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Form 10-Q, 1st Quarter, 2003

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.






EXPLANATORY NOTE

        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.
















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


1




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


2




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


3




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


4




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

1.      GENERAL

        In the opinion of Enterprise Products Partners L.P., the accompanying unaudited consolidated financial statements include all adjustments consisting of normal recurring accruals necessary for a fair presentation of its consolidated financial position as of 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.

2.      RECENTLY ISSUED ACCOUNTING STANDARDS

        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



5




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



6




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.

3.      BUSINESS ACQUISITIONS

        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:

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  

4.      INVENTORIES

        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  

        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.



7




5.      PROPERTY, PLANT AND EQUIPMENT

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

Estimated
Useful Life
in Years
 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.

6.      INVESTMENTS IN AND ADVANCES TO UNCONSOLIDATED AFFILIATES

        We own interests in a number of related businesses that are accounted for under the equity or cost 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:

Ownership
Percentage
 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


8




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.



9




        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.

7.      INTANGIBLE ASSETS AND GOODWILL

Intangible assets

        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 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  


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Goodwill

        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.

8.      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  

        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.



11




         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


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9.      CAPITAL STRUCTURE

        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 


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10.      SUPPLEMENTAL CASH FLOWS DISCLOSURE

        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.

11.      FINANCIAL INSTRUMENTS

        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

        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



14




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.

12.      SEGMENT INFORMATION

        We have five reportable operating segments: Pipelines, Fractionation, Processing, Octane Enhancement and Other. The reportable segments are generally organized according to the type of services rendered (or process employed) and products produced and/or sold, as applicable. The segments are regularly evaluated by the Chief Executive Officer of the General Partner. Pipelines consists of 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.

        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



15




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  


16




        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.



17




        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.

13.      PROVISION FOR INCOME TAXES

        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:

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  

        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.



18




14.      UNIT OPTION PLAN ACCOUNTING

        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 )

15. EARNINGS PER UNIT

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



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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 )


20




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


21




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


22




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


23




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







24




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

1.     GENERAL

        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.

        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. 333-93239-01) 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.

2.     RECENTLY ISSUED ACCOUNTING STANDARDS

        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.



25




        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.



26




3.     BUSINESS ACQUISITIONS

        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:

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  

4.     INVENTORIES

        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  

        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 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.



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5.     PROPERTY, PLANT AND EQUIPMENT

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

Estimated
Useful Life
in Years
 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.

6.     INVESTMENTS IN AND ADVANCES TO UNCONSOLIDATED AFFILIATES

        We own interests in a number of related businesses that are accounted for under the equity or cost 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:

Ownership
Percentage
 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  


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        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.



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        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.

7.     INTANGIBLE ASSETS AND GOODWILL

Intangible assets

        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  


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Goodwill

        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.

8.     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  

        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. 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.



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      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.

        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

        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
 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


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9.     CAPITAL STRUCTURE

        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.

10.     SUPPLEMENTAL CASH FLOWS DISCLOSURE

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 )

        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.



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11.     FINANCIAL INSTRUMENTS

        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

        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.

        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.



34




12.     SEGMENT INFORMATION

        We have five reportable operating segments: Pipelines, Fractionation, Processing, Octane Enhancement and Other. The reportable segments are generally organized according to the type of services rendered (or process employed) and products produced and/or sold, as applicable. The segments are regularly evaluated by the Chief Executive Officer of the General Partner. Pipelines consists of 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.

        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.



35




        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.
  
  

        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)     $ 85,311   $ (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  


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        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  

        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.



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        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.

13.     PROVISION FOR INCOME TAXES

        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:

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  

        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.



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14.     UNIT OPTION PLAN ACCOUNTING

        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) 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 )


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

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

        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.

Our results of operations

        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.



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        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.


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        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



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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



43




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”.

Our liquidity and capital resources

        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.



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        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



45




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



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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.



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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  

        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



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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, $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.



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Material contractual obligations

        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
 2006
through
2007
 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         

Related party transactions

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  


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         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.



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        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.

Recent accounting developments

        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 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.

        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 footnote 14 of the Notes to Unaudited Consolidated Financial Statements included elsewhere in this quarterly report.



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        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 footnote 8 of the Notes to Unaudited Consolidated Financial Statements included elsewhere in this quarterly report.

        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.

Our critical accounting policies

        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.



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        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



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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.

Other items

         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.



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Cautionary Statement regarding Forward-Looking Information and Risk Factors

        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.



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Item 3.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

        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.

        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



57




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.

Item 4.   CONTROLS AND PROCEDURES

        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.



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PART II. OTHER INFORMATION.

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

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

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

(a)(3) Exhibits.

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).


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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).


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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.



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SIGNATURES

        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















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SARBANES-OXLEY SECTION 302 CERTIFICATIONS

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:

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

  2. 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;

  3. 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;

  4. 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:

    a) 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;

    b) 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

    c) 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;

  5. 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):

    a) 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

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

  6. 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






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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:

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

  2. 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;

  3. 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;

  4. 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:

    a) 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;

    b) 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

    c) 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;

  5. 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):

    a) 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

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

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






64




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:

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

  2. 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;

  3. 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;

  4. 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:

    a) 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;

    b) 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

    c) 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;

  5. 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):

    a) 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

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

  6. 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






65




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:

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

  2. 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;

  3. 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;

  4. 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:

    a) 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;

    b) 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

    c) 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;

  5. 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):

    a) 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

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

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






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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

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.