         The title of the registered debt securities was "7.50% Senior Notes Due 2011."   The underwriters of the
offering were Goldman, Sachs and Co., Salomon Smith Barney Inc., Banc One Capital Markets, Inc., First Union
Securities, Inc., Scotia Capital (USA) Inc. and Tokyo-Mitsubishi International plc.  The 10-year Senior Notes
have a maturity date of February 1, 2011 and bear a fixed-rate interest coupon of 7.50%.

                                                                            Amounts
                                                                         (in millions)
                                                                         --------------
Proceeds:
       Sale of $450 Million Senior Notes to public at 99.937% per Note           $450
       Less underwriting discount of 0.650% per Note                               (3)
                                                                         --------------
            Total proceeds                                                        $447
                                                                         ==============

Use of Proceeds:
       Initial payment to finance Acadian Gas acquisition                       $(226)
       To finance investment in various Gulf of Mexico
               natural gas pipelines                                             (112)
       To finance remainder of the costs to construct certain NGL
               pipelines and related projects, and for working capital
               and other general Company purposes                                (109)
                                                                         --------------
           Total uses of funds                                                  $(447)
                                                                         ==============

The initial $226 million payment to Shell for Acadian Gas was made in April 2001, subject to certain post-closing
purchase price adjustments.   Also, the Company paid EPE $112 million in January 2001 for the purchase of equity
interests in four Gulf of Mexico natural gas pipeline systems (Starfish, Ocean Breeze, Neptune and Nemo).

Item 6.   Exhibits and Reports on Form 8-K

(a)      Exhibits

*2.1     Purchase and Sale Agreement between Coral Energy, LLC and Enterprise Products Operating L.P. dated as 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).


Page 39


+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 by and 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 "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).

^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 among 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).

 *4.10   First Amendment to $250 million Multi-Year Revolving Credit Agreement dated April 19, 2001. (Exhibit
         4.10 to Form 10-Q filed May 14, 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 among 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).


Page 40


^10.4    Venture Participation Agreement among Sun Company, Inc. (R and 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 among 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 and 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 among
         Enterprise Products Company, Texaco Producing Inc., El Paso Hydrocarbons Company and 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 among 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 among Tejas Natural Gas Liquids, LLC and Shell
         Oil Company, Shell Exploration and Production Company, Shell Offshore Inc., Shell Deepwater Development
         Inc., Shell Land and Energy Company and Shell Frontier Oil and Gas Inc. dated August 1, 1999.  (Exhibit
         10.14 to Form 10-Q filed on November 15, 1999).

^10.13   Fifth Amendment to Conveyance of Gas Processing Rights dated as of April 1, 2001 among Enterprise Gas
         Processing, LLC, Shell Oil Company, Shell Exploration and Production Company, Shell Offshore, Inc., Shell
         Consolidated Energy Resources, Inc., Shell Land and Energy Company and Shell Frontier Oil and Gas, Inc.
         (Exhibit 10.13 to Form 10-Q filed on August 13, 2001).

*        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

         (b) Reports on Form 8-K

No Form 8-K reports were filed during the quarter ending September 30, 2001.


Page 41





                                                    Signatures


         Pursuant to the requirements 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.


                                               Enterprise Products Operating L.P.
                                               (A Delaware Limited Partnership)
                                               By:     Enterprise Products GP, LLC
                                                       as General Partner


                                                       /s/ Michael J. Knesek
                                                       ---------------------------------------------------------------
                                                       Vice President, Controller and
Date:   November 13, 2001                              Principal Accounting Officer

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

FORM 10-Q

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

For the quarterly period ended March 31, 2003

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

For the transition period from ________ to ________.

Commission file numbers: 1-14323
333-93239-01

ENTERPRISE PRODUCTS PARTNERS L.P.
ENTERPRISE PRODUCTS OPERATING L.P.
(Exact name of registrants as specified in their charters)

Delaware		76-0568219
Delaware		76-0568220
(State or other jurisdiction of incorporation of organization)		(I.R.S. Employer Identification No.)

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

Indicate by check mark whether the registrants: (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 whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2).

Yes [X] No [ ]

There were 167,062,202 Common Units, 21,409,868 Subordinated Units and 10,000,000 Special Units of Enterprise Products Partners L.P. outstanding at May 1, 2003. Enterprise Products Partners L.P.'s Common Units trade on the New York Stock Exchange under symbol "EPD." Enterprise Products Operating L.P. is owned 98.9899% by its parent, EPD, and 1.0101% by the General Partner. No common equity securities of Enterprise Products Operating L.P. are publicly traded.

This report constitutes a combined quarterly report on Form 10-Q for Enterprise Products Partners L.P. (the "Company")(Commission File No. 1-14323) and its 98.9899% owned subsidiary, Enterprise Products Operating L.P. (the "Operating Partnership")(Commission File No. 333-93239-01). Since the Operating Partnership owns substantially all of the Company's consolidated assets and conducts substantially all of the Company's business and operations, the information set forth herein, except for Part I, Item 1, constitutes combined information for the Company and the Operating Partnership. In accordance with Rule 3-10 of Regulation S-X, Part I, Item 1 contains separate financial statements for the Company and the Operating Partnership.

The Operating Partnership’s Form 10-Q for the first quarter of 2003 was filed originally under CIK #0001061219 on May 13, 2003. Per instructions from EDGAR filing support on August 6, 2003, the Form 10-Q for the Operating Partnership was retransmitted to the Securities and Exchange Commission EDGAR system on August 6, 2003 to the co-registrant CIK # 0001102995.

ENTERPRISE PRODUCTS PARTNERS L.P.
ENTERPRISE PRODUCTS OPERATING L.P.
TABLE OF CONTENTS

		Page No.
	PART I
Glossary

Item 1.	Financial Statements.
Item 1A.	Enterprise Products Partners L.P.	1
Item 1B.	Enterprise Products Operating L.P.	21

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operation	40

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	57

Item 4.	Controls and Procedures	58

	PART II

Item 6.	Exhibits and Reports on Form 8-K.	59

Signature Page		62
Sarbanes-Oxley Section 302 certifications		63

Glossary

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


Acadian Gas	Acadian Gas, LLC and subsidiaries, acquired from Shell in April 2001
Accum. OCI	Accumulated Other Comprehensive Income
BBtus	Billion British thermal units, a measure of heating value
BEF	Belvieu Environmental Fuels, an equity investment of EPOLP
Belle Rose	Belle Rose NGL Pipeline LLC, an equity investment of EPOLP
BPD	Barrels per day
BRF	Baton Rouge Fractionators LLC, an equity investment of EPOLP
BRPC	Baton Rouge Propylene Concentrator, LLC, an equity investment of EPOLP
CEO	Chief Executive Officer
CFO	Chief Financial Officer
CMAI	Chemical Market Associates, Inc.
Company	Enterprise Products Partners L.P. and its consolidated subsidiaries, including the Operating Partnership
CPG	Cents per gallon
Diamond-Koch	Refers to affiliates of Valero Energy Corporation and Koch Industries, Inc.
Dixie	Dixie Pipeline Company, an equity investment of EPOLP
EPCO	Enterprise Products Company, an affiliate of the Company and our ultimate parent company (including its affiliates)
EPIK	EPIK Terminalling L.P. and EPIK Gas Liquids, LLC, collectively, an equity investment of EPOLP until March 1, 2003, after which time it became 100% owned by EPOLP
EPOLP	Enterprise Products Operating L.P., the operating subsidiary of the Company (also referred to as the "Operating Partnership")
EPU	Earnings per Unit
Evangeline	Evangeline Gas Pipeline Company, L.P. and Evangeline Gas Corp., collectively, an equity investment of EPOLP
FASB	Financial Accounting Standards Board
Feedstock	A raw material required for an industrial process such as in petrochemical manufacturing
Forward sales contracts	The sale of a commodity or other product in a current period for delivery in a future period.
GAAP	Generally Accepted Accounting Principles in the United States of America
General Partner	Enterprise Products GP, LLC, the General Partner of the Company and the Operating Partnership
La Porte	La Porte Pipeline Company, L.P. and La Porte GP, LLC, collectively, an equity investment of EPOLP
LIBOR	London interbank offered rate
MBA	Mont Belvieu Associates, see "MBA acquisition"below
MBA acquisition	Refers to the acquisition of Mont Belvieu Associates' remaining interest in the Mont Belvieu NGL fractionation facility in 1999
MBFC	Mississippi Business Finance Corporation
MBPD	Thousand barrels per day
Mid-America	Mid-America Pipeline Company, LLC (we acquired an indirect 98% interest in Mid-America in July 2002)
MMBbls	Millions of barrels
MMBtu/d	Million British thermal units per day, a measure of heating value
MMBtus	Million British thermal units, a measure of heating value
Mont Belvieu	Mont Belvieu, Texas
Mont Belvieu Storage II	Refers to NGL and petrochemical storage businesses located in Mont Belvieu that were acquired from Diamond-Koch
Mont Belvieu Splitter III	See "Splitter III"
Moody's	Moody's Investors Service

Glossary (continued)


MTBE	Methyl tertiary butyl ether
Nemo	Nemo Gathering Company, LLC, an equity investment of EPOLP
Neptune	Neptune Pipeline Company LLC, an equity investment of EPOLP
NGL or NGLs	Natural gas liquid(s)
NYSE	New York Stock Exchange
OPIS	Oil Price Information Service
Operating Partnership	Enterprise Products Operating L.P. and its subsidiaries
OTC	Olefins Terminal Corporation, an equity investment of the Company
Promix	K/D/S Promix LLC, an equity investment of EPOLP
SEC	U.S. Securities and Exchange Commission
Seminole	Seminole Pipeline Company (we acquired an indirect 78.4% interest in Seminole in July 2002)
SFAS	Statement of Financial Accounting Standards issued by the FASB
Shell	Shell Oil Company, its subsidiaries and affiliates
Splitter III	Refers to the propylene fractionation facility we acquired from Diamond-Koch
S & P	Standard and Poor's Rating Services
Starfish	Starfish Pipeline Company LLC, an equity investment of EPOLP
Throughput	Refers to the physical movement of volumes through a pipeline
Toca-Western	Refers to natural gas processing and NGL fractionation assets acquired from Western Gas Resources, Inc.
Tri-States	Tri-States NGL Pipeline LLC, an equity investment of EPOLP
Venice	Refers to natural gas processing and NGL fractionation assets owned by VESCO
Unit	Refers to limited partner interest in the Company (i.e., Common, Subordinated and Special Units)
VESCO	Venice Energy Services Company, LLC, a cost method investment of EPOLP
Williams	The Williams Companies, Inc. and subsidiaries
Wilprise	Wilprise Pipeline Company, LLC, an equity investment of EPOLP

For definitions of other commonly used terms used in our industry, please refer to the "Glossary" section of our 2002 annual report on Form 10-K.

PART I. FINANCIAL STATEMENTS. Item 1A. ENTERPRISE PRODUCTS PARTNERS L.P. CONSOLIDATED BALANCE SHEETS (Dollars in thousands)

ASSETS	March 31, 2003			December 31, 2002
Current Assets
Cash and cash equivalents (includes restricted cash of $18,757 at
March 31, 2003 and $8,751 at December 31, 2002)	$	41,346		$	22,568
Accounts and notes receivable - trade, net of allowance for doubtful accounts
of $21,249 at March 31, 2003 and $21,196 at December 31, 2002		482,965			399,187
Accounts receivable - affiliates		406			228
Inventories		101,962			167,369
Prepaid and other current assets		22,432			48,216

Total current assets		649,111			637,568
Property, Plant and Equipment, Net		2,845,993			2,810,839
Investments in and Advances to Unconsolidated Affiliates		386,249			396,993
Intangible assets, net of accumulated amortization of $29,136 at
March 31, 2003 and $25,546 at December 31, 2002		274,072			277,661
Goodwill		81,547			81,547
Deferred Tax Asset		13,113			15,846
Other Assets		16,305			9,818

Total	$	4,266,390		$	4,230,272

LIABILITIES AND PARTNERS' EQUITY
Current Liabilities
Current maturities of debt	$	15,000		$	15,000
Accounts payable-trade		74,364			67,283
Accounts payable-affiliates		35,162			40,772
Accrued gas payables		575,504			489,562
Accrued expenses		19,987			35,760
Accrued interest		17,974			30,338
Other current liabilities		23,994			42,641

Total current liabilities		761,985			721,356
Long-Term Debt		1,986,636			2,231,463
Other Long-Term Liabilities		7,663			7,666
Minority Interest		71,273			68,883
Commitments and Contingencies
Partners' Equity
Common Units (156,357,266 Units outstanding at March 31, 2003
and 141,694,766 at December 31, 2002)		1,181,052			949,835
Subordinated Units (32,114,804 Units outstanding at March 31, 2003
and December 31, 2002)		111,863			116,288
Special Units (10,000,000 Units outstanding at March 31, 2003
and December 31, 2002)		143,926			143,926
Treasury Units acquired by Trust, at cost (859,200 Common Units
outstanding at March 31, 2003 and December 31, 2002)		(17,808	)		(17,808	)
General Partner		14,514			12,223
Accumulated Other Comprehensive Income (Loss)		5,286			(3,560	)

Total Partners' Equity		1,438,833			1,200,904

Total	$	4,266,390		$	4,230,272

See Notes to Unaudited Consolidated Financial Statements

ENTERPRISE PRODUCTS PARTNERS L.P. STATEMENTS OF CONSOLIDATED OPERATIONS AND COMPREHENSIVE INCOME (LOSS) (Dollars in thousands, except per Unit amounts)

	For the Three Months Ended March 31,
	2003			2002
REVENUES
Revenues from consolidated operations
Third parties	$	1,348,782		$	571,246
Related parties		132,804			90,808

Total		1,481,586			662,054

COST AND EXPENSES
Operating costs and expenses
Third parties		1,152,302			518,049
Related parties		234,402			146,503
Selling, general and administrative
Third parties		5,087			2,009
Related parties		6,384			5,953

Total		1,398,175			672,514

EQUITY IN INCOME OF UNCONSOLIDATED AFFILIATES		1,621			9,227

OPERATING INCOME (LOSS)		85,032			(1,233	)

OTHER INCOME (EXPENSE)
Interest expense		(41,911	)		(18,513	)
Interest income from related parties					30
Dividend income from unconsolidated affiliates		2,601			954
Interest income - other		200			1,334
Other, net		34			52

Other income (expense)		(39,076	)		(16,143	)

INCOME (LOSS) BEFORE PROVISION FOR INCOME
TAXES AND MINORITY INTEREST		45,956			(17,376	)
PROVISION FOR INCOME TAXES		(3,129	)

INCOME (LOSS) BEFORE MINORITY INTEREST		42,827			(17,376	)
MINORITY INTEREST		(2,322	)		173

NET INCOME (LOSS)		40,505			(17,203	)
Reclassification of change in value of financial instruments
recorded as cash flow hedges		3,560
Gain on settlement of financial instruments recorded as cash flow hedges		5,354
Amortization of gain on settlement of financial instruments to earnings		(68	)

COMPREHENSIVE INCOME (LOSS)	$	49,351		$	(17,203	)

ALLOCATION OF NET INCOME (LOSS) TO:
Limited partners	$	36,368		$	(18,449	)

General partner	$	4,137		$	1,246

BASIC EARNINGS PER UNIT
Income (loss) before minority interest	$	0.21		$	(0.13	)

Net income (loss) per Common and Subordinated unit	$	0.20		$	(0.13	)

DILUTED EARNINGS PER UNIT
Income (loss) before minority interest	$	0.20		$	(0.13	)

Net income (loss) per Common, Subordinated
and Special unit	$	0.19		$	(0.13	)

See Notes to Unaudited Consolidated Financial Statements

ENTERPRISE PRODUCTS PARTNERS L.P. STATEMENTS OF CONSOLIDATED CASH FLOWS (Dollars in thousands)

	For the Three Months Ended March 31,
	2003			2002
OPERATING ACTIVITIES
Net income (loss)	$	40,505		$	(17,203	)
Adjustments to reconcile net income (loss) to cash flows provided
by (used for) operating activities:
Depreciation and amortization in operating costs and expenses		27,657			17,238
Depreciation in selling, general and administrative costs		22			7
Amortization in interest expense		11,582			702
Equity in income of unconsolidated affiliates		(1,621	)		(9,227	)
Distributions received from unconsolidated affiliates		15,626			14,438
Operating lease expense paid by EPCO		2,251			2,281
Minority interest		2,321			(173	)
Loss on sale of assets		4			14
Deferred income tax expense		2,733
Changes in fair market value of financial instruments		(28	)		30,141
Net effect of changes in operating accounts		50,497			(48,191	)

Operating activities cash flows		151,549			(9,973	)

INVESTING ACTIVITIES
Capital expenditures		(23,835	)		(17,112	)
Proceeds from sale of assets		34			10
Business acquisitions, net of cash received		(28,783	)		(368,631	)
Investments in and advances to unconsolidated affiliates		(20,509	)		(10,752	)

Investing activities cash flows		(73,093	)		(396,485	)

FINANCING ACTIVITIES
Borrowings under debt agreements		896,210			383,000
Repayments of debt		(1,141,000	)		(20,000	)
Debt issuance costs		(6,683	)
Distributions paid to partners		(69,155	)		(47,374	)
Distributions paid to minority interests		(2,517	)		(485	)
Contributions from minority interests		2,631			62
Proceeds from issuance of Common Units		255,482
Treasury Units purchased					(2,015	)
Settlement of treasury lock financial instruments		5,354
Increase in restricted cash		(10,006	)		(8,769	)

Financing activities cash flows		(69,684	)		304,419

NET CHANGE IN CASH AND CASH EQUIVALENTS		8,772			(102,039	)
CASH AND CASH EQUIVALENTS, JANUARY 1		13,817			132,071

CASH AND CASH EQUIVALENTS, MARCH 31	$	22,589		$	30,032

See Notes to Unaudited Consolidated Financial Statements

ENTERPRISE PRODUCTS PARTNERS L.P. STATEMENTS OF CONSOLIDATED PARTNERS’ EQUITY (Dollars in thousands, see Note 9 for Unit History)

	Limited Partners
	Common Units			Subord. Units			Special Units		Treasury Units			General Partner			Accum. OCI			Total
Balance, December 31, 2002	$	949,835		$	116,288		$	143,926	$	(17,808	)	$	12,223		$	(3,560	)	$	1,200,904
Net income		30,096			6,272								4,137						40,505
Leases paid by EPCO		1,846			382								23						2,251
Cash distributions to partners		(53,652	)		(11,079	)							(4,424	)					(69,155	)
Proceeds from issuance of
Common Units		252,927											2,555						255,482
Reclassification of change in
value of treasury lock financial
instruments recorded as
cash flow hedges (see Note 11)																3,560			3,560
Cash gains on settlement of treasury
lock financial instruments
recorded as cash flow hedges (see Note 11)																5,354			5,354
Amortization of cash gains on
settlement of treasury lock
financial instruments to interest
expense in earnings (see Note 11)																(68	)		(68	)

Balance, March 31, 2003	$	1,181,052		$	111,863		$	143,926	$	(17,808	)	$	14,514		$	5,286		$	1,438,833

See Notes to Unaudited Consolidated Financial Statements

In the opinion of Enterprise Products Partners L.P., the accompanying unaudited consolidated financial statements include all adjustments consisting of normal recurring accruals necessary for a fair presentation of its consolidated financial position as of March 31, 2003 and consolidated results of operations and cash flows for the three months ended March 31, 2003 and 2002. Within these footnote disclosures of Enterprise Products Partners L.P., references to “we”, “us”, “our” or “the Company” shall mean the consolidated financial statements of Enterprise Products Partners L.P.

References to “Operating Partnership” shall mean the consolidated financial statements of our primary operating subsidiary, Enterprise Products Operating L.P., which are included elsewhere in this combined report on Form 10-Q. We own 98.9899% of the Operating Partnership and act as guarantor of certain debt obligations of the Operating Partnership. Our General Partner, Enterprise Products GP, LLC, owns the remaining 1.0101% of the Operating Partnership. Essentially all of our assets, liabilities, revenues and expenses are recorded at the Operating Partnership level in our consolidated financial statements.

Although we believe the disclosures in these financial statements are adequate to make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to the rules and regulations of the SEC. These unaudited financial statements should be read in conjunction with our annual report on Form 10-K/A (File No. 1-14323) for the year ended December 31, 2002.

The results of operations for the three months ended March 31, 2003 are not necessarily indicative of the results to be expected for the full year.

Dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars, unless otherwise indicated.

Certain abbreviated entity names and other capitalized terms are described within the glossary of this quarterly report on Form 10-Q.

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.

See Note 14 for the pro forma effects to net income and earnings per Unit as if we had used the fair-value based method of accounting for Unit options.

The following recently issued accounting standards have been adopted and implemented by us:

• SFAS No. 143, "Accounting for Asset Retirement Obligations";

• SFAS No. 146, "Accounting for Costs Associated with Exit and Disposal Activities";

• SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure"; and,

• FIN No. 45, "Guarantor's Accounting and Disclosure Requirement from Guarantees, Including Indirect Guarantees of Indebtedness of Others.”

We are currently evaluating the provisions of FIN No. 46, Consolidation of Variable Interest Entities.

SFAS No. 143. We adopted this standard as of January 1, 2003. This statement establishes accounting standards for the recognition and measurement of a liability for an asset

retirement obligation (“ARO”) and the associated asset retirement cost. Under the provisions of this standard, we reviewed our long-lived assets for ARO liabilities and identified such liabilities in several operational areas. These include ARO liabilities related to (i) easements over property not currently owned by us and (ii) statutory regulatory requirements for abandonment or retirement of certain currently operated facilities.

As a result of our analysis of the identified AROs, we were not required to recognize such potential liabilities. Our rights to the easements are renewable and only require retirement action upon nonrenewal of the easement agreements. We currently plan to renew all such easement agreements and use these properties indefinitely. Therefore, the ARO liability is not estimable for such easements. If we decide to not renew these agreements, an ARO liability would be recorded at that time. ARO liabilities related to statutory regulatory requirements for abandonment or retirement of certain currently operated facilities were also identified. We currently have no intention or legal obligation to abandon or retire such facilities. An ARO liability would be recorded if future abandonment or retirement occurred. Certain Gulf of Mexico natural gas pipelines, in which we have an equity interest, have identified ARO’s relating to regulatory requirements. There is no current intention to abandon or retire these pipelines. If these pipelines were abandoned or retired, an ARO liability would then be disclosed.

SFAS No. 146. We adopted this standard as of January 1, 2003. This statement requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to exit or disposal plan. We determined that this standard had no material impact on our financial statements.

SFAS No. 148. We adopted this standard as of December 31, 2002. This statement provides alternative methods of transition from a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 in both annual and interim financial statements. We have provided the information required by this statement under Note 14.

SFAS No. 149. On April 30, 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” This statement amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS No. 133. This statement is effective for contracts entered into or modified after June 20, 2003, for hedging relationships designated after June 30, 2003, and to certain preexisting contracts. We will adopt SFAS No. 149 on a prospective basis at its effective date on July 1, 2003. We are currently evaluating the impact that SFAS No. 149 will have on our financial statements.

FIN 45. We implemented this FASB interpretation as of December 31, 2002. This interpretation of SFAS No. 5, 57 and 107, and rescission of FASB Interpretation No. 34 elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. We have provided the information required by this interpretation under Note 8.

FIN 46. In January 2003, FIN 46, an interpretation of ARB No. 51, Consolidated Financial Statements, was issued to address perceived weaknesses in accounting for entities commonly known as special-purpose or off-balance-sheet entities, but the guidance applies to a larger population of entities. FIN 46 provides guidance for identifying the party with a controlling financial interest resulting from arrangements or financial interests rather than from voting interests. FIN 46 defines the term “variable interest entity” (or “VIE”) and is based on the premise that if a business enterprise has a controlling financial interest in a VIE, the assets, liabilities, and results of the activities of the VIE should be included in the consolidated financial statements of the business enterprise. FIN 46 applies immediately to VIEs created after January 31, 2003 and to VIEs in which an enterprise obtains an interest after that date. For variable interests in VIEs created before February 1, 2003, FIN 46 applies to public enterprises no later than the beginning of the first interim or annual period beginning after June 15, 2003. This FIN may be applied prospectively with the cumulative-effect adjustment as of the date on which it is first applied or by restating previously issued financial statements for one

or more years with the cumulative-effect adjustment as of the beginning of the first year restated. We are currently studying the provisions of FIN 46. Based upon our initial interpretation of FIN 46, we do not believe that this guidance will have a material effect on our financial statements.

During the three months ended March 31, 2003, we acquired entities owning the Port Neches Pipeline and purchased the remaining 50% ownership interest in EPIK. We also made minor adjustments to the allocation of the purchase price we paid to acquire indirect interests in the Mid-America and Seminole pipelines. Due to the immaterial nature of each, individually and in the aggregate, our discussion of each of these transactions is limited to the following:

Acquisition of Port Neches Pipeline. In March 2003, we acquired two entities owning the Port Neches Pipeline (formerly known as the Quest Pipeline) for $14.2 million. The 70-mile Port Neches Pipeline transports high-purity grade isobutane produced at our facilities in Mont Belvieu to consumers in Port Neches, Texas.

Acquisition of remaining 50% interest in EPIK. In March 2003, we purchased the remaining 50% ownership interests in EPIK for $14.4 million (which is net of cash received of $4.6 million). EPIK owns an NGL export terminal located in southeast Texas. As a result of this acquisition, EPIK became a wholly-owned subsidiary of ours (previously, it had been an unconsolidated affiliate).

Our preliminary allocation of the purchase price of each transaction is as follows:

			Port Neches Pipeline			Other
Prepaid and other current assets	$	1,188		$	44				$	1,232
Property, plant and equipment		31,585			14,203			188		45,976
Investments in and advances to unconsolidated affiliates		(17,247	)							(17,247	)
Accrued expenses		(1,102	)		(19	)				(1,121	)
Other current liabilities		(35	)		(24	)				(59	)
Minority interest								4		4

Total purchase price	$	14,389		$	14,204		$	192	$	28,785

Our inventories were as follows at the dates indicated:


Working inventory	$	101,962	$	131,769
Forward-sales inventory				35,600

Inventory	$	101,962	$	167,369

Our regular trade (or “working”) inventory is comprised of inventories of natural gas, NGLs and petrochemical products that are available for sale by our marketing activities. The forward sales inventory was comprised of segregated NGL volumes dedicated to the fulfillment of forward sales contracts.

Due to fluctuating market conditions in the midstream energy industry in which we operate, we occasionally recognize lower of average cost or market (“LCM”) adjustments when the costs of our inventories exceed their net realizable value. These non-cash adjustments are charged to operating costs and expenses in the period they are recognized. For three months ended March 31, 2003 and 2002, we recognized $10.4 million and $0.1 million, respectively, of such LCM adjustments. The majority of these write-downs were taken against NGL inventories.

Our property, plant and equipment and accumulated depreciation were as follows at the dates indicated:


Plants and pipelines	5-35	$2,901,451	$2,860,180
Underground and other storage facilities	5-35	284,214	283,114
Transportation equipment	3-35	5,223	5,118
Land		23,825	23,817
Construction in progress		68,848	49,586

Total		3,283,561	3,221,815
Less accumulated depreciation		437,568	410,976

Property, plant and equipment, net		$2,845,993	$2,810,839

Depreciation for the three-month periods ended March 31, 2003 and 2002 was $27.7 million and $17.2 million, respectively.

We own interests in a number of related businesses that are accounted for under the equity or cost methods. The investments in and advances to these unconsolidated affiliates are grouped according to the operating segment to which they relate. For a general discussion of our business segments, see Note 12. The following table shows our investments in and advances to unconsolidated affiliates at the dates indicated:


Accounted for on equity basis:
Fractionation:
BRF	32.25%	$	28,214	$	28,293
BRPC	30.00%		17,392		17,616
Promix	33.33%		41,049		41,643
La Porte	50.00%		5,619		5,737
OTC	50.00%		5,493		2,178
Pipeline:
EPIK (see Note 3)	50.00%				11,114
Wilprise	37.35%		8,508		8,566
Tri-States	33.33%		25,571		25,552
Belle Rose	41.67%		10,904		11,057
Dixie	19.88%		37,461		36,660
Starfish	50.00%		30,716		28,512
Neptune	25.67%		76,928		77,365
Nemo	33.92%		12,004		12,423
Evangeline	49.50%		2,501		2,383
Octane Enhancement:
BEF	33.33%		50,889		54,894
Accounted for on cost basis:
Processing:
VESCO	13.10%		33,000		33,000

Total		$	386,249	$	396,993

The following table shows our equity in income (loss) of unconsolidated affiliates for the periods indicated:

	Ownership		For the Three Months Ended March 31,
	Percentage		2003		2002
Fractionation:
BRF	32.25%	$	142		$	549
BRPC	30.00%		148			249
Promix	33.33%		260			1,043
La Porte	50.00%		(181	)		(92	)
OTC	50.00%		(85	)		(110	)
Pipelines:
EPIK (see Note 3)	50.00%		1,818			1,683
Wilprise	37.35%		163			147
Tri-States	33.33%		549			469
Belle Rose	41.67%		(29	)		74
Dixie	19.88%		801			717
Starfish	50.00%		1,149			812
Neptune	25.67%		10			778
Nemo	33.92%		336			(22	)
Evangeline	49.50%		(19	)		(76	)
Octane Enhancement:
BEF	33.33%		(3,441	)		3,006

Total		$	1,621		$	9,227

The following tables represent summarized income statement information for our unconsolidated affiliates accounted for under the equity method (for the periods indicated on a 100% basis). We have grouped this information by the business segment to which the entities relate.

	Summarized Income Statement Information for the Three Months Ended
	March 31, 2003									March 31, 2002
	Revenues		Operating Inc (Loss)			Net Inc (Loss)			Revenues		Operating Income		Net Income
Pipelines	$	91,974	$	20,927		$	14,661		$	67,847	$	18,988	$	14,581
Fractionation		18,114		1,524			1,505			18,040		5,352		5,372
Octane Enhancement		45,651		(10,356	)		(10,322	)		47,929		8,978		9,019

Our initial investment in Promix, La Porte, Dixie, Neptune and Nemo exceeded our share of the historical cost of the underlying net assets of such entities (the “excess cost”). The excess cost of these investments is reflected in our investments in and advances to unconsolidated affiliates for these entities. That portion of excess cost attributable to the tangible plant and/or pipeline assets of each entity is amortized against equity earnings from these entities in a manner similar to depreciation. That portion of excess cost attributable to goodwill is subject to periodic impairment testing and is not amortized.

The following table summarizes our excess cost information at March 31, 2003 and December 31, 2002 by the business segment to which the unconsolidated affiliates relate:

		Original Excess Cost attributable to		Unamortized balance at
	Amort. Periods	Tangible assets	Goodwill	March 31, 2003	December 31, 2002
Fractionation	20-35 years	8,828		7,319	7,429
Pipelines	35 years (1)	41,943	9,246	47,338	47,637

(1) Goodwill is not amortized; however, it is subject to periodic impairment testing.

For the three months ended March 31, 2003 and 2002, we recorded $0.4 million and $0.5 million, respectively, of excess cost amortization which is reflected in our equity in income from unconsolidated affiliates.

Purchase of remaining 50% interest in EPIK

As discussed in Note 3, we purchased the remaining 50% ownership interests in EPIK in March 2003. As a result of this acquisition, EPIK became a wholly-owned subsidiary of ours. We recorded $1.8 million of equity income from EPIK for the two months that it was an unconsolidated subsidiary during the first quarter of 2003.

The following table summarizes our intangible assets at March 31, 2003 and December 31, 2002:

			At March 31, 2003
	Gross Value		Accum. Amort.			Carrying Value		Accum. Amort.			Carrying Value
Shell natural gas processing agreement	$	206,216	$	(25,777	)	$	180,439	$	(23,015	)	$	183,201
Mont Belvieu Storage II contracts		8,127		(290	)		7,837		(232	)		7,895
Mont Belvieu Splitter III contracts		53,000		(1,767	)		51,233		(1,388	)		51,612
Toca-Western natural gas processing contracts		11,187		(466	)		10,721		(326	)		10,861
Toca-Western NGL fractionation contracts		20,042		(836	)		19,206		(585	)		19,457
Venice contracts (a)		4,636					4,636					4,635

Total	$	303,208	$	(29,136	)	$	274,072	$	(25,546	)	$	277,661



(a) Amortization scheduled to begin when contracted-volumes begin to be processed in in the late 2003

The following table shows amortization expense associated with our intangible assets for the three months ended March 31, 2003 and 2002:

		For the Three Months Ended March 31,
		2003		2002
Shell natural gas processing agreement	$	2,762	$	2,761
Mont Belvieu Storage II contracts		58		60
Mont Belvieu Splitter III contracts		379		252
Toca-Western natural gas processing contracts		140
Toca-Western NGL fractionation contracts		250

Total	$	3,589	$	3,073

Our goodwill is attributable to the excess of the purchase price over the fair value of assets acquired and is comprised of the following (at March 31, 2003 and December 31, 2002):

Our goodwill amounts are classified as part of the Fractionation segment since they are related to assets recorded within this operating segment.

Our debt obligations consisted of the following at the dates indicated:

	March 31, 2003			December 31, 2002
Borrowings under:
364-Day Term Loan, variable rate, due July 2003				$	1,022,000
364-Day Revolving Credit facility, variable rate,
due November 2004	$	32,000			99,000
Multi-Year Revolving Credit facility, variable rate,
due November 2005		225,000			225,000
Senior Notes A, 8.25% fixed rate, due March 2005		350,000			350,000
Seminole Notes, 6.67% fixed rate, $15 million due
each December, 2002 through 2005		45,000			45,000
MBFC Loan, 8.70% fixed rate, due March 2010		54,000			54,000
Senior Notes B, 7.50% fixed rate, due February 2011		450,000			450,000
Senior Notes C, 6.375% fixed rate, due February 2013		350,000
Senior Notes D, 6.875% fixed rate, due March 2033		500,000

Total principal amount		2,006,000			2,245,000
Unamortized balance of increase in fair value related to
hedging a portion of fixed-rate debt		1,712			1,774
Less unamortized discount on:
Senior Notes A		(71	)		(81	)
Senior Notes B		(222	)		(230	)
Senior Notes D		(5,783	)
Less current maturities of debt		(15,000	)		(15,000	)

Long-term debt	$	1,986,636		$	2,231,463

Letters of credit. At March 31, 2003 and December 31, 2002, we had $75 million of standby letter of credit capacity under our Multi-Year Revolving Credit facility. We had $25.7 million of letters of credit outstanding under this facility at March 31, 2003 and $2.4 million outstanding at December 31, 2002.

Parent-Subsidiary guarantor relationships. We act as guarantor of certain debt obligations of our subsidiaries, including all of our Operating Partnership’s consolidated debt obligations, with the exception of the Seminole Notes. The Seminole Notes are unsecured obligations of Seminole Pipeline Company (of which we own an effective 78.4% of its ownership interests). If the Operating Partnership were to default on any guaranteed debt obligation, we would be responsible for full payment of that obligation.

New debt obligations issued during first quarter of 2003

During the first quarter of 2003, we completed the issuance of $850 million of private placement debt (Senior Notes C and D). Senior Notes C and D are unsecured obligations of our Operating Partnership and rank equally with its existing and future unsecured and unsubordinated indebtedness and senior to any future subordinated indebtedness. We guarantee both Senior Notes C and D for our subsidiary through an unsecured and unsubordinated guarantee that is non-recourse to the General Partner. These notes were issued under an indenture containing certain covenants and are subject to a make-whole redemption right. These covenants restrict our ability, with certain exceptions, to incur debt secured by liens and engage in sale and leaseback transactions.

Senior Notes C. In January 2003, we issued $350 million in principal amount of 6.375% fixed-rate Senior Notes C due February 1, 2013 (“Senior Notes C”), from which we received net proceeds before offering expenses of approximately $347.7 million. These notes were sold at face value with no discount or premium. We used the proceeds from this offering to repay a portion of the indebtedness outstanding under the 364-Day Term Loan that we incurred to finance the Mid-America and Seminole acquisitions. In April 2003, we initiated an offer to exchange the private placement Senior Notes C for publicly-registered Senior Notes C.

Senior Notes D. In February 2003, we issued $500 million in principal amount of 6.875% fixed-rate Senior Notes due March 1, 2033 (“Senior Notes D”), from which we received net proceeds before offering expenses of approximately $489.8 million. These notes were sold at a discount of 98.842% of their face amount. We used $421.4 million from this offering to repay the remaining principal balance outstanding under the 364-Day Term Loan. In addition, we applied $60.0 million of the proceeds to reduce the balance outstanding under the 364-Day Revolving Credit facility. The remaining proceeds were used for working capital purposes.

Repayment of 364-Day Term Loan

Our Operating Partnership entered into a $1.2 billion senior unsecured 364-day term loan to initially fund the acquisition of indirect interests in Mid-America and Seminole in July 2002. We used $178.5 million of the $182.5 million in proceeds from our October 2002 equity offering to partially repay this loan. We used $252.8 million of the $258.2 million in proceeds from the January 2003 equity offering (see Note 9), $347.0 million of the $347.7 million in proceeds from our issuance of Senior Notes C and $421.4 million in proceeds from our issuance of Senior Notes D to completely repay the 364-Day Term Loan by February 2003.

Covenants

We were in compliance with the various covenants of our debt agreements at March 31, 2003 and December 31, 2002.

Information regarding variable interest rates paid

The following table shows the range of interest rates paid and weighted-average interest rate paid on our variable-rate debt obligations for the three months ended March 31, 2003:

	Range of interest rates paid	Weighted- average interest rate paid
364-Day Term Loan (a)	2.59% - 2.88%	2.85%
364-Day Revolving Credit facility	2.47% - 4.25%	2.52%
Multi-Year Revolving Credit facility	1.92% - 2.00%	1.97%



(a) This facility was repaid in February 2003

Our Common Units, Subordinated Units and convertible Special Units represent limited partner interests in the Company. We are managed by the General Partner. The rights available to our partners are described in our Third Amended and Restated Agreement of Limited Partnership (together with any amendments thereto). Our Common Units trade on the New York Stock Exchange under the symbol “EPD.”

We allocate earnings and related amounts to Common and Subordinated Unitholders and the General Partner in accordance with our partnership agreement. These classes of our partnership interests are also entitled to receive cash distributions. For financial accounting and tax purposes, the Special Units are not allocated any portion of net income; however, for tax purposes, the Special Units are allocated a certain amount of depreciation until their conversion into Common Units.

In January 2003, we completed a public offering of 14,662,500 Common Units (including 1,912,500 Common Units sold pursuant to the underwriters’ over-allotment option) from which we received net proceeds before offering expenses of approximately $258.2 million, including our General Partner’s $5.2 million in capital contributions. We used $252.8 million of the proceeds from this offering to repay a portion of the indebtedness outstanding under the 364-Day Term Loan. The remaining balance of proceeds was used for working capital purposes and offering expenses.

Our partnership agreement stipulates that the Subordinated Units may undergo an early conversion to Common Units if certain criteria are satisfied. As a result of meeting the necessary criteria, 10,704,936 of EPCO’s Subordinated Units converted to Common Units on May 1, 2003. The remaining 21,409,868 Subordinated Units will convert to Common Units on August 1, 2003 if the remaining criteria are met.

The following table details the Unit activity within each class of our limited partner interests during the three months ended March 31, 2003 and the outstanding balance of each at March 31, 2003:

	Limited Partners
	Common Units	Subordinated Units	Special Units	Treasury Units
Balance, December 31, 2002	141,694,766	32,114,804	10,000,000	859,200
Common Units issued in January 2003	14,662,500

Balance, March 31, 2003	156,357,266	32,114,804	10,000,000	859,200

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

	For the Three Months Ended March 31,
	2003			2002
(Increase) decrease in:
Accounts and notes receivable	$	(83,955	)	$	978
Inventories		76,079			(31,748	)
Prepaid and other current assets		15,238			(2,494	)
Other assets		(503	)		(3,186	)
Increase (decrease) in:
Accounts payable		1,471			(9,559	)
Accrued gas payable		85,942			31,515
Accrued expenses		(16,894	)		(6,588	)
Accrued interest		(12,364	)		(16,137	)
Other current liabilities		(14,517	)		(10,892	)
Other liabilities					(80	)

Net effect of changes in operating accounts	$	50,497		$	(48,191	)

During the three months ended March 31, 2003, we completed two small business acquisitions and made minor adjustments to the purchase price allocation of the Mid-America and Seminole acquisitions. These acquisitions and adjustments affected various balance sheet accounts (see Note 3). The 2002 period reflects our acquisition of Diamond-Koch’s Mont Belvieu NGL and petrochemical storage business in January 2002 and their adjacent propylene fractionation business (Splitter III) in February 2002.

We record certain financial instruments relating to commodity positions and interest rate hedging activities at their respective fair values using mark-to-market accounting. For the three months ended March 31, 2002, we recognized a net $30.1 million in non-cash mark-to-market decreases in the fair value of these instruments, primarily in our commodity financial instruments portfolio. We had a limited number of such positions outstanding during the first quarter of 2003 and the non-cash change in fair value of these instruments was an increase of $28 thousand.

Cash and cash equivalents (as shown on our Statements of Consolidated Cash Flows) excludes restricted cash amounts held by a brokerage firm as margin deposits associated with our financial instruments portfolio and for our physical purchase transactions made on the NYMEX exchange. The restricted cash balance at March 31, 2003 and December 31, 2002 was $18.8 million and $8.8 million, respectively.

We are exposed to financial market risks, including changes in commodity prices and interest rates. We may use financial instruments (i.e., futures, forwards, swaps, options, and other financial instruments with similar characteristics) to mitigate the risks of certain identifiable and anticipated transactions, primarily within our Processing segment. In general, the types of risks we attempt to hedge are those relating to the variability of future earnings and cash flows caused by changes in commodity prices and interest rates. As a matter of policy, we do not use financial instruments for speculative (or trading) purposes.

Commodity hedging financial instruments

unexpected rapid increase in natural gas prices whereby the loss in value of our fixed-price natural gas financial instruments was not offset by increased gas processing margins. We exited the strategy underlying this loss in 2002.

During the first three months of 2003, we held a limited number of commodity financial instruments from which we recorded a loss of $0.9 million ($0.1 million was attributable to the Processing segment and the remainder to the Pipelines segment). The fair value of open positions at March 31, 2003 was a receivable of approximately $2 thousand.

Interest rate hedging financial instruments

During the fourth quarter of 2002, we entered into seven treasury lock transactions. Each treasury lock transaction carried a maturity date of either January 31, 2003 or April 15, 2003. The purpose of these transactions was to hedge the underlying U.S. treasury interest rate associated with our anticipated issuance of debt in early 2003 to refinance the Mid-America and Seminole acquisitions. The notional amounts of these transactions totaled $550 million, with a total treasury lock rate of approximately 4%.

Our treasury lock transactions are accounted for as cash flow hedges under SFAS No. 133. The fair value of these instruments at December 31, 2002 was a current liability of $3.8 million offset by a current asset of $0.2 million. The net $3.6 million non-cash mark-to-market liability was recorded as a component of comprehensive income on that date, with no impact to current earnings.

We settled all of the treasury locks by early February 2003 in connection with our issuance of Senior Notes C and D (see Note 8). The settlement of these instruments resulted in our receipt of $5.4 million of cash. This amount was recorded as a gain in other comprehensive income during the first quarter of 2003 and represents the effective portion of the treasury locks.

Of the $5.4 million recorded in other comprehensive income during the first quarter of 2003, $4.0 million is attributable to our issuance of Senior Notes C and is being amortized to earnings as a reduction in interest expense over the 10-year term of this debt. The remaining $1.4 million is attributable to our issuance of Senior Notes D and is being amortized to earnings as a reduction in interest expense over the 10-year term of the anticipated transaction as required by SFAS No. 133. The estimated amount to be reclassified from accumulated other comprehensive income to earnings during 2003 is $0.4 million. With the settlement of the treasury locks, the $3.6 million non-cash mark-to-market liability recorded at December 31, 2002 was reclassified out of accumulated other comprehensive income in Partners’ Equity to offset the current asset and liability we recorded at December 31, 2002 with no impact to earnings.

We have five reportable operating segments: Pipelines, Fractionation, Processing, Octane Enhancement and Other. The reportable segments are generally organized according to the type of services rendered (or process employed) and products produced and/or sold, as applicable. The segments are regularly evaluated by the Chief Executive Officer of the General Partner. Pipelines consists of NGL, petrochemical and natural gas pipeline systems, storage and import/export terminal services. Fractionation primarily includes NGL fractionation, isomerization, and polymer-grade and chemical-grade propylene fractionation services. Processing includes the natural gas processing business and its related NGL marketing activities. Octane Enhancement represents our equity interest in BEF, a facility that produces motor gasoline additives to enhance octane (currently producing MTBE). The Other operating segment consists of fee-based marketing services and various operational support activities.

which the partnership does not have the payment obligation and gains and losses on the sale of assets) from segment revenues, with both segment totals before elimination of intercompany transactions. Intercompany accounts and transactions are eliminated in consolidation in accordance with GAAP. Segment gross operating margin is also exclusive of other income and expense transactions, provision for income taxes, minority interest and extraordinary charges. We have provided a reconciliation of total gross operating margin (a non-GAAP performance measure) to operating income.

The following table shows our measurement of total segment gross operating margin for the periods indicated:

	For the Three Months Ended March 31,
	2003			2002
Revenues (a)	$	1,481,586		$	662,054
Less operating costs and expenses (a)		(1,386,704	)		(664,552	)
Add equity in income of unconsolidated affiliates (b)		1,621			9,227
Subtotal		96,503			6,729
Add: Depreciation and amortization in operating costs and expenses (c)		27,657			17,238
Retained lease expense, net in operating expenses allocable to us (d)		2,251			2,281
Retained lease expense, net in operating expense allocable to
our General Partner's minority interest in us(e)		23			24
Loss on sale of assets in operating costs and expenses (c)		4			14
Total segment gross operating margin	$	126,438		$	26,286

a) These amounts are comprised of both third party and related party totals as shown on our Statements of Consolidated Operations and Comprehensive Income.
(b) This amount is taken directly from our Statements of Consolidated Operations and Comprehensive Income.
(c) This amount is taken directly from the operating activities section of our Statements of Consolidated Cash Flows.
(d) This non-cash amount represents our share of the value of the operating leases contributed by EPCO to the Operating Partnership for which EPCO has retained the cash payment obligation (the "retained leases"). This amount is taken from the operating activities section ("Operating lease expense paid by EPCO" line item) of our Statements of Consolidated Cash Flows.
(e) This non-cash amount represents the minority interest's share of the value of the retained leases. This amount is a component of "Contributions from minority interests" as shown in the financing activities section of our Statements of Consolidated Cash Flows

The following table reconciles GAAP operating income as shown in our Statements of Consolidated Operations and Comprehensive Income to total segment gross operating margin (a non-GAAP financial measure):

	For the Three Months Ended March 31,
	2003		2002
Operating income (loss)	$	85,032	$	(1,233	)
Adjustments to reconcile operating income (loss)
to total segment gross operating margin:
Depreciation and amortization in operating costs and expenses		27,657		17,238
Operating lease expenses for which EPCO has retained the cash
payment obligation, net in operating costs and expenses		2,274		2,305
Loss on sale of assets in operating costs and expenses		4		14
Selling, general and administrative costs		11,471		7,962

Total segment gross operating margin	$	126,438	$	26,286

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

	Operating Segments
	Fractionation	Pipelines	Processing		Octane Enhancement		Other		Adjs. and Elims.		Consol. Totals
Revenues from third parties:
Three months ended March 31, 2003	$204,490	$ 201,893	$ 941,686				$ 713				$1,348,782
Three months ended March 31, 2002	103,799	75,844	391,131				472				571,246

Revenues from related parties:
Three months ended March 31, 2003	623	40,705	91,476								132,804
Three months ended March 31, 2002	5,623	23,237	61,903				45				90,808

Intersegment and intrasegment revenues:
Three months ended March 31, 2003	84,672	35,724	187,241				101		$(307,738	)
Three months ended March 31, 2002	33,397	24,510	126,260				100		(184,267	)

Total revenues:
Three months ended March 31, 2003	289,785	278,322	1,220,403				814		(307,738	)	1,481,586
Three months ended March 31, 2002	142,819	123,591	579,294				617		(184,267	)	662,054

Equity income in unconsolidated affiliates:
Three months ended March 31, 2003	284	4,778			$(3,441	)					1,621
Three months ended March 31, 2002	1,639	4,582			3,006						9,227

Gross operating margin by individual business segment and in total:
Three months ended March 31, 2003	29,047	71,932	29,956		(3,441	)	(1,056	)			126,438
Three months ended March 31, 2002	24,377	32,668	(33,376	)	3,006		(389	)			26,286

Segment assets:
At March 31, 2003	441,213	2,154,659	164,374				16,899		68,848		2,845,993
At December 31, 2002	444,016	2,166,524	134,237				16,825		49,237		2,810,839

Investments in and advances to unconsolidated affiliates:
At March 31, 2003	97,767	204,593	33,000		50,889						386,249
At December 31, 2002	95,467	213,632	33,000		54,894						396,993

Intangible Assets:
At March 31, 2003	70,439	7,837	195,796								274,072
At December 31, 2002	71,069	7,895	198,697								277,661

Goodwill:
At March 31, 2003 and
December 31, 2002	81,547										81,547

Our revenues are derived from a wide customer base. All consolidated revenues during the first quarter of 2003 and first quarter of 2002 were earned in the United States. Total consolidated revenues for the three months ended March 31, 2003 increased $819.5 million over those recorded during the same period in 2002. The majority of this increase is attributable to higher NGL prices, which (on a weighted-average basis for industry index prices) were 63 CPG during the first quarter of 2003 compared to 33 CPG during the first quarter of 2002. The higher NGL prices resulted in a significant increase in Processing segment revenues (particularly those of its NGL marketing activities component).

Also, higher natural gas prices during the first quarter of 2003 when compared to the first quarter of 2002 resulted in a substantial increase in Pipeline segment revenues from our Acadian Gas subsidiary. As part of its normal operations, Acadian Gas purchases natural gas from producers and suppliers and resells such natural gas to customers such as electric utility companies. The average index price for natural gas was $6.58 per MMBtu during the first quarter of 2003 versus $2.34 per MMBtu during the first quarter of 2002.

In addition to the effect of higher NGL and natural gas prices, consolidated revenues also increased as a result of acquisitions. Our Mid-America and Seminole pipeline systems contributed $82.5 million in revenues during the first three months of 2003.

Total segment gross operating margin was $126.4 million for the first quarter of 2003 compared to $26.3 million for the first quarter of 2002. The primary reasons for the increase are (i) the 2003 period includes $47.5 million of gross operating margin from Mid-America and Seminole (we acquired these operations in July 2002) and (ii) the 2002 period included $45.1 million in commodity hedging losses. Mid-America and Seminole’s gross operating margin is classified under our Pipelines segment while commodity hedging results are primarily a function of our Processing segment activities.

Provision for income taxes is primarily applicable to the tax obligation of a consolidated subsidiary, Seminole Pipeline Company, which is a corporation and subject to income taxes. Seminole Pipeline Company became a consolidated subsidiary on August 1, 2002. The following is a summary of our provision for income taxes for the three months ended March 31, 2003:

Current:
Federal tax benefit	$	349
State tax benefit		47

		396

Deferred:
Federal		2,409
State		324

		2,733

Provision for income taxes	$	3,129

The following is a reconciliation of our provision for income taxes at the federal statutory rate to our recorded provision for income taxes:

Significant components of deferred income tax assets and liabilities at March 31, 2003 are as follows:


Deferred tax assets:
Property, plant and equipment	$	13,113
Deferred tax liabilities:
Other		(619	)

Net deferred tax assets	$	12,494

Based upon the periods in which taxable temporary differences are anticipated to reverse, we believe it is more likely than not that the Company will realize the benefits of these deductible differences. Accordingly, we believe that no valuation allowance is required for the deferred tax assets. However, the amount of the deferred tax asset considered realizable could be adjusted in the future if estimates of reversing taxable temporary differences are revised.

During 1998, EPCO adopted its 1998 Long-Term Incentive Plan (the “1998 Plan”). Under the 1998 Plan, non-qualified incentive options to purchase a fixed number of our Common Units (the “Units”) may be granted to EPCO’s key employees who perform management, administrative or operational functions for us. The exercise price per Unit, vesting and expiration terms, and rights to receive distributions on Units granted are determined by EPCO for each grant. EPCO funds the purchase of the Units under the 1998 Plan at fair value in the open market. In general, our responsibility for reimbursing EPCO for the expense it incurs when these options are exercised is as follows:

•

We pay EPCO for the costs attributable to equity-based awards granted to operations personnel it employs on our behalf.

•

We pay EPCO for the costs attributable to equity-based awards granted to administrative and management personnel it hires in response to our expansion and business activities.

•

We pay EPCO for our share of the costs attributable to equity-based awards granted to certain of its employees in administrative and management positions that were active at the time of our initial public offering in July 1998 who manage our business and affairs. These costs are reimbursed through the administrative service fees we pay EPCO. EPCO is responsible for the actual costs of such awards when these options are exercised.

We account for our share of the cost of these awards using the intrinsic value-based method in accordance with APB No. 25, “Accounting for Stock Issued to Employees.” The exercise price of each option granted is equivalent to the market price of the Unit at the date of grant. Accordingly, no compensation expense related to Unit option grants is recognized in the Statements of Consolidated Operations and Comprehensive Income until the grants are exercised by the employee.

Accounting principles require us to illustrate the pro forma effect on our net income (loss) and earnings per Unit as if the fair value-based method of accounting, based on SFAS No. 123, “Accounting for Stock Based Compensation,” had been applied to the 1998 Plan. The following table shows these pro forma effects for the periods indicated:

	For the Three Months Ended March 31,
	2003			2002
Net income (loss):
As reported	$	40,505		$	(17,203	)
Additional Unit option-based compensation
expense estimated using the
fair value-based method		(171	)		(273	)

Pro forma	$	40,334		$	(17,476	)

Basic earnings per Unit:
As reported	$	0.20		$	(0.13	)
Pro forma	$	0.19		$	(0.13	)
Diluted earnings per Unit:
As reported	$	0.19		$	(0.13	)
Pro forma	$	0.18		$	(0.13	)

Basic earnings per Unit is computed by dividing net income available to limited partner interests by the weighted-average number of Common and Subordinated Units outstanding during the period. In general, diluted earnings per Unit is computed by dividing net income available to limited partner interests by the weighted-average number of Common,

Subordinated and Special Units outstanding during the period. In a period of net operating losses, the Special Units are excluded from the calculation of diluted earnings per Unit due to their antidilutive effect (as occurred for the first quarter of 2002). Treasury Units are not considered to be outstanding Units; therefore, they are excluded from the computation of both basic and diluted earnings per Unit. The amount of Common Units outstanding in the following table does not include Treasury Units.

The following table reconciles the number of Units used in the calculation of basic earnings per Unit and diluted earnings per Unit for the three months ended March 31, 2003 and 2002:

	For the Three Months Ended March 31,
	2003			2002
Income (loss) before minority interest	$	42,827		$	(17,376	)
General partner interest		(4,137	)		(1,246	)

Income (loss) before minority interest		38,690			(18,622	)
available to Limited Partners
Minority interest		(2,322	)		173

Net income (loss) available to Limited Partners	$	36,368		$	(18,449	)

BASIC EARNINGS PER UNIT
Numerator
Income(loss) before minority interest
available to Limited Partners	$	38,690		$	(18,622	)

Net income(loss)available
to Limited Partners	$	36,368		$	(18,449	)

Denominator
Common Units outstanding		154,076			102,706
Subordinated Units outstanding		32,115			42,820

Total		186,191			145,526

Basic Earnings per Unit
Income(loss) before minority interest
available to Limited Partners	$	0.21		$	(0.13	)

Net income(loss)available
to Limited Partners	$	0.20		$	(0.13	)

DILUTED EARNINGS PER UNIT
Numerator
Income(loss) before minority interest
available to Limited Partners	$	38,690		$	(18,622	)

Net income(loss)available
to Limited Partners	$	36,368		$	(18,449	)

Denominator
Common Units outstanding		154,076			102,706
Subordinated Units outstanding		32,115			42,820
Special Units outstanding		10,000			n/a

Total		196,191			145,526

Diluted Earnings per Unit
Income(loss) before minority interest
available to Limited Partners	$	0.20		$	(0.13	)

Net income(loss)available
to Limited Partners	$	0.19		$	(0.13	)

PART I. FINANCIAL STATEMENTS. Item 1B. ENTERPRISE PRODUCTS OPERATING L.P. CONSOLIDATED BALANCE SHEETS (Dollars in thousands)

ASSETS	March 31, 2003			December 31, 2002
Current Assets
Cash and cash equivalents (includes restricted cash of $18,757 at
March 31, 2003 and $8,751 at December 31, 2002)	$	36,783		$	20,795
Accounts and notes receivable - trade, net of allowance for doubtful accounts of $21,249 at March 31, 2003 and $21,196 at December 31, 2002		482,965			399,187
Accounts receivable-affiliates		5,594			3,369
Inventories		101,962			167,369
Prepaid and other current assets		22,301			48,137

Total current assets		649,605			638,857
Property, Plant and Equipment, Net		2,845,993			2,810,839
Investments in and Advances to Unconsolidated Affiliates		386,249			396,993
Intangible assets, net of accumulated amortization of $29,136 at
March 31, 2003 and $25,546 at December 31, 2002		274,072			277,661
Goodwill		81,547			81,547
Deferred Tax Asset		13,113			15,846
Other Assets		16,305			9,818

Total	$	4,266,884		$	4,231,561

LIABILITIES AND PARTNERS' EQUITY
Current Liabilities
Current maturities of debt	$	15,000		$	15,000
Accounts payable - trade		74,364			67,283
Accounts payable - affiliates		35,162			40,773
Accrued gas payables		575,504			489,562
Accrued expenses		19,253			35,760
Accrued interest		17,974			30,338
Other current liabilities		23,997			42,644

Total current liabilities		761,254			721,360
Long-Term Debt		1,986,636			2,231,463
Other Long-Term Liabilities		7,663			7,666
Minority Interest		59,410			59,336
Commitments and Contingencies
Partners' Equity
Limited Partner		1,440,595			1,211,593
General Partner		14,700			12,363
Parent's Units acquired by Trust		(8,660	)		(8,660	)
Accumulated Other Comprehensive Income (Loss)		5,286			(3,560	)

Total Partners' Equity		1,451,921			1,211,736

Total	$	4,266,884		$	4,231,561

See Notes to Unaudited Consolidated Financial Statements

ENTERPRISE PRODUCTS OPERATING L.P. STATEMENTS OF CONSOLIDATED OPERATIONS AND COMPREHENSIVE INCOME (Dollars in thousands)

	For the Three Months Ended March 31,
	2003			2002
REVENUES
Revenues from consolidated operations
Third parties	$	1,348,782		$	571,246
Related parties		132,804			90,808

Total		1,481,586			662,054

COST AND EXPENSES
Operating costs and expenses
Third parties		1,152,302			518,049
Related parties		234,402			146,503
Selling, general and administrative
Third parties		4,808			1,833
Related parties		6,384			5,953

Total		1,397,896			672,338

EQUITY IN INCOME OF UNCONSOLIDATED AFFILIATES		1,621			9,227

OPERATING INCOME (LOSS)		85,311			(1,057	)

OTHER INCOME (EXPENSE)
Interest expense		(41,911	)		(18,513	)
Interest income from related parties					30
Dividend income from unconsolidated affiliates		2,601			954
Interest income - other		340			1,436
Other, net		36			52

Other income (expense)		(38,934	)		(16,041	)

INCOME (LOSS) BEFORE PROVISION FOR INCOME
TAXES AND MINORITY INTEREST		46,377			(17,098	)
PROVISION FOR INCOME TAXES		(3,129	)

INCOME (LOSS) BEFORE MINORITY INTEREST		43,248			(17,098	)
MINORITY INTEREST		(1,899	)		(53	)

NET INCOME (LOSS)		41,349			(17,151	)
Reclassification of change in value of financial instruments
recorded as cash flow hedges		3,560
Gain on settlement of financial instruments recorded as cash flow hedges		5,354
Amortization of gain on settlement of financial instruments to earnings		(68	)

COMPREHENSIVE INCOME (LOSS)	$	50,195		$	(17,151	)

See Notes to Unaudited Consolidated Financial Statements

ENTERPRISE PRODUCTS OPERATING L.P. STATEMENTS OF CONSOLIDATED CASH FLOWS (Dollars in thousands)

	For the Three Months Ended March 31,
	2003			2002
OPERATING ACTIVITIES
Net income (loss)	$	41,349		$	(17,151	)
Adjustments to reconcile net income (loss) to cash flows provided
by (used for) operating activities:
Depreciation and amortization in operating costs and expenses		27,657			17,238
Depreciation in selling, general and administrative costs		22			7
Amortization in interest expense		11,582			702
Equity in income of unconsolidated affiliates		(1,621	)		(9,227	)
Distributions received from unconsolidated affiliates		15,626			14,438
Operating lease expense paid by EPCO		2,274			2,305
Minority interest		1,899			53
Loss on sale of assets		4			14
Deferred income tax expense		2,733
Changes in fair market value of financial instruments		(28	)		30,141
Net effect of changes in operating accounts		47,767			(52,185	)

Operating activities cash flows		149,264			(13,665	)

INVESTING ACTIVITIES
Capital expenditures		(23,835	)		(17,112	)
Proceeds from sale of assets		34			10
Business acquisitions, net of cash received		(28,783	)		(368,631	)
Investments in and advances to unconsolidated affiliates		(20,509	)		(10,752	)

Investing activities cash flows		(73,093	)		(396,485	)

FINANCING ACTIVITIES
Borrowings under debt agreements		896,210			383,000
Repayments of debt		(1,141,000	)		(20,000	)
Debt issuance costs		(6,683	)
Distributions paid to partners		(70,454	)		(44,154	)
Distributions paid to minority interests		(1,806	)
Contributions from partners		258,170			39
Contributions from minority interests		26			10
Parent's Units acquired by consolidated Trust					(2,015	)
Settlement of treasury lock financial instruments		5,354
Increase in restricted cash		(10,006	)		(8,769	)

Financing activities cash flows		(70,189	)		308,111

NET CHANGE IN CASH AND CASH EQUIVALENTS		5,982			(102,039	)
CASH AND CASH EQUIVALENTS, JANUARY 1		12,044			132,071

CASH AND CASH EQUIVALENTS, MARCH 31	$	18,026		$	30,032

See Notes to Unaudited Consolidated Financial Statements

ENTERPRISE PRODUCTS OPERATING L.P. STATEMENTS OF CONSOLIDATED PARTNERS' EQUITY (Dollars in thousands)

	Limited Partner			General Partner			Parent's Units			Accum. OCI			Total
Balances, December 31, 2002	$	1,211,593		$	12,363		$	(8,660	)	$	(3,560	)	$	1,211,736
Net income		40,932			417									41,349
Leases paid by EPCO		2,251			23									2,274
Contributions from partners		255,562			2,608									258,170
Cash distributions to partners		(69,743	)		(711	)								(70,454	)
Reclassification of change in
value of treasury lock financial
instruments recorded as
cash flow hedges (see Note 11)											3,560			3,560
Cash gains on settlement of treasury
lock financial instruments
recorded as cash flow hedges (see Note 11)											5,354			5,354
Amortization of cash gains on
settlement of treasury lock
financial instruments to interest
expense in earnings (see Note 11)											(68	)		(68	)

Balances, March 31, 2003	$	1,440,595		$	14,700		$	(8,660	)	$	5,286		$	1,451,921

See Notes to Unaudited Consolidated Financial Statements

In the opinion of Enterprise Products Operating L.P., the accompanying unaudited consolidated financial statements include all adjustments consisting of normal recurring accruals necessary for a fair presentation of its consolidated financial position as of March 31, 2003 and consolidated results of operations and cash flows for the three months ended March 31, 2003 and 2002. Within these footnote disclosures of Enterprise Products Operating L.P., references to “we”, “us”, “our” or “the Company” shall mean the consolidated financial statements of Enterprise Products Operating L.P. References to “Limited Partner” shall mean the consolidated financial statements of our parent, Enterprise Products Partners L.P., which are included elsewhere in this combined report on Form 10-Q.

The results of operations for the three months ended March 31, 2003 are not necessarily indicative of the results to be expected for the full year.

Dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars, unless otherwise indicated.

Certain abbreviated entity names and other capitalized terms are described within the glossary of this quarterly report on Form 10-Q.

See Note 14 for the pro forma effects to net income and earnings per Unit as if we had used the fair-value based method of accounting for Unit options.

The following recently issued accounting standards have been adopted and implemented by us:

•

SFAS No. 143, "Accounting for Asset Retirement Obligations";

•

SFAS No. 146, "Accounting for Costs Associated with Exit and Disposal Activities";

•

SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure"; and,

•

FIN No. 45, "Guarantor's Accounting and Disclosure Requirement from Guarantees, Including Indirect Guarantees of Indebtedness of Others.”

We are currently evaluating the provisions of FIN No. 46, Consolidation of Variable Interest Entities.

SFAS No. 143. We adopted this standard as of January 1, 2003. This statement establishes accounting standards for the recognition and measurement of a liability for an asset retirement obligation (“ARO”) and the associated asset retirement cost. Under the provisions of this standard, we reviewed our long-lived assets for ARO liabilities and identified such liabilities in several operational areas. These include ARO liabilities related to (i) easements over property not currently owned by us and (ii) statutory regulatory requirements for abandonment or retirement of certain currently operated facilities.

Our preliminary allocation of the purchase price of each transaction is as follows:

	50% interest in EPIK			Port Neches Pipeline			Other		Total
Prepaid and other current assets	$	1,188		$	44				$	1,232
Property, plant and equipment		31,585			14,203			188		45,976
Investments in and advances to
unconsolidated affiliates		(17,247	)							(17,247	)
Accrued expenses		(1,102	)		(19	)				(1,121	)
Other current liabilities		(35	)		(24	)				(59	)
Minority interest								4		4

Total purchase price	$	14,389		$	14,204		$	192	$	28,785

Our inventories were as follows at the dates indicated:

	March 31, 2003		December 31, 2002
Working inventory	$	101,962	$	131,769
Forward-sales inventory				35,600

Inventory	$	101,962	$	167,369

Due to fluctuating market conditions in the midstream energy industry in which we operate, we occasionally recognize lower of average cost or market (“LCM”) adjustments when the costs of our inventories exceed their net realizable value. These non-cash adjustments are charged to operating costs and expenses in the period they are recognized. For the three months ended March 31, 2003 and 2002, we recognized $10.4 million and $0.1 million, respectively, of such LCM adjustments. The majority of these write-downs were taken against NGL inventories.

Our property, plant and equipment and accumulated depreciation were as follows at the dates indicated:

		March 31, 2003		December 31, 2002
Plants and pipelines	5-35	$	2,901,451	$	2,860,180
Underground and other storage facilities	5-35		284,214		283,114
Transportation equipment	3-35		5,223		5,118
Land			23,825		23,817
Construction in progress			68,848		49,586

Total			3,283,561		3,221,815
Less accumulated depreciation			437,568		410,976

Property, plant and equipment, net		$	2,845,993	$	2,810,839

Depreciation for the three-month periods ended March 31, 2003 and 2002 was $27.7 million and $17.2 million, respectively.

			March 31, 2003		December 31, 2002
Accounted for on equity basis:
Fractionation:
BRF	32.25	%	$	28,214	$	28,293
BRPC	30.00	%		17,392		17,616
Promix	33.33	%		41,049		41,643
La Porte	50.00	%		5,619		5,737
OTC	50.00	%		5,493		2,178
Pipeline:
EPIK (see Note 3)	50.00	%				11,114
Wilprise	37.35	%		8,508		8,566
Tri-States	33.33	%		25,571		25,552
Belle Rose	41.67	%		10,904		11,057
Dixie	19.88	%		37,461		36,660
Starfish	50.00	%		30,716		28,512
Neptune	25.67	%		76,928		77,365
Nemo	33.92	%		12,004		12,423
Evangeline	49.50	%		2,501		2,383
Octane Enhancement:
BEF	33.33	%		50,889		54,894
Accounted for on cost basis:
Processing:
VESCO	13.10	%		33,000		33,000

Total			$	386,249	$	396,993

The following table shows our equity in income (loss) of unconsolidated affiliates for the periods indicated:

	Ownership			For the Three Months Ended March 31,
	Percentage			2003			2002
Fractionation:
BRF		32.25	%	$	142		$	549
BRPC		30.00	%		148			249
Promix		33.33	%		260			1,043
La Porte		50.00	%		(181	)		(92	)
OTC		50.00	%		(85	)		(110	)
Pipelines:
EPIK (see Note 3)		50.00	%		1,818			1,683
Wilprise		37.35	%		163			147
Tri-States		33.33	%		549			469
Belle Rose		41.67	%		(29	)		74
Dixie		19.88	%		801			717
Starfish		50.00	%		1,149			812
Neptune		25.67	%		10			778
Nemo		33.92	%		336			(22	)
Evangeline		49.50	%		(19	)		(76	)
Octane Enhancement:
BEF		33.33	%		(3,441	)		3,006

Total				$	1,621		$	9,227

	Summarized Income Statement Information for the Three Months Ended
	March 31, 2003								March 31, 2002
	Revenues		Operating Inc (Loss)			Net Inc (Loss)			Revenues		Operating Income		Net Income
Pipelines	$	91,974	$	20,927		$	14,661		$	67,847	$	18,988	$	14,581
Fractionation		18,114		1,524			1,505			18,040		5,352		5,372
Octane Enhancement		45,651		(10,356	)		(10,322	)		47,929		8,978		9,019

The following table summarizes our excess cost information at March 31, 2003 and December 31, 2002 by the business segment to which the unconsolidated affiliates relate:

			Original Excess Cost attributable to				Unamortized balance at
	Amort. Periods		Tangible assets		Goodwill		March 31, 2003		December 31, 2002
Fractionation		20-35 years		8,828				7,319		7,429
Pipelines		35 years (1)		41,943		9,246		47,338		47,637

(1) Goodwill is not amortized; however, it is subject to periodic impairment testing.

Purchase of remaining 50% interest in EPIK

The following table summarizes our intangible assets at March 31, 2003 and December 31, 2002:

			At March 31, 2003					At December 31, 2002
	Gross Value		Accum. Amort.			Carrying Value		Accum. Amort.			Carrying Value
Shell natural gas processing agreement	$	206,216	$	(25,777	)	$	180,439	$	(23,015	)	$	183,201
Mont Belvieu Storage II contracts		8,127		(290	)		7,837		(232	)		7,895
Mont Belvieu Splitter III contracts		53,000		(1,767	)		51,233		(1,388	)		51,612
Toca-Western natural gas processing contracts		11,187		(466	)		10,721		(326	)		10,861
Toca-Western NGL fractionation contracts		20,042		(836	)		19,206		(585	)		19,457
Venice contracts (a)		4,636					4,636					4,635

Total	$	303,208	$	(29,136	)	$	274,072	$	(25,546	)	$	277,661


(a) Amortization scheduled to begin when contracted-volumes begin to be processed in late 2003

The following table shows amortization expense associated with our intangible assets for the three months ended March 31, 2003 and 2002:

	For the Three Months Ended March 31,
	2002		2003
Shell natural gas processing agreement	$	2,762	$	2,761
Mont Belvieu Storage II contracts		58		60
Mont Belvieu Splitter III contracts		379		252
Toca-Western natural gas processing contracts		140
Toca-Western NGL fractionation contracts		250

Total	$	3,589	$	3,073

Our goodwill is attributable to the excess of the purchase price over the fair value of assets acquired and is comprised of the following (at March 31, 2003 and December 31, 2002):

Mont Belvieu Splitter III acquisition	$	73,690
MBA acquisition		7,857

	$	81,547

Our goodwill amounts are classified as part of the Fractionation segment since they are related to assets recorded within this operating segment.

Our debt obligations consisted of the following at the dates indicated:

	March 31, 2003			December 31, 2002
Borrowings under:
364-Day Term Loan, variable rate, due July 2003				$	1,022,000
364-Day Revolving Credit facility, variable rate,
due November 2004	$	32,000			99,000
Multi-Year Revolving Credit facility, variable rate,
due November 2005		225,000			225,000
Senior Notes A, 8.25% fixed rate, due March 2005		350,000			350,000
Seminole Notes, 6.67% fixed rate, $15 million due
each December, 2002 through 2005		45,000			45,000
MBFC Loan, 8.70% fixed rate, due March 2010		54,000			54,000
Senior Notes B, 7.50% fixed rate, due February 2011		450,000			450,000
Senior Notes C, 6.375% fixed rate, due February 2013		350,000
Senior Notes D, 6.875% fixed rate, due March 2033		500,000

Total principal amount		2,006,000			2,245,000
Unamortized balance of increase in fair value related to
hedging a portion of fixed-rate debt		1,712			1,774
Less unamortized discount on:
Senior Notes A		(71	)		(81	)
Senior Notes B		(222	)		(230	)
Senior Notes D		(5,783	)
Less current maturities of debt		(15,000	)		(15,000	)

Long-term debt	$	1,986,636		$	2,231,463

Parent-Subsidiary guarantor relationships. Our parent (which is our Limited Partner) is the guarantor of certain of our consolidated debt obligations. This parent-subsidiary guaranty provision exists under all of our consolidated debt obligations, with the exception of the Seminole Notes. The Seminole Notes are unsecured obligations of Seminole Pipeline Company (of which we own an effective 78.4% of its ownership interests). If we were to default on any guaranteed debt obligation, our Limited Partner would be responsible for full payment of that obligation.

New debt obligations issued during first quarter of 2003

During the first quarter of 2003, we completed the issuance of $850 million of private placement debt (Senior Notes C and D). Senior Notes C and D are unsecured obligations and rank equally with its existing and future unsecured and unsubordinated indebtedness and senior to any future subordinated indebtedness. Senior Notes C and D are guaranteed by the Limited Partner through an unsecured and unsubordinated guarantee that is non-recourse to the General Partner. These notes were issued under an indenture containing certain covenants and are subject to a make-whole redemption right. These covenants restrict our ability, with certain exceptions, to incur debt secured by liens and engage in sale and leaseback transactions.

Repayment of 364-Day Term Loan

We entered into a $1.2 billion senior unsecured 364-day term loan to initially fund the acquisition of indirect interests in Mid-America and Seminole in July 2002. We used $178.5 million of the $182.5 million in proceeds from our Limited Partner’s October 2002 equity offering to partially repay this loan. We used $252.8 million of the $258.2 million in proceeds from our Limited Partner’s January 2003 equity offering (see Note 9), $347.0 million of the $347.7 million in proceeds from our issuance of Senior Notes C and $421.4 million in proceeds from our issuance of Senior Notes D to completely repay the 364-Day Term Loan by February 2003.

Covenants

We were in compliance with the various covenants of our debt agreements at March 31, 2003 and December 31, 2002.

Information regarding variable interest rates paid

The following table shows the range of interest rates paid and weighted-average interest rate paid on our variable-rate debt obligations for the three months ended March 31, 2003:

	Range of interest rates paid
364-Day Term Loan (a)	2.59% - 2.88%	2	.85%
364-Day Revolving Credit facility	2.47% - 4.25%	2	.52%
Multi-Year Revolving Credit facility	1.92% - 2.00%	1	.97%

(a) This facility was repaid in February 2003

We are owned 98.9899% by our Limited Partner and 1.0101% by our General Partner. The rights available to our partners are described in our Amended and Restated Agreement of Limited Partnership dated July 31, 1998. We are managed by our General Partner.

In January 2003, our Limited Partner completed an equity offering from which we received a cash contribution of $258.2 million, which includes our General Partner’s related capital contribution of $2.6 million. We used $252.8 million of the proceeds from this offering to repay a portion of the indebtedness outstanding under the 364-Day Term Loan. The remaining balance of proceeds was used for working capital purposes and offering expenses.

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

	For the Three Months Ended March 31,
	2003			2002
(Increase) decrease in:
Accounts and notes receivable	$	(86,002	)	$	794
Inventories		76,079			(31,748	)
Prepaid and other current assets		15,290			(2,494	)
Other assets		(503	)		(3,186	)
Increase (decrease) in:
Accounts payable		1,470			(13,369	)
Accrued gas payable		85,942			31,515
Accrued expenses		(17,628	)		(6,588	)
Accrued interest		(12,364	)		(16,137	)
Other current liabilities		(14,517	)		(10,891	)
Other liabilities					(81	)

Net effect of changes in operating accounts	$	47,767		$	(52,185	)

Commodity hedging financial instruments

During the first three months of 2002, we recognized a loss of $45.1 million from our Processing segment’s commodity hedging activities that was recorded as an operating cost in our Statements of Consolidated Operations and Comprehensive Income. In March 2002, the effectiveness of our primary commodity hedging strategy at the time deteriorated due to an unexpected rapid increase in natural gas prices whereby the loss in value of our fixed-price natural gas financial instruments was not offset by increased gas processing margins. We exited the strategy underlying this loss in 2002.

Interest rate hedging financial instruments

We evaluate segment performance based on the non-GAAP financial measure of gross operating margin. We define gross operating margin as operating income before: (1) depreciation and amortization amounts; (2) operating lease expenses for which the partnership does not have the payment obligation; (3) gains and losses on the sale of assets; and (4) selling, general and administrative expenses. Gross operating margin is exclusive of other income and expense transactions, provision for income taxes, minority interest and extraordinary charges. Segment gross operating margin is derived by subtracting segment operating costs and expenses (before depreciation and amortization amounts, operating lease expenses for which the partnership does not have the payment obligation and gains and losses on the sale of assets) from segment revenues, with both segment totals before elimination of intercompany transactions. Intercompany accounts and transactions are eliminated in consolidation in accordance with GAAP. Segment gross operating margin is also exclusive of other income and expense transactions, provision for income taxes, minority interest and extraordinary charges. We have provided a reconciliation of total gross operating margin (a non-GAAP performance measure) to operating income.

The following table shows our measurement of total segment gross operating margin for the periods indicated:

	For the Three Months Ended March 31,
	2003			2002
Revenues (a)	$	1,481,586		$	662,054
Less operating costs and expenses (a)		(1,386,704	)		(664,552	)
Add equity in income of unconsolidated affiliates (b)		1,621			9,227

Subtotal		96,503			6,729
Add: Depreciation and amortization in operating costs and expenses (c)		27,657			17,238
Retained lease expense, net in operating expenses allocable to us (d)		2,274			2,305
Loss on sale of assets in operating costs and expenses(c)		4			14

Total segment gross operating margin	$	126,438		$	26,286


(a) These amounts are comprised of both third party and related party totals as shown on our Statements of Consolidated Operations and Comprehensive Income.
(b) This amount is taken directly from our Statements of Consolidated Operations and Comprehensive Income.
(c) This amount is taken directly from the operating activities section of our Statements of Consolidated Cash Flows.
(d) This non-cash amount represents the value of the operating leases contributed by EPCO to us for which EPCO has retained the cash payment obligation (the "retained leases"). This amount is taken from the operating activities section ("Operating lease expense paid by EPCO" line item) of our Statements of Consolidated Cash Flows.

	For the Three Months Ended March 31,
	2003		2002
Operating income (loss)	$	85,311	$	(1,057	)
Adjustments to reconcile operating income (loss)
to total segment gross operating margin:
Depreciation and amortization in operating costs and expenses		27,657		17,238
Operating lease expenses for which EPCO has retained the cash
payment obligation, net in operating costs and expenses		2,274		2,305
Loss on sale of assets in operating costs and expenses		4		14
Selling, general and administrative costs		11,192		7,786

Total segment gross operating margin	$	126,438	$	26,286

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

	Operating Segments													Adjs.
	Fractionation		Pipelines		Processing			Octane Enhancement			Other			and Elims.			Consol. Totals
Revenues from
third parties:
Three months ended March 31, 2003	$	204,490	$	201,893	$	941,686					$	713					$	1,348,782
Three months ended March 31, 2002		103,799		75,844		391,131						472						571,246
Revenues from
related parties:
Three months ended March 31, 2003		623		40,705		91,476												132,804
Three months ended March 31, 2002		5,623		23,237		61,903						45						90,808
Intersegment and intrasegment
revenues:
Three months ended March 31, 2003		84,672		35,724		187,241						101		$	(307,738	)
Three months ended March 31, 2002		33,397		24,510		126,260						100			(184,267	)
Total revenues:
Three months ended March 31, 2003		289,785		278,322		1,220,403						814			(307,738	)		1,481,586
Three months ended March 31, 2002		142,819		123,591		579,294						617			(184,267	)		662,054
Equity income in
unconsolidated affiliates:
Three months ended March 31, 2003		284		4,778				$	(3,441	)								1,621
Three months ended March 31, 2002		1,639		4,582					3,006									9,227
Gross operating margin by individual
business segment and in total:
Three months ended March 31, 2003		29,047		71,932		29,956			(3,441	)		(1,056	)					126,438
Three months ended March 31, 2004		24,377		32,668		(33,376	)		3,006			(389	)					26,286
Segment assets:
At March 31, 2003		441,213		2,154,659		164,374						16,899			68,848			2,845,993
At December 31, 2002		444,016		2,166,524		134,237						16,825			49,237			2,810,839
Investments in and advances
to unconsolidated affiliates:
At March 31, 2003		97,767		204,593		33,000			50,889									386,249
At December 31, 2002		95,467		213,632		33,000			54,894									396,993
Intangible Assets:
At March 31, 2003		70,439		7,837		195,796												274,072
At December 31, 2002		71,069		7,895		198,697												277,661
Goodwill:
At March 31, 2003 and
December 31, 2002		81,547																81,547

Current:
Federal tax benefit	$	349
State tax benefit		47

		396

Deferred:
Federal		2,409
State		324

		2,733

Provision for income taxes	$	3,129

The following is a reconciliation of our provision for income taxes at the federal statutory rate to our recorded provision for income taxes:

Taxes computed by applying the federal statutory rate	$	2,888
State income taxes (net of federal benefit)		241

Provision for income taxes	$	3,129

Significant components of deferred income tax assets and liabilities at March 31, 2003 are as follows:

Deferred tax assets:
Property, plant and equipment	$	13,113
Deferred tax liabilities:
Other		(619	)

Net deferred tax assets	$	12,494

•

We pay EPCO for the costs attributable to equity-based awards granted to operations personnel it employs on our behalf.

•

We pay EPCO for the costs attributable to equity-based awards granted to administrative and management personnel it hires in response to our expansion and business activities.

•

Accounting principles require us to illustrate the pro forma effect on our net income (loss) as if the fair value-based method of accounting, based on SFAS No. 123, “Accounting for Stock Based Compensation,” had been applied to the 1998 Plan. The following table shows these pro forma effects for the periods indicated:

	For the Three Months Ended March 31,
	2003			2002
Net income (loss):
As reported	$	41,349		$	(17,151	)
Additional Unit option-based compensation
expense estimated using the
fair value-based method		(171	)		(273	)

Pro forma	$	41,178		$	(17,424	)

Enterprise Products Partners L.P. is a publicly-traded limited partnership (NYSE, symbol “EPD”) that conducts substantially all of its business through its 98.9899% owned subsidiary, Enterprise Products Operating L.P. (the “Operating Partnership”), the Operating Partnership’s subsidiaries, and a number of investments with industry partners. Since the Operating Partnership owns substantially all of Enterprise Products Partners L.P.‘s consolidated assets and conducts substantially all of its business and operations, the information set forth herein constitutes combined information for the two registrants. Unless the context requires otherwise, references to “we”, “us”, “our” or the “Company” are intended to mean the consolidated business and operations of Enterprise Products Partners L.P., which includes Enterprise Products Operating L.P. and its subsidiaries.

The following discussion and analysis should be read in conjunction with the unaudited consolidated financial statements and notes thereto of the Company and Operating Partnership included in Part I of this quarterly report on Form 10-Q.

We have five reportable operating segments: Pipelines, Fractionation, Processing, Octane Enhancement and Other. Pipelines consists of NGL, petrochemical and natural gas pipeline systems, storage and import/export terminal services. Fractionation primarily includes NGL fractionation, isomerization and propylene fractionation. Processing includes our natural gas processing business and related NGL marketing activities. Octane Enhancement represents our 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 various operational support activities.

We evaluate segment performance based on our measurement of gross operating margin (in the aggregate and by segment). This non-generally accepted accounting principle financial measure is used in this quarterly report. Amounts included in the calculation of this measure are computed in accordance with generally accepted accounting principles (“GAAP”). As part of our quarterly report, we have provided a reconciliation of this non-GAAP financial measure to its most comparable financial measure calculated and presented in accordance with GAAP.

We believe that investors benefit from having access to the same financial measures being utilized by management. Gross operating margin is an important performance measure of the economic success of our core operations and individual asset locations. This measure forms the basis of our internal financial reporting and is used by senior management in deciding how to allocate capital resources among segments. The nearest GAAP counterpart to gross operating margin is operating income. Operating income, however, includes expense items that management does not consider when evaluating the core profitability of an operation such as depreciation and selling, general and administrative costs.

We define gross operating margin as operating income before: (1) depreciation and amortization amounts; (2) operating lease expenses for which the partnership does not have the payment obligation; (3) gains and losses on the sale of assets; and (4) selling, general and administrative expenses. Gross operating margin is exclusive of other income and expense transactions, provision for income taxes, minority interest and extraordinary charges. Segment gross operating margin is derived by subtracting segment operating costs and expenses (before depreciation and amortization amounts, operating lease expenses for which the partnership does not have the payment obligation and gains and losses on the sale of assets) from segment revenues, with both segment totals before elimination of intercompany transactions. Intercompany accounts and transactions are eliminated in consolidation in accordance with GAAP. Segment gross operating margin is also exclusive of other income and expense transactions, provision for income taxes, minority interest and extraordinary charges. We have reconciled total gross operating margin (a non-GAAP performance measure) to operating income.

We include equity earnings from unconsolidated affiliates in our measurement of segment gross operating margin. Our equity investments with industry partners are a vital component of our business strategy. They are a means by which we conduct our operations to align our interests with our customers which may be a supplier of raw materials or a consumer of finished products. This method of operation also enables us to achieve favorable economies of scale relative to the level of investment and business risk assumed versus what we could accomplish on a stand alone basis. Many of these businesses perform supporting or complementary roles to our other business operations. For additional information regarding our business segments, see footnote 12 of our Notes to Unaudited Consolidated Financial Statements included under Item 1 of this quarterly report.

The following table shows our consolidated revenues, costs and expenses, equity in income of unconsolidated affiliates and operating income (loss) for the periods indicated (dollars in thousands):

	For the Three Months Ended March 31,
	2003		2002
Revenues	$	1,481,586	$	662,054
Operating costs and expenses		1,386,704		664,552
Selling, general and administrative costs		11,471		7,962
Equity in income of unconsolidated affiliates		1,621		9,227
Operating income (loss)		85,032		(1,233	)

The following table reconciles consolidated operating income (loss) to our measurement of total gross operating margin for the periods indicated (dollars in thousands):

	For the Three Months Ended March 31,
	2003		2002
Operating income (loss)	$	85,032	$	(1,233	)
Adjustments to reconcile operating income (loss)
to total segment gross operating margin:
Depreciation and amortization in operating costs and expenses		27,657		17,238
Operating lease expenses for which EPCO has retained the cash
payment obligation, net in operating costs and expenses		2,274		2,305
Loss on sale of assets in operating costs and expenses		4		14
Selling, general and administrative costs		11,471		7,962

Total segment gross operating margin	$	126,438	$	26,286

EPCO subleases certain equipment to us located at our Mont Belvieu facility and 100 railroad tankcars for $1 dollar per year. These subleases (the “retained leases”) are part of the EPCO Agreement we executed with EPCO at our formation in 1998. EPCO holds these items pursuant to operating leases for which it has retained the corresponding cash lease payment obligation. Operating costs and expenses (as shown in the Statements of Consolidated Operations and Comprehensive Income) treat the lease payments being made by EPCO as a non-cash related party operating expense, with the offset to Partners’ Equity on the Consolidated Balance Sheets recorded as a general contribution to the Company. Apart from the partnership interests we granted to EPCO at our formation, EPCO does not receive any additional ownership rights as a result of its contribution to us of the retained leases. In addition, EPCO has assigned to us the purchase options associated with these leases. For additional information regarding the EPCO Agreement and the retained leases, see “Related party transactions” on page 50 and “Capital spending” on page 49 of this quarterly report.

Our gross operating margin amounts by segment were as follows for the periods indicated (dollars in thousands):

	For the Three Months Ended March 31,
	2003			2002
Gross operating margin by segment:
Pipelines	$	71,932		$	32,668
Fractionation		29,047			24,377
Processing		29,956			(33,376	)
Octane enhancement		(3,441	)		3,006
Other		(1,056	)		(389	)

Gross operating margin total	$	126,438		$	26,286

Our significant plant production and other volumetric data were as follows for the periods indicated:

	For the Three Months Ended March 31,
	2003	2002
MBPD, Net
NGL and Petrochemical Pipelines	1,348	537
NGL Fractionation	240	204
Propylene Fractionation	61	52
Isomerization	80	74
Equity NGL Production	54	81
Octane Enhancement	3	4

BBtus per day, Net
Natural Gas Pipelines	1,055	1,224

Equivalent MBPD, Net
NGL, petrochemical and natural gas pipelines	1,626	859

The following table illustrates selected average quarterly industry index prices for natural gas, crude oil and selected NGL and petrochemical products since the beginning of 2002:

	Natural Gas, $/MMBtu		Crude Oil, $/barrel		Ethane, $/gallon		Propane, $/gallon		Normal Butane, $/gallon		Isobutane, $/gallon		Polymer Grade Propylene, $/pound		Refinery Grade Propylene, $/pound
	(a)		(b)		(a)		(a)		(a)		(a)		(a)		(a)
2002
1st Quarter	$	2.34	$	21.41	$	0.22	$	0.30	$	0.38	$	0.44	$	0.16	$	0.12
2nd Quarter	$	3.38	$	26.26	$	0.26	$	0.40	$	0.48	$	0.51	$	0.20	$	0.17
3rd Quarter	$	3.16	$	28.30	$	0.26	$	0.42	$	0.52	$	0.58	$	0.21	$	0.16
4th Quarter	$	3.99	$	28.33	$	0.31	$	0.49	$	0.60	$	0.63	$	0.20	$	0.15

Average	$	3.22	$	26.08	$	0.26	$	0.40	$	0.50	$	0.54	$	0.20	$	0.15

2003
1st Quarter	$	6.58	$	34.07	$	0.43	$	0.65	$	0.76	$	0.80	$	0.24	$	0.21

(a) Natural , NGL, polymer grade propylene and refinery grade propylene prices represent an average of various
commercial index prices including OPIS and CMAI
(b) Crude Oil price is representative of the index price for West Texas Intermediate

Three months ended March 31, 2003 compared to three months ended March 31, 2002

Revenues, operating costs and expenses, operating income and total gross operating margin.

Revenues for the three months ended March 31, 2003 increased $819.5 million over those recorded during the same period in 2002. The increase is primarily due to higher NGL, propylene and natural gas prices (see comparative product prices chart on page 42). The higher NGL prices resulted in a significant increase in Processing segment revenues (particularly those of its NGL marketing activities component). The higher propylene prices contributed to an increase in the revenues we derive from our petrochemical marketing activities. Also, the higher natural gas prices quarter-to-quarter resulted in an increase in Pipeline segment revenues from our Acadian Gas subsidiary. As part of its normal operations, Acadian Gas purchases natural gas from producers and suppliers and resells such natural gas to customers such as electric utility companies. Lastly, revenues increased as a result of acquisitions we completed since March 31, 2002 (particularly our acquisition of indirect interests in Mid-America and Seminole in July 2002).

Operating costs and expenses for the three months ended March 31, 2003 were $722.2 million higher than those recorded for the same period in 2002. The increase is primarily due to the same reasons that caused our revenues to be higher. As a result of the higher NGL, propylene and natural gas prices, the prices we paid for feedstocks and inventories increased. This affected our NGL and petrochemical marketing activities as well as our Acadian Gas natural gas purchases. In addition to the increase in product purchase prices, operating costs and expenses also increased as a result of acquisitions.

Our operating costs and expenses for the first three months of 2002 include a $45.1 million loss we recognized from our commodity hedging activities. In March 2002, the effectiveness of our primary commodity hedging strategy at the time deteriorated due to an unexpected rapid increase in natural gas prices whereby the loss in value of our fixed-price natural gas financial instruments was not offset by increased gas processing margins. We exited the strategy underlying this loss in 2002. During the first three months of 2003, we recorded a loss of $0.9 million from our commodity hedging activities.

Operating income was $85.0 million for the first three months of 2003 compared to a loss of $1.2 million for the first three months of 2002. Total gross operating margin was $126.4 million for the 2003 period versus $26.3 million for the 2002 period. The primary reasons for the increase in operating income and total gross operating margin are (i) the 2003 period includes results from our recently acquired Mid-America and Seminole pipeline systems and (ii) the 2002 period includes $45.1 million in commodity hedging losses. From a gross operating margin standpoint, Mid-America and Seminole contributed $47.5 million for the first quarter of 2003.

The following information highlights the significant quarter-to-quarter variances in gross operating margin by operating segment:

Pipelines. Gross operating margin from our Pipelines segment was $71.9 million for the first quarter of 2003 compared to $32.7 million for the first quarter of 2002. On an energy-equivalent basis, net pipeline throughput volume was 1,626 MBPD for the 2003 period versus 859 MBPD for the 2002 period. The increase in gross operating margin and throughput volume is primarily due to the acquisition of Mid-America and Seminole. These systems earned gross operating margin of $47.5 million on volumes of 816 MBPD for the first quarter of 2003. This acquisitions-related increase was offset by a decrease in gross operating margin from our Louisiana Pipeline System and our storage operations. Gross operating margin from our Louisiana Pipeline System declined $2.4 million quarter-to-quarter primarily due to lower throughput volumes attributable to a decrease in NGL extraction rates at regional gas processing facilities. Gross operating margin from our NGL and petrochemical storage operations was $4.7 million lower quarter-to-quarter as a result of higher storage well charges.

Fractionation. Gross operating margin from our Fractionation segment was $29.0 million for the first quarter of 2003 compared to $24.4 million for the first quarter of 2002. Gross operating margin from NGL fractionation improved $2.2 million quarter-to-quarter primarily due to an increase in in-kind fees at our Norco facility due to higher NGL prices. NGL fractionation volumes were 240 MBPD during the first three months of 2003 compared to 204 MBPD during the first three months of 2002. Gross operating margin from propylene fractionation declined $2.8 million quarter-to-quarter primarily due to higher energy-related costs, unscheduled

maintenance at one of our propylene fractionators and lower petrochemical marketing margins. Propylene fractionation volumes were 61 MBPD during the 2003 period versus 52 MBPD during the 2002 period. Gross operating margin from isomerization increased $3.6 million quarter-to-quarter primarily due to higher volumes and NGL by-product revenues. Isomerization volumes increased to 80 MBPD during the 2003 period from 74 MBPD during the 2002 period. Gross operating margin for our Fractionation segment also includes a one-time benefit of $1.1 million resulting from the settlement of a business interruption and related insurance claims involving Fractionation segment assets used to support our BEF investment.

Processing. Gross operating margin from our Processing segment was $30.0 million for the first quarter of 2003 compared to a loss of $33.4 million for the first quarter of 2002. As noted under our discussion of operating costs and expenses on page 43, the 2002 period includes commodity hedging losses of $45.1 million. Our commodity hedging results for the first quarter of 2003 were negligible. During the first quarter of 2003, our NGL marketing activities benefited from higher NGL prices and strong demand for propane and normal butane. This more than offset the decrease in gross operating margin caused by a decrease in equity NGL production from 81 MBPD during the 2002 period to 54 MBPD in the 2003 period.

The decrease in equity NGL production was largely attributable to higher natural gas prices relative to NGL prices, which caused us to minimize the amount of NGLs that were extracted by our natural gas processing facilities. In order to meet the natural gas processing needs of Shell (our largest processing customer) in this difficult pricing environment, we renegotiated certain aspects of the 20-year Shell natural gas processing agreement during the first quarter of 2003. For a general discussion of this amendment, see our discussion entitled “Related party transactions” on page 50.

Octane enhancement. Our equity earnings from BEF were a loss of $3.4 million for the first quarter of 2003 compared to income of $3.0 million for the first quarter of 2002. The quarter-to-quarter decline in equity earnings is attributable to increased downtime related to maintenance activities (which contributed to higher maintenance expenses); lower MTBE sales margins (primarily due to high methanol feedstock prices); and MTBE inventory valuation adjustments. BEF’s gross MTBE production rate declined to 10.1 MBPD during the first quarter of 2003 from 13.5 MBPD during the first quarter of 2002. We held a 33.3% ownership interest in BEF during both periods.

Selling, general and administrative expenses. These expenses were $11.5 million for the first quarter of 2003 versus $8.0 million for the first quarter of 2002. The increase is primarily due to the additional staff and resources needed to support our expansion activities resulting from acquisitions and other business development. The 2003 period includes a $2.0 million payment we made to Williams for general and administrative transition services related to our acquisition of the Mid-America and Seminole pipelines. These payments ceased in February 2003 when we took over the operation of these two systems.

Interest expense. Interest expense increased to $41.9 million for the first quarter of 2003 from $18.5 for the first quarter of 2002. The increase is primarily due to debt obligations we incurred as a result of business acquisitions, particularly the $1.2 billion in overall financing used to purchase Mid-America and Seminole in July 2002.

Interest expense for the 2003 period includes a non-cash charge of $11.3 million related to unamortized costs associated with the 364-Day Term Loan that we used to initially fund the Mid-America and Seminole acquisitions. In February 2003, we completely repaid this loan. As a result, all unamortized costs associated with this debt was charged to expense. For more information regarding our debt obligations and changes since December 31, 2002, please see “Our liquidity and capital resources – Our debt obligations”.

The following represents a combined discussion of our liquidity and capital resources and those of our Operating Partnership. Within this section, references to partnership equity pertains to limited partner interests issued by us, whereas references to debt pertains to those obligations entered into by our Operating Partnership or its subsidiaries.

General

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

Operating cash flows primarily reflect the effects of net income adjusted for depreciation and amortization, equity income and cash distributions from unconsolidated affiliates, fluctuations in fair values of financial instruments and changes in operating accounts. The net effect of changes in operating accounts is generally the result of timing of sales and purchases near the end of each period. Cash flow from operations is primarily based on earnings from our business activities. As a result, these cash flows are exposed to certain risks. The products that we process, sell or transport are principally used as feedstocks in petrochemical manufacturing, in the production of motor gasoline and as fuel for residential, agricultural and commercial heating. Reduced demand for our products or services by industrial customers, whether because of general economic conditions, reduced demand for the end products made with our products, increased competition from petroleum-based products due to pricing differences or other reasons, could have a negative impact on earnings and thus the availability of cash from operating activities. Other risks include fluctuations in NGL and energy prices, competitive practices in the midstream energy industry and the impact of operational and systems risks. For a more complete discussion of these and other risk factors pertinent to our businesses, see “Cautionary Statement regarding Forward-Looking Information and Risk Factors” on page 56 of this quarterly report.

As noted above, certain of our liquidity and capital resource requirements are fulfilled by borrowings made under debt agreements and/or proceeds from the issuance of additional partnership equity. At March 31, 2003, we had approximately $2.0 billion outstanding under various debt agreements. On that date, total borrowing capacity under our revolving commercial bank credit facilities was $500 million of which $217.3 million of capacity was available. For additional information regarding our debt, see “Our debt obligations” on page 48.

In February 2001, we filed a universal shelf registration with the SEC covering the issuance of up to $500 million of partnership equity or public debt obligations. In October 2002, we sold 9.8 million Common Units under this shelf registration statement which generated $182.5 million of cash to us (including related capital contributions from our General Partner). In January 2003, we sold an additional 14.7 million Common Units under this shelf registration which generated $258.2 million of cash to us (including related capital contributions from our General Partner). We used the cash generated by these equity offerings to reduce debt outstanding under our 364-Day Term Loan and for working capital purposes. Also, in January and February 2003, we issued $850 million of private placement debt (Senior Notes C and D). For information regarding our application of cash generated by these debt offerings, please read the section titled “Our debt obligations” within this “Our liquidity and capital resources” discussion.

In January 2003, we filed a new $1.5 billion universal shelf registration statement with the SEC covering the issuance of an unallocated amount of partnership equity or public debt obligations (separately or in combination). In accordance with Rule 457(p) promulgated under the Securities Act of 1933, as amended, the registration fee associated with the unsold portion of the securities under the shelf registration statement filed in February 2001 was used to offset the registration fee due in connection with our $1.5 billion universal shelf registration statement. When our new shelf registration was declared effective by the SEC in April 2003, the securities remaining under the shelf registration statement filed in February 2001 were deemed deregistered.

We have the ability to issue an unlimited number of Common Units to finance acquisitions and capital improvements if Adjusted Operating Surplus (as defined within our partnership agreement) for each of the four fiscal quarters immediately preceding the expenditure, on a pro forma basis, would have increased as a result of such expenditure (i.e., would have been accretive on a pro forma basis for each of the quarters in the test). For those

acquisitions and other transactions that do not qualify under the aforementioned pro forma “accretive” test, we have 54,550,000 Units available for general partnership purposes during the Subordination Period. The Subordination Period generally extends until the first day of any quarter beginning after June 30, 2003 when certain financial tests have been satisfied. We expect the Subordination Period to end on August 1, 2003. After the Subordination Period expires, we may prudently issue an unlimited number of Units for general partnership purposes that do not meet the pro forma “accretive” test.

If deemed necessary, we believe that additional financing arrangements can be obtained on reasonable terms. Furthermore, we believe that maintenance of our investment grade credit ratings combined with a continued ready access to debt and equity capital at reasonable rates and sufficient trade credit to operate our businesses efficiently provide a solid foundation to meet our long and short-term liquidity and capital resource requirements.

Three months ended March 31, 2003 compared to three months ended March 31, 2002

The following discussion highlights significant quarter-to-quarter comparisons regarding our consolidated operating, investing and financing cash flows:

Operating cash flows. Cash flow from operating activities was an inflow of $151.6 million during the first quarter of 2003 compared to an outflow of $10.0 million during the first quarter of 2002. The following table summarizes the major components of operating cash flows for first three months of 2003 and 2002 (dollars in thousands):

	For the Three Months Ended March 31,
	2003			2002
Net income (loss)	$	40,505		$	(17,203	)
Adjustments to reconcile net income (loss) to cash flows provided by
(used for) operating activities before changes in operating accounts:
Depreciation and amortization		39,261			17,947
Equity in income of unconsolidated affiliates		(1,621	)		(9,227	)
Distributions received from unconsolidated affiliates		15,626			14,438
Changes in fair market value of financial instruments		(28	)		30,141
Other		7,309			2,122

Cash flow from operating activities before changes in operating accounts	$	101,052		$	38,218
Net effect of changes in operating accounts		50,497			(48,191	)

Operating activities cash flows	$	151,549		$	(9,973	)

As shown in the table above, cash flow before changes in operating accounts was an inflow of $101.1 million during the first quarter of 2003 versus $38.2 million during the same period in 2002. We believe that cash flow from operating activities before changes in operating accounts is an important measure of our liquidity. We believe it provides an indication of our ability to generate core cash flows from the assets and investments we own or in which we have an interest. The $62.9 million increase in this element of our operating cash flows is primarily due to:

•

earnings from acquired businesses present in the 2003 period but not in the 2002 period (particularly those of Mid-America and Seminole which we acquired in July 2002);

•

the 2002 period including $45.1 million of commodity hedging losses versus practically none during the 2003 period; offset by,

•

higher interest costs associated with debt we incurred and issued since the first quarter of 2002 to finance acquisitions.

The $21.3 million increase in depreciation and amortization is primarily due to businesses we acquired since the first quarter of 2002. Changes in operating accounts are generally the result of timing of cash receipts from sales and cash payments for inventory, purchases and other expenses near the end of each period. For

additional information regarding changes in operating accounts, please see footnote 10 in our Notes to Unaudited Consolidated Financial Statements included under Item 1 of this quarterly report.

Investing cash flows. During the first three months of 2003, we used $73.1 million in cash for investing activities compared to $396.5 million during the same period for 2002. We used $28.8 million and $368.6 million for business acquisitions during the first quarter of 2003 and 2002, respectively. The 2003 period includes our acquisition of the Port Neches Pipeline and the remaining 50% ownership interests in EPIK. The 2002 period includes our acquisition of Diamond-Koch’s Mont Belvieu NGL and petrochemical storage business and propylene fractionation business.

Our capital expenditures were $23.8 million during the first quarter of 2003 and $17.1 million during the first quarter of 2002. The majority of the expenditures for the 2003 period related to Processing segment projects whereas the expenditures for the 2002 period centered on Pipeline segment projects. In addition, we made investments in and advances to our unconsolidated affiliates of $20.5 million during the first quarter of 2003 compared to $10.8 million during the first quarter of 2002. The increase is primarily due to funding our share of the expansion projects of our Gulf of Mexico natural gas pipeline investments.

Financing cash flows. Our financing activities were a cash outflow of $69.7 million during the first quarter of 2003 versus a cash inflow of $304.4 million during the first quarter of 2002. During the 2003 period, we made net payments on our debt obligations of $244.8 million with the aid of $258.2 million from our January 2003 equity offering. The 2003 period reflects our issuance of Senior Notes C ($350 million in principal amount) and Senior Notes D ($500 million in principal amount) and the final repayment of $1.0 billion that was outstanding under our 364-Day Term Loan. The 2002 period reflects the borrowings under our revolving bank credit facilities primarily to fund the acquisition of Diamond-Koch’s propylene fractionation business. Cash distributions to our partners increased to $69.2 million during the first quarter of 2003 from $47.4 million during the first quarter of 2002 primarily due to increases in both the declared quarterly distribution rates and the number of Units eligible for distributions.

Our debt obligations

Our debt obligations consisted of the following at the dates indicated:

	March 31, 2003			December 31, 2002
Borrowings under:
364-Day Term Loan, variable rate, due July 2003				$	1,022,000
364-Day Revolving Credit facility, variable rate,
due November 2004	$	32,000			99,000
Multi-Year Revolving Credit facility, variable rate,
due November 2005		225,000			225,000
Senior Notes A, 8.25% fixed rate, due March 2005		350,000			350,000
Seminole Notes, 6.67% fixed rate, $15 million due
each December, 2002 through 2005		45,000			45,000
MBFC Loan, 8.70% fixed rate, due March 2010		54,000			54,000
Senior Notes B, 7.50% fixed rate, due February 2011		450,000			450,000
Senior Notes C, 6.375% fixed rate, due February 2013		350,000
Senior Notes D, 6.875% fixed rate, due March 2033		500,000

Total principal amount		2,006,000			2,245,000
Unamortized balance of increase in fair value related to
hedging a portion of fixed-rate debt		1,712			1,774
Less unamortized discount on:
Senior Notes A		(71	)		(81	)
Senior Notes B		(222	)		(230	)
Senior Notes D		(5,783	)
Less current maturities of debt		(15,000	)		(15,000	)

Long-term debt	$	1,986,636		$	2,231,463

Parent-Subsidiary guarantor relationships. We act as guarantor of certain debt obligations of our subsidiaries including, all of our Operating Partnership’s consolidated debt obligations, with the exception of the Seminole Notes. The Seminole Notes are unsecured obligations of Seminole Pipeline Company (of which we own an effective 78.4% of its ownership interests). If the Operating Partnership were to default on any guaranteed debt obligation, we would be responsible for full payment of that obligation.

New debt obligations issued during first quarter of 2003

incurred to finance the Mid-America and Seminole acquisitions. In April 2003, we initiated an offer to exchange the private placement Senior Notes C for publicly-registered Senior Notes C.

Repayment of 364-Day Term Loan

Our Operating Partnership entered into a $1.2 billion senior unsecured 364-day term loan to initially fund the acquisition of indirect interests in Mid-America and Seminole in July 2002. We used $178.5 million of the $182.5 million in proceeds from our October 2002 equity offering to partially repay this loan. We used $252.8 million of the $258.2 million in proceeds from the January 2003 equity offering, $347.0 million of the $347.7 million in proceeds from our issuance of Senior Notes C and $421.4 million in proceeds from our issuance of Senior Notes D to completely repay the 364-Day Term Loan by February 2003.

Covenants

We were in compliance with the various covenants of our debt agreements at March 31, 2003 and December 31, 2002.

Credit ratings

Our current investment grade credit ratings are Baa2 by Moody’s Investor Service and BBB by Standard and Poors. Upon our acquisitions of the Mid-America and Seminole pipelines, both agencies maintained our ratings; however, each placed us on negative outlook pending the issuance of an appropriate amount of equity to repay the debt we incurred to fund these acquisitions. The agencies have responded positively to our recent equity and debt offerings. We believe that the maintenance of an investment grade credit rating is important in managing our liquidity and capital resource requirements. We maintain regular communications with these ratings agencies which independently judge our creditworthiness based on a variety of quantitative and qualitative factors.

Capital spending

At March 31, 2003, we had $11.1 million in estimated outstanding purchase commitments attributable to capital projects. Of this amount, $7.8 million is related to the construction of assets that will be recorded as property, plant and equipment and $3.3 million is associated with our share of capital projects of our unconsolidated affiliates which will be recorded as additional investments in unconsolidated affiliates.

During the remainder of 2003, we expect capital spending on internal growth projects to approximate $105.9 million, of which $44.5 million is forecasted for various projects within our Pipelines segment; $35.7 million for the expansion of our Norco NGL fractionator and $13.3 million for the expansion of our Neptune gas processing facility. Our unconsolidated affiliates forecast a combined $35.1 million in capital expenditures during the remainder of 2003, the majority of which relate to expansion projects on our Gulf of Mexico natural gas pipeline systems. Our share of these forecasted capital expenditures is estimated at $15.1 million.

EPCO subleases to us all of the equipment it holds pursuant to operating leases relating to an isomerization unit, a deisobutanizer tower, two cogeneration units and approximately 100 railcars for one dollar per year and has assigned to us its purchase option under such leases (the “retained leases”). EPCO remains liable for the lease payments associated with these items. We have notified the original lessor of the isomerization unit of our intent to exercise the purchase option assigned to us. The purchase price of this equipment is expected to be up to $23.1 million and be payable in 2004.

With regards to our material contractual obligations, there have been no significant changes outside of the ordinary course of our business since December 31, 2002 except for the following:

•

In February 2003, we completely repaid the $1.0 billion principal balance that was outstanding under the 364-Day Term Loan at December 31, 2002 using proceeds from the debt and equity offerings we completed during the first quarter of 2003 (which include our Senior Notes C and D discussed below).

•

We issued our $350 million in principal amount Senior Notes C in January 2003. These notes mature in 2013.

•

We issued our $500 million in principal amount Senior Notes D in February 2003. These notes mature in 2033.

•

Our letters of credit increased from $2.4 million at December 31, 2002 to $25.7 million at March 31, 2003. The increase is attributable to letter of credit requirements related to our import of NGL cargoes during the period.

The following table summarizes our updated material contractual obligations related to our debt obligations:

Contractual Obligations	Total		2003		2004 through 2005		After 2007
Principal payments to be made
under debt obligations	$	2,006,000	$	15,000	$	637,000	$	1,354,000
Potential payments due under
letter of credit agreements	$	25,695			$	25,695

Relationship with EPCO and Its Affiliates

We have an extensive and ongoing relationship with EPCO and its affiliates. EPCO is controlled by Dan L. Duncan, Chairman and a director (and Chairman of the Board of Directors) of the General Partner. In addition, three other members of the Board of Directors (O.S. Andras, Randa D. Williams and Richard H. Bachmann) and the remaining executive and other officers of the General Partner are employees of EPCO. The principal business activity of our General Partner is to act as our managing partner. Collectively, EPCO and its affiliates owned 57.4% of our limited partnership interests and 70.0% of our General Partner at March 31, 2003.

We have no employees. All of our management, administrative and operating functions are performed by employees of EPCO. We reimburse EPCO for the costs of its employees who perform operating functions for us. In addition, we reimburse EPCO for the costs of certain of employees who manage our business and affairs.

EPCO is also the operator of certain facilities we own or have an equity interest in. We have also entered into an agreement with EPCO to provide trucking services to us for the loading and transportation of products. Lastly, in the normal course of business, we buy from and sell NGL products to EPCO’s Canadian affiliate.

The following table shows our related party revenues and operating expenses attributable to EPCO for the periods indicated:

	For the Three Months Ended March 31,
	2003		2002
Revenues from consolidated operations	$	563	$	2,299
Operating costs and expenses		46,205		19,929
Selling, general and administrative expenses		6,384		5,953

Relationship with Shell

We have a commercial relationship with Shell as a partner, customer and vendor. At March 31, 2003, Shell owned approximately 20.1% of our limited partnership interests and 30.0% of our General Partner. Currently, three members of the Board of Directors of the General Partner (J.A. Berget, J.R. Eagan and A.Y. Noojin, III) are employees of Shell.

Shell and its affiliates are the Company’s single largest customer. During the three months ended March 31, 2003 and 2002, they accounted for 5.5% and 8.7%, respectively, of our consolidated revenues. Our revenues from Shell reflect the sale of NGL and petrochemical products to them and the fees we charge them for pipeline transportation and NGL fractionation services. Our operating costs and expenses with Shell primarily reflect the payment of energy-related expenses related to the Shell natural gas processing agreement and the purchase of NGL products from them.

The most significant contract affecting our natural gas processing business is the 20-year, keepwhole Shell processing agreement, which grants us the right to process Shell’s current and future production from state and federal waters of the Gulf of Mexico. The Shell processing agreement includes a life of lease dedication, which may extend the agreement well beyond 20 years. This contract was amended effective March 1, 2003. Generally, the amended contract has the following rights and obligations:

•

the exclusive right, but not the obligation in all cases, to process substantially all of Shell's Gulf of Mexico natural gas production; plus

•

the exclusive right, but not the obligation in all cases, to process all natural gas production from leases dedicated by Shell for the life of such leases; plus

•

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

•

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

In our natural gas processing activities under this contract, we reimburse Shell for the energy value of (i) the NGLs we extract and (ii) the natural gas we consume as fuel. This energy value is referred to as plant thermal reduction (“PTR”) and is based on the Btu content of the natural gas taken out of the stream. The amended contract contains a mechanism (termed “Consideration Adjustment Outside of Normal Operations” or “CAONO”) to adjust the value of the PTR we reimburse to Shell. The CAONO, in effect, protects us from processing at an economic loss when the value of the NGLs we extract is less than the sum of the cost of the PTR reimbursement, operating costs of the gas processing facility and other costs such as NGL fractionation and pipeline fees.

In general, the CAONO adjustment requires the comparison of our average net gas processing margin to an upper and lower limit (all as defined within the agreement). If our average net processing margin is below the lower limit, the PTR reimbursement payable to Shell is decreased by the product of the absolute value of the difference between our average net processing margin and the specified lower limit multiplied by the volume of NGLs extracted. To the extent our average net processing margin is higher than the upper limit (the probability of which we believe is low), the PTR reimbursement payable to Shell is increased by the product of the difference between the average net gas processing margin and the specified upper limit multiplied by the volume of NGLs extracted.

The underlying purpose of the CAONO mechanism is to provide Shell with relative assurance that its gas will continue to be processed during periods when natural gas prices are high relative to NGL prices (times when we would choose not to process) while continuing to protect us from processing Shell’s gas at an economic loss.

The following table shows our related party revenues and operating expenses attributable to Shell for the periods indicated:

	For the Three Months Ended March 31,
	2003		2002
Revenues from consolidated operations	$	82,220	$	57,657
Operating costs and expenses		171,714		105,148

Shell is also a partner with us in the Gulf of Mexico natural gas pipelines we acquired from El Paso in 2001. We also lease from Shell its 45.4% interest in our Splitter I propylene fractionation facility.

The following recently issued accounting standards have been adopted and implemented by us:

•

SFAS No. 143, "Accounting for Asset Retirement Obligations";

•

SFAS No. 146, "Accounting for Costs Associated with Exit and Disposal Activities";

•

SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure"; and,

•

FIN No. 45, "Guarantor's Accounting and Disclosure Requirement from Guarantees, Including Indirect Guarantees of Indebtedness of Others.”

We are currently evaluating the provisions of FIN No. 46, Consolidation of Variable Interest Entities.

As a result of our analysis of the identified AROs, we were not required to recognize such potential liabilities. Our rights to the easements are renewable and only require retirement action upon nonrenewal of the easement agreements. We currently plan to renew all such easement agreements and use these properties indefinitely. Therefore, the ARO liability is not estimable for such easements. If we decide not to renew these agreements, an ARO liability would be recorded at that time. ARO liabilities related to statutory regulatory requirements for abandonment or retirement of certain currently operated facilities were also identified. We currently have no intention or legal obligation to abandon or retire such facilities. An ARO liability would be recorded if future abandonment or retirement occurred. Certain Gulf of Mexico natural gas pipelines, in which we have an equity interest, have identified ARO’s relating to regulatory requirements. There is no current intention to abandon or retire these pipelines. If these pipelines were abandoned or retired, an ARO liability would then be disclosed.

In our financial reporting process, we employ methods, estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements. These methods, estimates and assumptions also affect the reported amounts of revenues and expenses during the reporting period. Investors should be aware that actual results could differ from these estimates if the underlying assumptions prove to be incorrect.

There have been no significant changes in our critical accounting policies since December 31, 2002. For a detailed discussion of these policies, please see the section titled “Our critical accounting policies” under Item 7 of our annual report on Form 10-K for 2002. The following is a condensed discussion of our critical accounting policies and the estimates and assumptions underlying them.

Depreciation methods and estimated useful lives of property, plant and equipment

In general, depreciation is the systematic and rational allocation of an asset’s cost, less its residual value (if any), to the periods it benefits. We use the straight-line method to depreciate our property, plant and equipment. Our estimate of an asset’s useful life is based on a number of assumptions including technological changes that may affect the asset’s usefulness and the manner in which we intend to physically use the asset. If we subsequently change our assumptions regarding these factors, it would result in an increase or decrease in depreciation expense. Additionally, if we determine that an asset’s undepreciated cost may not be recoverable due to impairment, this would result in a charge against earnings.

At March 31, 2003 and December 31, 2002, the net book value of our property, plant and equipment was $2.8 billion. See footnote 5 of the Notes to Unaudited Consolidated Financial Statements for additional information regarding our property, plant and equipment.

Amortization methods and estimated useful lives of qualifying intangible assets

Our recorded intangible assets primarily consist of the estimated value assigned to certain contract-based assets representing the rights we own arising from contractual agreements. A contract-based intangible asset with a finite useful life is amortized over its estimated useful life. Our estimate of useful life is based on a number of factors including the expected useful life of related assets (i.e., fractionation facility, pipeline, etc.) and the effects of obsolescence, demand, competition and other factors. If our underlying assumptions regarding the useful life of an intangible asset change, we then might need to adjust the amortization period of such asset which would increase or decrease amortization expense. Additionally, if we determine that an intangible asset’s unamortized cost may not be recoverable due to impairment, this would result in a charge against earnings.

At March 31, 2003 and December 31, 2002, the net book value of our intangible assets was $274.1 million and $277.7 million. See footnote 7 of the Notes to Unaudited Consolidated Financial Statements for additional information regarding our intangible assets.

Methods we employ to measure the fair value of goodwill

Our goodwill is attributable to the excess of the purchase price over the fair value of assets acquired. Goodwill is not amortized. Instead, goodwill is tested for impairment at a reporting unit level annually, and more frequently, if circumstances warrant. This testing involves calculating the fair value of a reporting unit, which in turn is based on our assumptions regarding the future economic prospects of the reporting unit. If the fair value of the reporting unit (including related goodwill) is less than its book value, a charge to earnings would be required to reduce the carrying value of goodwill to its implied fair value. If our underlying assumptions regarding the future economic prospects of a reporting unit change, this could impact the fair value of the reporting unit and result in a charge to earnings to reduce the carrying value of goodwill.

At March 31, 2003 and December 31, 2002, the carrying value of our goodwill was $81.5 million. See footnote 7 of the Notes to Unaudited Consolidated Financial Statements for additional information regarding our goodwill.

Our revenue recognition polices

In general, we recognize revenue from our customers when all of the following criteria are met: (i) firm contracts are in place, (ii) delivery has occurred or services have been rendered, (iii) pricing is fixed and determinable and (iv) collectibility is reasonably assured. When contracts settle (i.e., either physical delivery of product has taken place or the services designated in the contract have been performed), we determine if an allowance is necessary and record it accordingly. The revenues that we record are not materially based on estimates. We believe the assumptions underlying any revenue estimates that we use will not prove to be significantly different from actual amounts due to the routine nature of these estimates and the stability of our operations.

Mark-to-market accounting for certain financial instruments

Our earnings are also affected by use of the mark-to-market method of accounting required under GAAP for certain financial instruments. We use short-term, highly liquid financial instruments such as swaps, forwards and other contracts to manage price risks associated with inventories, firm commitments and certain anticipated transactions, primarily within our Processing segment. The use of mark-to-market accounting for financial instruments may cause our non-cash earnings to fluctuate based upon changes in underlying indexes, primarily commodity prices. Fair value for the financial instruments we employ is determined using price data from highly liquid markets such as the NYMEX commodity exchange.

During the first three months of 2002, we recognized a loss of $45.1 million from our commodity hedging activities. Of this loss, $28.7 million was attributable to the change in fair value of the portfolio between December

31, 2001 and March 31, 2002. The fair value of open positions at March 31, 2002 was a payable of $23.1 million. In March 2002, the effectiveness of our primary commodity hedging strategy deteriorated due to an unexpected rapid increase in natural gas prices whereby the loss in value of our fixed-price natural gas financial instruments was not offset by increased gas processing margins. We exited the strategy underlying this loss.

During the first three months of 2003, we entered into a limited number of commodity financial instruments from which we recorded a loss of $0.9 million. The fair value of open positions at March 31, 2003 was a receivable of approximately $2 thousand. See footnote 11 of the Notes to Unaudited Consolidated Financial Statements for additional information regarding our financial instruments.

Uncertainties regarding our investment in BEF

In recent years, MTBE has been detected in municipal and private water supplies resulting in various legal actions. BEF has not been named in any MTBE legal action to date. In light of these developments, we and the other two partners of BEF are formulating a plan for the BEF facility if MTBE is banned. We are evaluating a possible conversion of the facility from MTBE production to alkylate production. The carrying value of our investment in BEF was $50.9 million at March 31, 2003.

Conversion of EPCO Subordinated Units to Common Units

On May 1, 2003, 10,704,936 of EPCO’s Subordinated Units converted to Common Units as a result of the Company satisfying certain financial tests. The remaining 21,409,872 Subordinated Units are anticipated to convert to Common Units on August 1, 2003. These conversions will have no impact upon our earnings per unit or distributions since Subordinated Units are already included in both the basic and fully-diluted earnings per unit calculations and are distribution-bearing.

This quarterly report contains various forward-looking statements and information that are based on our beliefs and those of our general partner, as well as assumptions made by us and information currently available to us. When used in this document, words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “intend,” “could,” “believe,” “may” and similar expressions and statements regarding our plans and objectives for future operations, are intended to identify forward-looking statements. Although we and our general partner believe that such expectations reflected in such forward-looking statements are reasonable, neither we nor our general partner can give any assurances that such expectations will prove to be correct. Such statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. You should not put undue reliance on any forward-looking statements. When considering forward-looking statements, please review our “Risk Factors” below.

Risk Factors

Among the key risk factors that may have a direct impact on our results of operations and financial condition are:

•

A decrease in the difference between NGL product prices and natural gas prices results in lower margins on volumes processed, which would adversely affect our profitability.

•

A reduction in demand for our products by the petrochemical, refining or heating industries could adversely affect our results of operations.

•

A decline in the volume of NGLs delivered to our facilities could adversely affect our results of operations.

•

Our business requires extensive credit risk management that may not be adequate to protect against customer nonpayment.

•

Acquisitions and expansions may affect our business by substantially increasing the level of our indebtedness and contingent liabilities and increasing our risks of being unable to effectively integrate these new operations.

•

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to entity-level taxation by states. If the IRS treats us as a corporation or we become subject to entity-level taxation for state tax purposes, it would substantially reduce distributions to our Unitholders and our ability to make payments on our debt securities.

•

We have leverage that may restrict our future financial and operating flexibility.

•

Terrorist attacks aimed at our facilities could adversely affect our business.

There has been no material change in our commodity financial instruments portfolio since December 31, 2002. During the first quarter of 2003, we settled all interest rate-related financial instruments that were outstanding at December 31, 2002 (see the following discussion titled “Interest rate-related financial instruments portfolio”). For additional information regarding our financial instruments, see footnote 11 of our Notes to Unaudited Consolidated Financial Statements.

Commodity financial instruments portfolio

At December 31, 2002, the net fair value of this portfolio was a payable of $26 thousand, based entirely upon quoted market prices. At March 31, 2003, the net fair value of this portfolio was a receivable $2 thousand. We continue to have only a limited number of commodity financial instruments outstanding.

During the first three months of 2002, we recognized a loss of $45.1 million from our Processing segment’s commodity hedging activities that was recorded as an operating cost in our Statements of Consolidated Operations. In March 2002, the effectiveness of our primary commodity hedging strategy at the time deteriorated due to an unexpected rapid increase in natural gas prices whereby the loss in value of our fixed-price natural gas financial instruments was not offset by increased gas processing margins. We exited the strategy underlying this loss in 2002.

During the first three months of 2003, we recorded a loss of $0.9 million from our commodity hedging activities, of which $0.1 million is attributable to the Processing segment and the remainder to Pipelines.

Interest rate-related financial instruments portfolio

Interest rate swap agreements. At December 31, 2002, we had one interest rate swap outstanding having a notional amount of $54 million and a fair value at that date of $1.6 million. The counterparty elected to exercise its option to terminate this swap as of March 1, 2003 and we received $1.6 million associated with the final settlement of this swap on that date. The early termination of the swap had no impact on our earnings. At March 31, 2003, we have no interest rate swap agreements outstanding.

Treasury Locks. During the fourth quarter of 2002, we entered into seven treasury lock transactions, each with an original maturity of either January 31, 2003 or April 15, 2003. A treasury lock is a specialized agreement that fixes the price (or yield) on a specific U.S. treasury security for an established period of time. The purpose of these transactions was to hedge the underlying treasury interest rate associated with our anticipated issuance of debt in early 2003 to partially refinance the Mid-America and Seminole acquisitions. Our treasury lock transactions are accounted for as cash flow hedges under SFAS No. 133. The notional amounts of these transactions totaled $550 million, with a total treasury lock rate of approximately 4%.

We elected to settle all of the treasury locks during the first quarter of 2003 in connection with our issuance of Senior Notes C and D (see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Our liquidity and capital resources—Our debt obligations” under Item 2 of this quarterly report). The settlement of the treasury locks resulted in our receipt of $5.4 million of cash.

The fair value of these instruments at December 31, 2002 was a current liability of $3.8 million offset by a current asset of $0.2 million. The net $3.6 million net liability was recorded as a component of comprehensive income on that date, with no impact to current earnings. With the settlement of the treasury locks, the $3.6 million net liability was reclassified out of accumulated other comprehensive income in Partners’ Equity to offset the

current asset and liabilities we recorded at December 31, 2002, with no impact to earnings. For additional information regarding our treasury lock transactions, see our footnote 11 of our Notes to Unaudited Consolidated Financial Statements.

In the 90-day period before the filing of this quarterly report, the CEO and CFO of the General Partner of Enterprise Products Partners L.P. and Enterprise Products Operating L.P. (collectively the “registrants”) have evaluated the effectiveness of the registrants’ disclosure controls and procedures. These disclosure controls and procedures are those controls and other procedures we maintain, which are designed to insure that all of the information required to be disclosed by the registrants in all of their combined and separate periodic reports filed with the SEC is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the registrants in their reports filed or submitted under the Securities Exchange Act of 1934 is accumulated and communicated to our management, including the CEO and CFO of the General Partner, as appropriate to allow those persons to make timely decisions regarding required disclosure.

Subsequent to the date when the disclosure controls and procedures were evaluated, there have not been any significant changes in the registrants’ controls or procedures or in other factors that could significantly affect such controls or procedures. No significant deficiencies or material weaknesses were detected, so no corrective actions needed to be taken.

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

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

(a)(3) Exhibits.

Exhibit No.		Exhibit*
2.1	--	Purchase and Sale Agreement between Coral Energy, LLC and Enterprise Products Operating L.P. dated September 22, 2000 (incorporated by reference to Exhibit 10.1 to Form 8-K filed September 26, 2000).
2.2	--	Purchase and Sale Agreement dated January 16, 2002 by and between Diamond-Koch, L.P. and Diamond-Koch III, L.P. and Enterprise Products Texas Operating L.P. (incorporated by reference to Exhibit 10.1 to Form 8-K filed February 8, 2002.)
2.3	--	Purchase and Sale Agreement dated January 31, 2002 by and between D-K Diamond-Koch, L.L.C., Diamond-Koch, L.P. and Diamond-Koch III, L.P. as Sellers and Enterprise Products Operating L.P. as Buyer (incorporated by reference to Exhibit 10.2 to Form 8-K filed February 8, 2002).
2.4	--	Purchase Agreement by and between E-Birchtree, LLC and Enterprise Products Operating L.P. dated July 31, 2002 (incorporated by reference to Exhibit 2.2 to Form 8-K filed August 12, 2002).
2.5	--	Purchase Agreement by and between E-Birchtree, LLC and E-Cypress, LLC dated July 31, 2002 (incorporated by reference to Exhibit 2.1 to Form 8-K filed August 12, 2002).
3.1	--	First Amended and Restated Limited Liability Company Agreement of Enterprise Products GP, LLC dated as of September 17, 1999 (incorporated by reference to Exhibit 99.8 to the Form 8-K/A-l filed October 27, 1999).
3.2	--	Amendment No. 1 to the First Amended and Restated Limited Liability Company Agreement of the General Partner dated as of September 19, 2002 (incorporated by reference to Exhibit 3.2 to Form 10-K filed March 31, 2003).
3.3	--	Third Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P. dated May 15, 2002 (incorporated by reference to Exhibit 3.3 to Form 10-Q filed August 13, 2002).
3.4	--	Amendment No. 1 to Third Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P. dated August 7, 2002 (incorporated by reference to Exhibit 3.3 to Form 10-Q filed August 13, 2002).
3.5	--	Amendment No. 2 to Third Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P. dated December 17, 2002 (incorporated by reference to Exhibit 3.5 to Form 8-K filed December 17, 2002).
3.6	--	Amended and Restated Agreement of Limited Partnership of Enterprise Products Operating L.P. dated as of July 31, 1998 (incorporated by reference to Exhibit 3.2 to Registration Statement on Form S-1/A filed July 21, 1998).
4.1	--	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 (incorporated by reference to Exhibit 4.1 to Form 8-K filed March 10, 2000).
4.2	--	First Supplemental Indenture dated as of January 22, 2003, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wachovia Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Registration Statement on Form S-4, Reg. No. 333-102776, filed January 28, 2003).
4.3	--	Global Note representing $350 million principal amount of 6.375% Series A Senior Notes due 2013 with attached Guarantee (incorporated by reference to Exhibit 4.3 to Registration Statement on Form S-4, Reg. No. 333-102776, filed January 28, 2003).

4.4	--	Global Note representing $350 million principal amount of 6.375% Series B Senior Notes due 2013 with attached Guarantee (incorporated by reference to Exhibit 4.4 to Registration Statement on Form S-4, Reg. No. 333-102776, filed January 28, 2003).
4.5	--	Registration Rights Agreement dated as of January 22, 2003, among Enterprise Products Operating L.P., Enterprise Products Partners L.P. and the Initial Purchasers named therein (incorporated by reference to Exhibit 4.5 to Registration Statement on Form S-4, Reg. No. 333-102776, filed January 28, 2003).
4.6	--	Second Supplemental Indenture dated as of February 14, 2003, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wachovia Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 10-K filed March 31, 2003).
4.7	--	Rule 144 A Global Note representing $499.2 million principal amount of 6.875% Series A Senior Notes due 2033 with attached Guarantee (incorporated by reference to Exhibit 4.5 to Form 10-K filed March 31, 2003).
4.8	--	Regulation S Global Note representing $800,000 principal amount of 6.875% Series A Senior Notes due 2033 with attached Guarantee (incorporated by reference to Exhibit 4.6 to Form 10-K filed March 31, 2003).
4.9	--	Form of Global Note representing $500 million principal amount of 6.875% Series B Senior Notes due 2033 with attached Guarantee (incorporated by reference to Exhibit 4.8 to Form 10-K filed March 31, 2003).
4.10	--	Registration Rights Agreement dated as of February 14, 2003, among Enterprise Products Operating L.P., Enterprise Products Partners L.P. and the Initial Purchasers named therein (incorporated by reference to Exhibit 4.10 to Form 10-K filed March 31, 2003).
4.11	--	Global Note representing $350 million principal amount of 8.25% Senior Notes due 2005 (incorporated by reference to Exhibit 4.2 to Form 8-K filed March 10, 2000).
4.12	--	Global Note representing $450 million principal amount of 7.50% Senior Notes due 2011 (incorporated by reference to Exhibit 4.1 to Form 8-K filed January 25, 2001).
4.13	--	Form of Common Unit certificate (incorporated by reference to Exhibit 4.1 to Registration Statement on Form S-1/A; File No. 333-52537, filed July 21, 1998).
4.14	--	$250 Million Multi-Year Revolving Credit Facility dated as of November 17, 2000, among Enterprise Products Operating L.P., First Union National Bank, as Administrative Agent, Bank One, NA, as Documentation Agent, the Chase Manhattan Bank, as Syndication Agent, and the several banks from time to time parties thereto, with First Union Securities, Inc. and Chase Securities Inc. as Joint Lead Arrangers and Joint Book Managers (incorporated by reference to Exhibit 4.2 to Form 8-K filed January 24, 2001).
4.15	--	$150 Million 364-Day Revolving Credit Facility November 17, 2000, among Enterprise Products Operating L.P., First Union National Bank, as Administrative Agent, Bank One, NA, as Documentation Agent, the Chase Manhattan Bank, as Syndication Agent, and the several banks from time to time parties thereto, with First Union Securities, Inc. and Chase Securities Inc. as Joint Lead Arrangers and Joint Book Managers (incorporated by reference to Exhibit 4.3 to Form 8-K filed January 24, 2001).
4.16	--	Guaranty Agreement dated as of November 17, 2000, by Enterprise Products Partners L.P. in favor of First Union National Bank, as Administrative Agent, with respect to the $250 Million Multi-Year Revolving Credit Facility included as Exhibit 4.4 above (incorporated by reference to Exhibit 4.4 to Form 8-K filed January 24, 2001).
4.17	--	Guaranty Agreement dated as of November 17, 2000, by Enterprise Products Partners L.P. in favor of First Union National Bank, as Administrative Agent, with respect to the $150 Million 364-Day Revolving Credit Facility (incorporated by reference to Exhibit 4.5 to Form 8-K filed January 24, 2001).
4.18	--	First Amendment to Multi-Year Credit Facility dated April 19, 2001 (incorporated by reference to Exhibit 4.12 to Form 10-Q filed May 14, 2001).
4.19	--	Second Amendment to Multi-Year Revolving Credit Facility dated April 14, 2002 (incorporated by reference to Exhibit 4.14 to Form 10-Q filed May 14, 2002).
4.20	--	Third Amendment to Multi-Year Revolving Credit Facility dated July 31, 2002 (incorporated by reference to Exhibit 4.1 to Form 10-Q filed August 12, 2002).
4.21	--	Fourth Amendment to Multi-Year Revolving Credit Facility dated effective as of November 15, 2002 (incorporated by reference to Exhibit 4.21 to Form 10-Q filed November 13, 2002).
4.22	--	First Amendment to 364-Day Credit Facility dated November 6, 2001, effective as of November 16, 2001 (incorporated by reference to Exhibit 4.13 to Form 10-Q filed August 13, 2002).

4.23	--	Second Amendment to 364-Day Revolving Credit Facility dated April 24, 2002 (incorporated by reference to Exhibit 4.15 to Form 10-Q filed May 14, 2002).
4.24	--	Third Amendment to 364-Day Revolving Credit Facility dated July 31, 2002 (incorporated by reference to Exhibit 4.2 to Form 8-K filed August 12, 2002).
4.25	--	Contribution Agreement dated September 17, 1999 (incorporated by reference to Exhibit "B" to Schedule 13D filed September 27, 1999 by Tejas Energy, LLC).
4.26	--	Registration Rights Agreement dated September 17, 1999 (incorporated by reference to Exhibit "E" to Schedule 13D filed September 27, 1999 by Tejas Energy, LLC).
4.27	--	Unitholder Rights Agreement dated September 17, 1999 (incorporated by reference to Exhibit "C" to Schedule 13D filed September 27, 1999 by Tejas Energy, LLC).
10.1**	--	Sixth Amendment to Conveyance of Gas Processing Rights, dated as of March 1, 2003 among Enterprise Gas Processing, LLC, Shell Oil Company, Shell Exploration & Production Company, Shell Offshore Inc., Shell Consolidated Energy Resources Inc., Shell Land & Energy Company, Shell Frontier Oil & Gas Inc. and Shell Gulf of Mexico Inc. (incorporated by reference to Exhibit 10.1 to Form 8-K filed May 9, 2003).
10.2	--	Letter agreement dated April 9, 2003, relating to Sixth Amendment to Conveyance of Gas Processing Rights related to Exhibit 10.14 to this report (incorporated by reference to Exhibit 10.2 to Form 8-K filed May 9, 2003).
99.1#	--	Section 1350 Certifications

*	With respect to any exhibits incorporated by reference to any Exchange Act filings, the Commission file number for Enterprise Products Partners L.P. is 1-14323 and the Commission file number for Enterprise Products Operating L.P. is 333-93239-01.
**	Portions of this Exhibit have been omitted pursuant to a request for confidential treatment.
#	Filed with this report.

(b) Reports on Form 8-K.

January 10, 2003 filing, Item 5. On January 9, 2003, we entered into an underwriting agreement for the public offering of 12,750,000 Common Units, including 1,000,000 Common Units to be offered to four trusts established for the benefit of the children of Dan L. Duncan, the Chairman of the Board of our General Partner. Closing of the issuance and sale of the Common Units occurred on January 15, 2003.

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrants have duly caused this combined quarterly report on Form 10-Q to be signed on their behalf by the undersigned thereunto duly authorized, in the City of Houston, State of Texas on May 13, 2003.

		ENTERPRISE PRODUCTS PARTNERS L.P. (A Delaware Limited Partnership) ENTERPRISE PRODUCTS OPERATING L.P. (A Delaware Limited Partnership) By: Enterprise Products GP, LLC, as General Partner for both registrants



		By: /s/ Michael J. Knesek Name: Michael J. Knesek Title: Vice President, Controller, and Principal Accounting Officer of the General Partner

CERTIFICATION OF O.S. ANDRAS, PRINCIPAL EXECUTIVE OFFICER OF
ENTERPRISE PRODUCTS GP, LLC THE GENERAL PARTNER OF
ENTERPRISE PRODUCTS PARTNERS L.P.

I, O.S. Andras, the Principal Executive Officer of Enterprise Products GP, LLC, the General Partner of Enterprise Products Partners L.P., certify that:

I have reviewed this quarterly report on Form 10-Q of Enterprise Products Partners L.P.;

Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-13 and 15d-14) for the registrant and we have:

designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and audit committee of registrant’s board of directors (or persons performing the equivalent function):

all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

The registrant’s other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: May 13, 2003

		/s/ O.S. Andras
		Name: O.S. Andras
		Title: Principal Executive Officer of our General Partner, Enterprise Products GP, LLC

CERTIFICATION OF MICHAEL A. CREEL, PRINCIPAL FINANCIAL OFFICER OF
ENTERPRISE PRODUCTS GP, LLC THE GENERAL PARTNER OF
ENTERPRISE PRODUCTS PARTNERS L.P.

I, Michael A. Creel, the Principal Financial Officer of Enterprise Products GP, LLC, the General Partner of Enterprise Products Partners L.P., certify that:

I have reviewed this quarterly report on Form 10-Q of Enterprise Products Partners L.P.;

evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

Date: May 13, 2003

		/s/ Michael A. Creel
		Name: Michael A. Creel
		Title: Principal Financial Officer of our General Partner, Enterprise Products GP, LLC

CERTIFICATION OF O.S. ANDRAS, PRINCIPAL EXECUTIVE OFFICER OF
ENTERPRISE PRODUCTS GP, LLC THE GENERAL PARTNER OF
ENTERPRISE PRODUCTS OPERATING L.P.

I, O.S. Andras, the Principal Executive Officer of Enterprise Products GP, LLC, the General Partner of Enterprise Products Operating L.P., certify that:

I have reviewed this quarterly report on Form 10-Q of Enterprise Products Operating L.P.;

evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

Date: May 13, 2003

		/s/ O.S. Andras
		Name: O.S. Andras
		Title: Principal Executive Officer of our General Partner, Enterprise Products GP, LLC

CERTIFICATION OF MICHAEL A. CREEL, PRINCIPAL FINANCIAL OFFICER OF
ENTERPRISE PRODUCTS GP, LLC THE GENERAL PARTNER OF
ENTERPRISE PRODUCTS OPERATING L.P.

I, Michael A. Creel, the Principal Financial Officer of Enterprise Products GP, LLC, the General Partner of Enterprise Products Operating L.P., certify that:

I have reviewed this quarterly report on Form 10-Q of Enterprise Products Operating L.P.;

evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

Date: May 13, 2003

		/s/ Michael A. Creel
		Name: Michael A. Creel
		Title: Principal Financial Officer of our General Partner, Enterprise Products GP, LLC

EXHIBIT 99.1

CERTIFICATION OF O.S. ANDRAS, CHIEF EXECUTIVE OFFICER
OF ENTERPRISE PRODUCTS GP, LLC THE GENERAL PARTNER OF
ENTERPRISE PRODUCTS OPERATING L.P. AND ENTERPRISE PRODUCTS PARTNERS L.P.

In connection with this combined quarterly report of Enterprise Products Partners L.P. and Enterprise Products Operating L.P. (collectively, the “Registrants”) on Form 10-Q for the three months ending March 31, 2003 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, O.S. Andras, Chief Executive Officer of Enterprise Products GP, LLC, the General Partner of the Registrants, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Registrants.

/s/ O.S. Andras

Name: O.S. Andras

Title:       Chief Executive Officer of Enterprise Products GP, LLC
                on behalf of Enterprise Products Operating L.P. and
                Enterprise Products Partners L.P.

Date: May 13, 2003

A signed original of this written statement required by Section 906 has been provided to the Registrants and will be retained by the Registrants and furnished to Securities and Exchange Commission or its staff upon request.

CERTIFICATION OF MICHAEL A. CREEL, CHIEF FINANCIAL OFFICER
OF ENTERPRISE PRODUCTS GP, LLC THE GENERAL PARTNER OF
ENTERPRISE PRODUCTS OPERATING L.P. AND ENTERPRISE PRODUCTS PARTNERS L.P.

In connection with the combined quarterly report of Enterprise Products Partners L.P. and Enterprise Products Operating L.P. (collectively, the “Registrants”) on Form 10-Q for the three months ending March 31, 2003 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Michael A. Creel, Chief Financial Officer of Enterprise Products GP, LLC, the General Partner of the Registrants, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Registrants.

/s/ Michael A. Creel

Name: Michael A. Creel

Title:       Chief Financial Officer of Enterprise Products GP, LLC
                on behalf of Enterprise Products Operating L.P. and
                 Enterprise Products Partners L.P.

Date: May 13, 2003

Mont Belvieu Splitter III acquisition

MBA acquisition

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