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

FORM 10-Q

For the quarterly period ended March 31, 2004 or

For the transition period from _______ to _______.

Commission file number: 1-14323

ENTERPRISE PRODUCTS PARTNERS L.P.
(Exact name of Registrant as specified in its charters)

Registrant’s Telephone Number, including area code: (713) 880-6500

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

YES [X] NO [  ]

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

YES [X] NO [  ]

        There were 229,661,604 common units and 4,413,549 Class B special units of Enterprise Products Partners L.P. outstanding at May 5, 2003. Enterprise Products Partners L.P.’s Common Units trade on the New York Stock Exchange under symbol “EPD.”

ENTERPRISE PRODUCTS PARTNERS L.P.
TABLE OF CONTENTS

Glossary

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

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        For definitions of other commonly used terms used in our industry, please refer to the “Glossary” section of our 2003 annual report on Form 10-K (Commission File No. 1-14323).

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PART I.  ITEM 1.   FINANCIAL STATEMENTS.

ENTERPRISE PRODUCTS PARTNERS L.P.
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)

See Notes to Unaudited Condensed Consolidated Financial Statements

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

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

See Notes to Unaudited Condensed Consolidated Financial Statements

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

See Notes to Unaudited Condensed Consolidated Financial Statements

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

1.  GENERAL

        ENTERPRISE PRODUCTS PARTNERS L.P. including its consolidated subsidiaries is a publicly traded Delaware limited partnership listed on the NYSE under the ticker symbol “EPD.” Unless the context requires otherwise, references to “we,” “us,” “our,” “the Company” or “Enterprise” are intended to mean the consolidated business and operations of Enterprise Products Partners L.P. Certain abbreviated entity names and other capitalized and industry terms are defined within the glossary of this quarterly report on Form 10-Q.

        We were formed in April 1998 to own and operate certain NGL-related businesses of Enterprise Products Company (“EPCO”). We conduct substantially all of our business through a wholly owned subsidiary, Enterprise Products Operating L.P. ( our “Operating Partnership”). We are owned 98% by our limited partners and 2% by Enterprise Products GP, LLC (our “General Partner”). We and our General Partner are affiliates of EPCO.

        In the opinion of Enterprise, the accompanying unaudited consolidated financial statements include all adjustments consisting of normal recurring accruals necessary for a fair presentation. 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 GAAP have been condensed or omitted pursuant to the rules and regulations of the SEC. These unaudited financial statements should be read in conjunction with our annual report on Form 10-K (File No. 1-14323) for the year ended December 31, 2003.

        Essentially all of our assets, liabilities, revenues and expenses are recorded at the Operating Partnership level in our consolidated financial statements. We act as guarantor of certain of our Operating Partnership’s debt obligations. See Note 15 for condensed financial information of our Operating Partnership.

        The results of operations for the three month period ended March 31, 2004 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 reclassifications have been made to the prior year’s financial statements to conform to the current year presentation.

        CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE represents the effect of changing the method our majority owned BEF subsidiary uses to account for its planned major maintenance activities from the accrue-in-advance method to the expense-as-incurred method. These major maintenance costs, which typically result in facility shutdowns for 30 to 45 days, are principally comprised of amounts paid to third parties for materials, contract services, and other related items.

        We have historically used the expense-as-incurred method for planned major maintenance activities. The change in accounting for our majority owned BEF subsidiary conforms the Company’s accounting for all planned major maintenance costs and changes the method to better reflect expenses in the period incurred. As such, we believe the change is to a method that is preferable in the circumstances.

        The cumulative effect of this accounting change for years prior to 2004, which is shown separately in the Statement of Consolidated Operations and Comprehensive Income for 2004, resulted in a benefit of $7 million. See Note 14 for information regarding the effect of the accounting change on basic and diluted earnings per unit.

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        For the periods indicated, the following table shows pro forma net income and earnings per unit amounts assuming the accounting change was applied retroactively to January 1, 2003:

        UNIT OPTION PLAN ACCOUNTING is based on the intrinsic-value method described in APB No. 25, “Accounting for Stock Issued to Employees.” Under this method, no compensation expense is recorded related to options granted when the exercise price is equal to or greater than the market price of the underlying equity on the date of grant. In accordance with SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure,” we disclose the pro forma effect on our earnings as if the fair-value method of SFAS No. 123, “Accounting for Stock-Based Compensation” had been used instead of the intrinsic-value of APB No. 25. The effects of applying SFAS No. 123 in the following pro forma disclosure may not be indicative of future amounts as additional awards in future years are anticipated.

        The following table shows the pro forma effects for the periods indicated.

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2.  RECENTLY ISSUED ACCOUNTING STANDARDS

        FIN 46, “Consolidation of Variable Interest Entities – An Interpretation of ARB No. 51.” This interpretation of ARB No. 51 addresses requirements for accounting consolidation of a variable interest entity (“VIE”) with its primary beneficiary. In general, if an equity owner of a VIE meets certain criteria defined within FIN 46, the assets, liabilities and results of the activities of the VIE should be included in the consolidated financial statements of the owner. Our adoption of FIN 46 (as amended by FIN 46R) in 2003 has had no material effect on our consolidated financial statements.

        Due to the complexity of FIN 46 (as amended by FIN 46R and interpreted), the FASB is continuing to provide guidance regarding implementation issues. Since this guidance is still continuing, our conclusions regarding the application of this guidance may be altered. As a result, adjustments may be recorded in future periods as we adopt new FASB interpretations of FIN 46.

        EITF 03-16, “Accounting for Investments in Limited Liability Companies.” This accounting guidance requires that investments in limited liability companies (or “LLCs”) that have separate ownership accounts for each investor be accounted for similar to a limited partnership investment under SOP No. 78-9, “Accounting for Investments in Real Estate Ventures.” Under this new guidance (applicable for the period beginning July 1, 2004), investors would be required to apply the equity method of accounting to their investments at a much lower ownership threshold (typically any ownership interest greater than 3-5%) than the 20% threshold applied under APB Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock.”

        Currently, we account for our 13.1% investment in Venice Energy Services Company, LLC (“VESCO”) using the cost method. As a result, we have recognized dividend income from VESCO to the extent that we have received cash distributions from them. In accordance with the new accounting guidance in EITF 03-16, we will record a retroactive cumulative effect adjustment equal to the difference between (i) equity earnings from VESCO that would have been recorded using the equity method in prior periods and (ii) the dividend income from VESCO that was recorded using the cost method. We are currently studying the effect that EITF 03-16 will have on our investment in VESCO; however, based on information available, we do not believe that the implementation of this new accounting guidance will have a material effect on our financial statements.

3.  BUSINESS COMBINATIONS

        We did not enter into any business acquisitions during the first quarter of 2004; however, we are still expecting completion of the proposed merger with GulfTerra during the second half of 2004. In general, the proposed merger with GulfTerra involves the following three steps:

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        We anticipate that our obligations under Steps Two and Three of the proposed merger to pay El Paso $650 million will be financed initially with a short-term acquisition term loan and with borrowings under our revolving credit facilities.

        Our preliminary estimate of the total consideration for Steps One, Two and Three we would pay or issue is approximately $4.0 billion. For a period of three years following the closing of the proposed merger, at our request El Paso will provide certain support services to GulfTerra similar to those provided by El Paso prior to the closing of the merger. GulfTerra will reimburse El Paso for 110% of its direct costs for such services (excluding any overhead costs). El Paso will make transition support payments to us in annual amounts of $18 million, $15 million and $12 million for the first, second and third years of such period, respectively, payable in twelve equal monthly installments for each such year. These transition support payments are included in our preliminary estimate of total consideration.

        A number of conditions must be satisfied before we can complete the merger, including approval by the unitholders of both Enterprise and GulfTerra and the expiration or termination of applicable waiting periods under the Hart-Scott-Rodino Antitrust Improvements Act of 1974. While we cannot predict if and when all of the conditions of the proposed merger will be satisfied, we expect to complete the transaction in the second half of 2004.

        To review a copy of the merger agreement and related transaction documents, please read our Current Reports on Form 8-K filed with the SEC on December 15, 2003 and April 21, 2004.

4.  INVENTORIES

        Our inventories were as follows at the dates indicated:

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        Our regular trade (or “working”) inventory is comprised of inventories of natural gas, NGLs and petrochemical products that are available for sale or used in the provision of services. The forward sales inventory is comprised of segregated NGL volumes dedicated to the fulfillment of forward sales contracts. Both inventories are valued at the lower of average cost or market.

        Due to fluctuating conditions in the NGL, natural gas and petrochemical industry, we occasionally recognize lower of average cost or market (“LCM”) adjustments when the cost of our inventories exceed their net realizable value. These non-cash adjustments are charged to operating costs and expenses in the period they are recognized. For the three months ended March 31, 2004 and 2003, we recognized $4.2 million and $10.4 million, respectively, of LCM adjustments.

5.  PROPERTY, PLANT AND EQUIPMENT

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

        Depreciation expense for the three months ended March 31, 2004 and 2003 was $26.8 million and $24.1 million, respectively.

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6.  INVESTMENTS IN AND ADVANCES TO UNCONSOLIDATED AFFILIATES

        We own interests in a number of related businesses that are accounted for using the equity or cost methods. The investments in and advances to these unconsolidated affiliates are grouped according to the business segment to which they relate. For a general discussion of business segments, see Note 13. The following table shows our investments in and advances to unconsolidated affiliates at the dates indicated:

        Our initial investment in Promix, La Porte, Dixie, Tri-States, Neptune, Nemo and GulfTerra GP exceeded our share of the historical cost of the underlying net assets of such entities (“excess cost”). The excess cost amounts are reflected in our investments in and advances to unconsolidated affiliates for these entities. That portion of excess cost attributable to tangible or amortizable intangible assets of each entity is amortized over the estimated useful of the underlying asset(s) as a reduction in equity earnings from the investee. That portion of excess cost attributable to goodwill or non-amortizable intangible assets is not amortized. Equity method investments, including their associated excess cost amounts, are evaluated for impairment whenever events or changes in circumstances indicate that there is a loss in value of the investment which is an other than temporary decline. The following table summarizes our excess cost information at March 31, 2004 and December 31, 2003 by the business segment to which the unconsolidated affiliates relate:

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        The Pipelines section in the preceding table includes $337.5 million of excess cost attributable to goodwill, of which $328.2 million results from our December 2003 purchase of a 50% membership interest in GulfTerra GP. The allocation of the $328.2 million of excess cost to goodwill (which represents potential intangible assets, excess of fair values over carrying values of tangible assets, and remaining goodwill, if any) is preliminary pending completion of a fair value analysis which is expected to be completed during the last half of 2004. The table below shows the potential decrease in equity earnings from GulfTerra GP if certain amounts included in this excess cost were ultimately assigned to tangible or amortizable intangible assets. For purposes of calculating this sensitivity, we have applied the straight-line method of cost allocation over an estimated useful life of 20-years to various fair values.

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

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

        Expected change in accounting method for VESCO

        As a result of newly issued accounting guidance per EITF 03-16, we expect to change our method of accounting for VESCO from the cost method to the equity method on July 1, 2004. The VESCO investment consists of a 13.1% membership interest in a limited liability company that owns a natural gas processing plant, NGL fractionation facilities, storage assets and gas gathering pipelines located in south Louisiana.

7.  INTANGIBLE ASSETS AND GOODWILL

        Intangible assets

        The following table summarizes our amortizable intangible assets at the dates indicated:

        All of the intangible assets noted in the preceding table are subject to amortization. Amortization expense for the three months ended March 31, 2004 and 2003 was $3.8 million and $3.6 million, respectively. For the remainder of 2004, amortization expense attributable to these intangible assets is currently estimated at $11.5 million.

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        Goodwill

        The following table summarizes our goodwill amounts at March 31, 2004 and December 31, 2003 (excluding amounts included in the carrying value of unconsolidated affiliates – See Note 6).

8.  RELATED PARTY TRANSACTIONS

        Relationship with EPCO

        We have an extensive and ongoing relationship with EPCO. EPCO is controlled by Dan L. Duncan, who is also a director (and Chairman of the Board of Directors) of our General Partner. In addition, the remaining executive and other officers of our General Partner are employees of EPCO, including O.S. Andras who is President and Chief Executive Officer and a director of the General Partner. The principal business activity of the General Partner is to act as our managing partner. Collectively, EPCO and its affiliates owned 56.6% of Enterprise at March 31, 2004, which includes the 2% ownership interest of our General Partner (of which EPCO and its affiliates own 100%).

        We have no employees. All of our management, administrative and operating functions are performed by employees of EPCO pursuant to the Administrative Services Agreement. Prior to January 1, 2004, we reimbursed EPCO for the costs of its employees who performed operating functions for us and for costs related to certain of its management and administrative personnel hired in response to the expansion of our business. In addition, we paid EPCO a monthly fee for services provided by its other management and administrative employees. On January 1, 2004, the Administrative Services Agreement was amended to eliminate the fee portion of this reimbursement and to provide that we reimburse EPCO for all costs related to management or administrative support for us.

        We also have entered into an agreement with EPCO to provide trucking services to us for the transportation of NGLs and other products. In addition, we also buy from and sell to EPCO’s Canadian affiliate certain NGL products.

        Relationship with Shell

        We have a significant commercial relationship with Shell as a partner, customer and vendor. At March 31, 2004, Shell owned an approximate 18.3% equity interest in Enterprise. Shell is our largest customer. Our revenues from Shell primarily reflect the sale of NGL and petrochemical products to Shell and the fees we charge Shell for natural gas processing, 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 Shell.

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        Relationship with unconsolidated affiliates

        Our significant related party transactions with unconsolidated affiliates consist of the sale of natural gas to Evangeline, purchase of pipeline transportation services from Dixie and purchase of NGL storage, transportation and fractionation services from Promix. In addition, we sell natural gas to Promix.

        The following table summarizes our related party revenues, operating costs and expenses, and selling, general and administrative costs for the periods indicated:

9.  CAPITAL STRUCTURE

        Our common and Class B special units represent limited partner interests, which give the holders thereof the right to participate in distributions and to exercise the other rights or privileges available to them under our Third Amended and Restated Agreement of Limited Partnership (together with all amendments thereto, the “Partnership Agreement”). Our common units trade on the NYSE under the ticker symbol “EPD.” We are managed by our General Partner.

        Our partnership agreement generally authorizes us to issue an unlimited number of additional limited partner interests and other equity securities for such consideration and on such terms and conditions as may be established by the General Partner in its sole discretion (subject, under certain circumstances, to the approval of our unitholders). In February 2004, we issued 1,053,861 common units primarily in connection with our distribution reinvestment plan (“DRIP”) for which we received net proceeds of approximately $23.1 million, including our General Partner’s proportionate net capital contribution of $0.5 million. We used the proceeds from the February 2004 DRIP offering for general partnership purposes. See Note 16 for information regarding our May 2004 equity offering of 15,000,000 common units. During the first quarter of 2004, we reissued 240,983 treasury units at a cost of $5.1 million primarily due to obligations under EPCO employee unit option agreements and recorded a $0.3 million gain on the transactions.

        Unit History

        The following table details the outstanding balance of each class of units for the periods and at the dates indicated:

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10.  DEBT OBLIGATIONS

        Our debt consisted of the following at the dates indicated:

        Scheduled future maturities of long-term debt. We have long and short-term payment obligations under credit agreements such as our Senior Notes and revolving credit facilities. Scheduled future maturities of debt at March 31, 2004 were: $240 million due in 2004; $615 million due in 2005; $54 million due in 2010; $450 million due in 2011; $350 million due in 2013; and $500 million due in 2033. On May 5, 2004, we used $307 million in net proceeds from our May 2004 equity offering to repay the $225 million Interim Term Loan and approximately $80 million to temporarily reduce debt outstanding under our revolving credit facilities.

        Parent-Subsidiary guarantor relationships. We act as guarantor of the debt obligations of our Operating Partnership, with the exception of the Seminole Notes. If the Operating Partnership were to default on any debt we

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guarantee, we would be responsible for full repayment of that obligation. The Seminole Notes are unsecured obligations of Seminole Pipeline Company (of which we own an effective 78.4% of its capital stock).

        Covenants. We were in compliance with the various covenants of our debt agreements at March 31, 2004 and December 31, 2003.

        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, 2004:

11.  SUPPLEMENTAL CASH FLOWS DISCLOSURE

        The net effect of changes in operating assets and liabilities is as follows for the periods indicated:

        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 the physical purchase of natural gas made on the NYMEX exchange. The restricted cash balance at March 31, 2004 and December 31, 2003 was $8.0 million and $13.9 million, respectively.

        We recorded certain fair value amounts related to our interest rate hedging financial instruments during the first quarter of 2004 that affected various balance sheet accounts. For information regarding our financial instruments, see Note 12.

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12.  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. In general, the type of risks we attempt to hedge are those related 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.

        We recognize our financial instruments on the balance sheet as assets and liabilities based on the instrument’s fair value. Fair value is generally defined as the amount at which the financial instrument could be exchanged in a current transaction between willing parties, not in a forced or liquidation sale. The estimated fair values of our financial instruments have been determined using available market information and appropriate valuation techniques. We must use considerable judgment, however, in interpreting market data and developing these estimates. Accordingly, our fair value estimates are not necessarily indicative of the amounts that we could realize upon disposition of these instruments. The use of different market assumptions and/or estimation techniques could have a material effect on our estimates of fair value.

        Changes in the fair value of financial instrument contracts are recognized currently in earnings unless specific hedge accounting criteria are met. If the financial instruments meet those criteria, the instrument’s gains and losses offset the related results of the hedged item in the Statement of Operations and Comprehensive Income for a fair value hedge and are deferred in other comprehensive income for a cash flow hedge. Gains and losses on a cash flow hedge are reclassified into earnings when the forecasted transaction affects earnings. A contract designated as a hedge of an anticipated transaction that is no longer likely to occur is immediately recognized in earnings.

        To qualify as a hedge, the item to be hedged must expose us to price risk, interest rate risk or changes in fair value and the hedging instrument must reduce the exposure and meet the hedging requirements of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (as amended and interpreted). We must formally designate the financial instrument as a hedge and document and assess the effectiveness of the hedge at inception and on a quarterly basis. Any ineffectiveness is recorded into earnings immediately.

        Due to the complexity of SFAS No. 133 (as amended and interpreted), the FASB is continuing to provide guidance about implementation issues. Since this guidance is still continuing, our conclusions regarding the application of guidance may be altered. As a result, adjustments may be recorded in future periods as we adopt new FASB interpretations of this guidance.

        Interest rate risk hedging program

        Our interest rate exposure results from variable and fixed rate borrowings under debt agreements (see Note 10). We assess the cash flow risk related to interest rates by identifying and measuring changes in our interest rate exposures that may impact future cash flows and evaluating hedging opportunities to manage these risks. We use analytical techniques to measure our exposure to fluctuations in interest rates, including cash flow sensitivity analysis to estimate the expected impact of changes in interest rates on our future cash flows. The General Partner oversees the strategies associated with these financial risks and approves instruments that are appropriate for our requirements.

        We manage a portion of our interest rate risks by utilizing interest rate swaps and similar arrangements. The objective of entering into this type of arrangement is to manage debt service costs by converting a portion of fixed rate debt into variable rate debt or a portion of variable rate debt into fixed rate debt. In general, an interest rate swap requires one party to pay a fixed interest rate on a defined (or “notional”) amount while the other party pays a variable rate based on the same notional amount. The notional amount specified in an interest rate swap agreement does not represent exposure to credit loss. We monitor our positions and the credit ratings of counterparties. Management believes the risk of incurring a credit loss on these financial instruments is remote, and that if incurred, such losses would be minimal. We believe that it is prudent to maintain an appropriate balance of variable rate and fixed rate debt.

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        Fair value hedges – Interest rate swaps. On January 8, 2004, we entered into three interest rate swap agreements under which we exchanged the payment of fixed rate interest on a portion of principal outstanding under Senior Notes B and C for variable rate interest:

        We have designated these interest rate swaps as fair value hedges under SFAS No. 133 since they mitigate changes in the fair value of the underlying fixed rate debt. These agreements have a combined notional amount of $250 million and match the maturity dates of the underlying debt being hedged. Under the swap agreements, we pay the counterparty a variable rate based on LIBOR (plus an applicable margin) and receive back from the counterparty a fixed rate payment equal to the stated interest rate of the debt being hedged, based on the notional amounts for each swap agreement. We settle amounts receivable from or payable to the counterparties every six months (the “settlement period”).

        As effective fair value hedges, an increase in the fair value of these interest rate swaps is equally offset by an increase in fair value of the underlying hedged debt. The offsetting changes in fair value have no effect on current period interest expense. However, the interest rate swaps effectively converted a portion of the underlying fixed rate debt (i.e., the notional amounts hedged for Senior Notes B and C) into variable rate debt. As a result, interest expense will vary depending on the variable rates payable by us under terms of the swap agreements at the end of each settlement period. To the extent that the variable rate amount payable by us at the end of each settlement period is less than the fixed rate amount receivable from the counterparty, we will amortize the difference ratably to earnings as a reduction in interest expense over the settlement period. If the variable rate payable by us at the end of each settlement period is more than the fixed rate amount receivable from the counterparty, we would amortize this difference ratably to earnings as an increase in interest expense over the settlement period.

        Total fair value of the interest rate swaps at March 31, 2004 was approximately $6.4 million with an offsetting increase in fair value of the underlying debt. Interest expense in our Statement of Consolidated Operations and Comprehensive Income for the three months ended March 31, 2004 reflects a $1.7 million benefit from these swaps.

        Cash flow hedges – Forward starting interest rate swaps. On March 17, 2004, we entered into four forward starting interest rate swap transactions with original maturities of September 30, 2004. A forward starting swap is an agreement that effectively hedges the price on a specific U.S. treasury security for an established period of time. The purpose of these transactions was to effectively hedge the underlying U.S. treasury interest rate associated with our anticipated issuance of debt to refinance the existing debt of GulfTerra after the proposed merger is completed (see Note 3). The forward starting interest rate swaps have been designated as cash flow hedges under SFAS No. 133. The notional amount of the anticipated debt issuances was $2 billion.

        On April 23, 2004, we elected to terminate these financial instruments in order to monetize the then current value of the swaps and to reduce future debt service costs. As a result, we received $104.5 million in cash from the counterparties. This amount will be amortized over the life of the anticipated debt (when issued) as a reduction to interest expense. The following table shows the portfolio of forward starting swaps categorized by the term of the underlying anticipated debt offering:

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        The non-cash fair value of the forward starting interest rate swaps at March 31, 2004 was $17.0 million and was recorded as a component of AOCI in our Statement of Consolidated Partners’ Equity and as an addition to comprehensive income in our Statement of Consolidated Operations and Comprehensive Income for the three months ended March 31, 2004. When the $104.5 million cash settlement is recorded during the second quarter of 2004, it will replace the $17.0 non-cash fair value amount in AOCI and comprehensive income.

        Commodity risk hedging program

        The prices of natural gas, NGLs, petrochemical products and MTBE are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control. In order to manage the risks associated with our Processing segment activities, we may enter into various commodity financial instruments. The primary purpose of these risk management activities is to hedge our exposure to price risks associated with natural gas, NGL production and inventories, firm commitments and certain anticipated transactions. The commodity financial instruments we utilize may be settled in cash or with another financial instrument.

        We do not hedge our exposure related to MTBE price risks. In addition, we generally do not hedge risks associated with the petrochemical marketing activities that are part of our Fractionation segment. In our Pipelines segment, we utilize a limited number of commodity financial instruments to manage the price Acadian Gas charges or pays certain of its customers for natural gas. Lastly, we do not employ commodity financial instruments in our fee-based marketing business classified under the Other segment.

        We have adopted a policy to govern our use of commodity financial instruments to manage the risks of our natural gas and NGL businesses. The objective of this policy is to assist us in achieving our profitability goals while maintaining a portfolio with an acceptable level of risk, defined as remaining within the position limits established by the General Partner. We enter into risk management transactions to manage price risk, basis risk, physical risk or other risks related to our commodity positions on both a short-term (less than 30 days) and long-term basis, not to exceed 24 months. The General Partner oversees our strategies associated with physical and financial risks (such as those mentioned previously), approves specific activities subject to the policy (including authorized products, instruments and markets) and establishes specific guidelines and procedures for implementing and ensuring compliance with the policy.

        Our commodity financial instruments may not qualify for hedge accounting treatment under the specific guidelines of SFAS No. 133 (as amended and interpreted). In those situations where the financial instrument does not qualify for hedge accounting treatment, the instrument is accounted for using mark-to-market accounting, which results in a degree of non-cash earnings volatility that is dependent upon changes in the commodity prices underlying these financial instruments. Even though these financial instruments may not qualify for hedge accounting treatment under SFAS No. 133, we view such contracts as hedges since this was the intent when we entered into such positions. Upon entering into such positions, our expectation is that the economic performance of these instruments will mitigate (or offset) the commodity risk being addressed. The specific accounting for these contracts; however, is consistent with the requirements of SFAS No. 133.

        The fair value of our commodity financial instrument portfolio at March 31, 2004 and December 31, 2003 and the results of our commodity hedging activities for the three months ended March 31, 2004 and 2003 were both

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nominal amounts. During both the first quarter of 2004 and the first quarter of 2003, we utilized a limited number of commodity financial instruments.

13.  SEGMENT INFORMATION

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

        We have five reportable business (or operating) segments: Pipelines, Fractionation, Processing, Octane Enhancement and Other. Our 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 CEO 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 propylene fractionation services. Processing includes the natural gas processing business and its related NGL marketing activities. Octane Enhancement represents our investment in a facility that produces motor gasoline additives to enhance octane (currently producing MTBE and isobutylene). The Other business 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. Gross operating margin (either in total or by individual segment) is an important performance measure of the core profitability of our operations. This measure forms the basis of our internal financial reporting and is used by senior management in deciding how to allocate capital resources among business segments. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating segment results. The GAAP measure most directly comparable to total segment gross operating margin is operating income. Our non-GAAP financial measure of total segment gross operating margin should not be considered as an alternative to GAAP operating income.

        We define total segment gross operating margin as operating income before: (1) depreciation and amortization expense; (2) operating lease expenses for which we do 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. Gross operating margin by segment is calculated by subtracting segment operating costs and expenses (net of the adjustments noted above) from segment revenues, with both segment totals before the elimination of intercompany transactions.

        Segment revenues and expenses include intersegment and intrasegment transactions, which are generally based on transactions made at market-related rates. Our consolidated revenues reflect the elimination of all material intercompany (both intersegment and intrasegment) transactions.

        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 those of 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 example, we use the Promix NGL fractionator to process a portion of the mixed NGLs extracted by our gas plants. Another example is our use of the Dixie pipeline to transport propane sold to customers through our NGL marketing activities. See Note 8 for additional information regarding our related party relationships with unconsolidated affiliates.

        Our revenues are derived from a wide customer base. All consolidated revenues were earned in the United States. Most of our plant-based operations are located primarily along the western Gulf Coast in Texas, Louisiana and Mississippi. Our pipelines and related operations are in a number of regions of the United States including the

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Gulf of Mexico offshore Louisiana (certain natural gas pipelines); the south and southeastern United States (primarily in the Texas, Louisiana and Mississippi regions); and certain regions of the central and western United States. The Mid-America pipeline system extends from the Hobbs hub located on the Texas-New Mexico border to Wyoming along one route and to Minnesota, Wisconsin and Illinois along other routes. Our marketing activities are headquartered in Houston, Texas at our main office and service customers in a number of regions in the United States including the Gulf Coast, West Coast and Mid-Continent areas.

        Consolidated property, plant and equipment and investments in and advances to unconsolidated affiliates are allocated to each segment on the basis of each asset’s or investment’s principal operations. The principal reconciling item between consolidated property, plant and equipment and segment property is construction-in-progress. Segment property represents those facilities and projects that contribute to gross operating margin and is net of accumulated depreciation on these assets. Since assets under construction do not generally contribute to segment gross operating margin, these assets are not included in the operating segment totals until they are deemed operational. Consolidated intangible assets and goodwill are allocated to the segments based on the classification of the assets to which they relate.

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