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The information in this preliminary prospectus supplement is not complete and may be changed. This preliminary prospectus supplement and the attached prospectus are not an offer to sell these securities, and we are not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

      Filed Pursuant to Rule 424(b)(3)

Registration No. 333-102778
333-102778-01
SUBJECT TO COMPLETION, DATED AUGUST 2, 2004

PRELIMINARY PROSPECTUS SUPPLEMENT

(To Prospectus Dated April 21, 2003)

(ENTERPRISE PRODUCTS PARTNERS L.P. LOGO)

13,750,000 Common Units

Enterprise Products Partners L.P.

$                           per common unit


     We are selling 13,750,000 common units, including an aggregate of 1,751,500 common units to be offered to an entity controlled by Dan L. Duncan, the Chairman of our general partner, to O.S. Andras, the President and Chief Executive Officer of our general partner, and to two other members of our senior management team. We have granted the underwriters an option to purchase up to 2,062,500 additional common units to cover over-allotments.

     Our common units are listed on the New York Stock Exchange under the symbol “EPD.” The last reported sales price of our common units on the New York Stock Exchange on July 29, 2004 was $20.90 per common unit.

     Investing in our common units involves risk. See “Risk Factors” beginning on page S-26 of this prospectus supplement and on page 2 of the accompanying prospectus.


     Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus supplement or the accompanying prospectus is truthful or complete. Any representation to the contrary is a criminal offense.


                 
Per Common Unit Total


Public Offering Price
  $       $    
Underwriting Discount(1)
  $       $    
Proceeds to Enterprise Products Partners (before expenses)
  $       $    


(1)  The underwriters will receive no discount or commission on the sale of an aggregate of 1,751,500 common units to an entity controlled by Mr. Duncan, to Mr. Andras and to two other members of our senior management team.

     The underwriters expect to deliver the common units on or about                  , 2004.


Joint Book-Running Managers

Citigroup Morgan Stanley


Lehman Brothers
  UBS Investment Bank
  Wachovia Securities
  A.G. Edwards
  Merrill Lynch & Co.
  RBC Capital Markets
  Sanders Morris Harris
  JP Morgan
  KeyBanc Capital Markets

            , 2004


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[ENTERPRISE PRODUCTS PARTNERS SYSTEM MAP, GULFTERRA SYSTEM MAP

AND COMBINED COMPANY SYSTEM MAP APPEAR HERE]


      This document is in two parts. The first part is this prospectus supplement, which describes the terms of this offering of common units. The second part is the accompanying prospectus, which gives more general information, some of which may not apply to the common units. If the description of the common unit offering varies between this prospectus supplement and the accompanying prospectus, you should rely on the information in this prospectus supplement.

      You should rely only on the information contained or incorporated by reference in this prospectus supplement or the accompanying prospectus. We have not authorized anyone to provide you with additional or different information. We are not making an offer to sell these securities in any state where the offer is not permitted. You should not assume that the information contained in this prospectus supplement or the accompanying prospectus is accurate as of any date other than the date on the front of these documents or that any information we have incorporated by reference is accurate as of any date other than the date of the document incorporated by reference. Our business, financial condition, results of operations and prospects may have changed since these dates.

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SUMMARY

      This summary highlights information from this prospectus supplement and the accompanying prospectus to help you understand the common units. It does not contain all of the information that is important to you. You should read carefully the entire prospectus supplement, the accompanying prospectus, the documents incorporated by reference and the other documents to which we refer for a more complete understanding of this offering. You should read “Risk Factors” beginning on page S-26 of this prospectus supplement and on page 2 of the accompanying prospectus for more information about important risks that you should consider before making a decision to purchase common units in this offering.

      The information presented in this prospectus supplement assumes that the underwriters do not exercise their over-allotment option. All references in this prospectus supplement and the accompanying prospectus to number of units, earnings per unit or unit price give effect to our two-for-one unit split on May 15, 2002. “Our,” “we,” “us” and “Enterprise” as used in this prospectus supplement and the accompanying prospectus refer solely to Enterprise Products Partners L.P. and its wholly-owned subsidiaries, and do not refer to GulfTerra Energy Partners, L.P. “GulfTerra” as used in this prospectus supplement refers to GulfTerra Energy Partners, L.P. and its wholly-owned subsidiaries, and “El Paso Corporation” as used in this prospectus supplement refers to El Paso Corporation and its wholly-owned subsidiaries. References to the “combined company” in this prospectus supplement mean Enterprise Products Partners L.P. and its wholly-owned subsidiaries following the closing of our merger with GulfTerra and related transactions.

      Unless otherwise indicated, pro forma financial results presented in this prospectus supplement give effect to the completion of our merger with GulfTerra, the concurrent purchase from El Paso Corporation of the related South Texas midstream assets, our May 2004 common unit offering, the issuance of common units pursuant to our distribution reinvestment plan, or DRIP, in May 2004, the conversion of the 4,413,549 Class B special units into an equal number of our common units on July 29, 2004 and this offering. For a complete description of the adjustments we have made to arrive at the pro forma financial measures that we present in this prospectus supplement, please read our unaudited pro forma financial statements included elsewhere in this prospectus supplement.

Enterprise Products Partners L.P.

      We are a leading North American midstream energy company that provides a wide range of services to producers and consumers of natural gas and natural gas liquids, or NGLs. NGLs are used by the petrochemical and refining industries to produce plastics, motor gasoline and other industrial and consumer products and also are used as residential, agricultural and industrial fuels. Our existing asset platform in the Gulf Coast region of the United States, combined with our Mid-America and Seminole pipeline systems acquired in 2002, creates the only integrated natural gas and NGL transportation, fractionation, processing, storage and import/export network in North America. We provide integrated services to our customers and generate fee-based cash flow from multiple sources along our natural gas and NGL “value chain.” Our principal executive offices are located at 2727 North Loop West, Houston, Texas 77008, and our phone number is (713) 880-6500.

      On December 15, 2003, we entered into a series of agreements with El Paso Corporation and GulfTerra Energy Partners, L.P. pursuant to which:

  •  we purchased a 50% membership interest in GulfTerra’s general partner for $425 million;
 
  •  we agreed to merge with GulfTerra; and
 
  •  we agreed to purchase from El Paso Corporation approximately $150 million of midstream assets located in South Texas and related inventories that are closely related to GulfTerra’s operations.

      GulfTerra is a master limited partnership formerly known as El Paso Energy Partners, L.P. and is principally engaged in activities in the midstream energy sector. GulfTerra’s common units are traded on the New York Stock Exchange under the symbol “GTM.”

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      On July 29, 2004, we held a special meeting of our unitholders at which our unitholders approved the issuance of our common units pursuant to the merger agreement and approved the conversion of our 4,413,549 Class B special units into an equal number of our common units. The conversion of the Class B special units into an equal number of our common units occurred immediately following this approval. On the same day, GulfTerra held a special meeting of its unitholders at which GulfTerra’s unitholders approved and adopted the merger agreement. For a discussion of the remaining conditions to the effectiveness of the merger, please read “— Conditions to the Effectiveness of the Merger and Related Transactions.”

      For the year ended December 31, 2003, we had revenues of $5.3 billion, operating income of $248.1 million and net income of $104.5 million. On a pro forma basis for the year ended December 31, 2003, we had revenues of $7.2 billion, operating income of $582.8 million and net income of $274.3 million. For the three months ended March 31, 2004, we had revenues of $1.7 billion, operating income of $87.3 million and net income of $58.5 million. On a pro forma basis for the three months ended March 31, 2004, we had revenues of $2.1 billion, operating income of $174.4 million and net income of $111.7 million. Please read “— Our Other Recent Developments — Second Quarter 2004 Unaudited Results” for additional summarized financial information.

Our Business Segments

      Pipelines. Our Pipelines segment includes approximately 14,200 miles of NGL, petrochemical and natural gas pipelines located primarily in the Rocky Mountain, Mid-Continent and Gulf Coast regions of the United States. This segment also includes our storage and import/export terminalling businesses.

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

      Processing. Our Processing segment is comprised of our natural gas processing business and related NGL marketing activities. At the core of our natural gas processing business are 12 gas plants, located primarily in south Louisiana, that process raw natural gas into a product that meets pipeline and industry specifications by removing NGLs and impurities. In connection with our processing businesses, we receive a portion of the NGL production from our gas plants. This equity NGL production, together with the NGLs we purchase, supports the NGL marketing activities included in this operating segment.

      Octane Enhancement and Other. Our Octane Enhancement segment consists of a 66.6% equity investment in Belvieu Environmental Fuels L.P., or BEF, which owns a facility that produces motor gasoline additives used to enhance octane. Our Other segment consists primarily of fee-based marketing services and unallocated cost of services that support our operations and business activities.

GulfTerra’s Business Segments

      Natural Gas Pipelines and Plants. GulfTerra owns or has interests in natural gas pipeline systems extending over 15,650 miles. These pipeline systems include natural gas gathering systems onshore in Alabama, Colorado, Louisiana, Mississippi, New Mexico and Texas and offshore in some of the most active drilling and development regions in the Gulf of Mexico. GulfTerra also owns interests in five processing and treating plants in New Mexico, Texas and Colorado.

      Oil and NGL Logistics. GulfTerra owns over 1,000 miles of intrastate NGL gathering and transportation pipelines and four fractionation plants in Texas, owns interests in four offshore oil pipeline systems, which extend over 380 miles, is constructing the 390-mile Cameron Highway Oil Pipeline, owns a 3.3 million barrel, or MMBbl, propane storage business in Mississippi and owns or leases NGL storage facilities in Louisiana and Texas with aggregate capacity of approximately 21.3 MMBbls.

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      Natural Gas Storage. GulfTerra owns two salt dome natural gas storage facilities in Mississippi that have a combined current working capacity of 13.5 billion cubic feet, or Bcf, and are capable of delivering in excess of 1.2 billion cubic feet per day, or Bcf/d, of natural gas into five interstate pipeline systems. In addition, GulfTerra has the exclusive right to use a natural gas storage facility in Wharton County, Texas under an operating lease that expires in January 2008. This facility has a working gas capacity of 6.4 Bcf and a maximum withdrawal capacity of 800 million cubic feet per day, or MMcf/d, of natural gas.

      Platform Services. GulfTerra has interests in seven multi-purpose offshore hub platforms in the Gulf of Mexico, including the recently completed Marco Polo tension leg platform. These platforms were specifically designed to be used as deepwater hubs and production handling and pipeline maintenance facilities. Many of GulfTerra’s offshore natural gas and oil pipelines utilize these platforms.

      Other Assets. GulfTerra owns interests in four oil and natural gas properties located in waters offshore of Louisiana. Production is gathered, transported, and processed through GulfTerra’s pipeline systems and platform facilities, and sold to various third parties and subsidiaries of El Paso Corporation.

Our Reasons for the Merger

      The board of directors of our general partner considered various factors in pursuing the proposed merger with GulfTerra and the related transactions, including the following:

  •  Significant increases to the diversity and scale of our operations. We believe that the merger will enable us to have a more balanced business mix and to expand our geographic presence to areas where we currently have no significant operations, such as the San Juan and Permian Basins.
 
  •  Greater cash flow stability. After the merger, we believe that a higher percentage of our income will be generated from fee-based businesses. Additionally, GulfTerra’s operations currently benefit from higher natural gas prices, and are expected to provide a natural hedge to our NGL business, which generally benefits from lower or stable natural gas prices.
 
  •  Incremental growth opportunities. GulfTerra has significant organic growth projects, and the combination of our operations with GulfTerra’s operations is expected to provide incremental growth opportunities.
 
  •  Potential cost savings. We expect that the annual operating costs of the combined company will be lower than the aggregate pro forma historical costs of our company and GulfTerra, and we expect that the combined company will have annual interest expense savings.
 
  •  Long-term accretion to distributable cash flow per unit to our unitholders. In connection with the proposed merger, we agreed, subject to the terms of our partnership agreement, to increase our quarterly cash distribution on our common units to at least $0.395 per unit, or $1.58 per unit on an annual basis, commencing with the first regular quarterly distribution after the merger closes. Our unitholders are expected to benefit from accretion to distributable cash flow per unit, which is the basis for the contracted distribution increase. Additionally, the accretion to distributable cash flow per unit could allow us to further increase future distributions to our unitholders.

Business Strategy of the Combined Company

      The business strategy of the combined company will be to:

  •  capitalize on expected increases in natural gas, NGL and oil production resulting from development activities in the Rocky Mountain region and in the deepwater and continental shelf areas of the Gulf of Mexico;
 
  •  maintain a balanced and diversified portfolio of midstream energy assets and expand this asset base through organic development projects and accretive acquisitions of complementary midstream energy assets;

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  •  share capital costs and risks through joint ventures or alliances with strategic partners that will provide the raw materials for these projects or purchase the projects’ end products; and
 
  •  increase fee-based cash flows by investing in pipelines and other fee-based businesses and de-emphasize commodity-based activities.

Competitive Strengths of the Combined Company

      We believe that the combined company will have the following competitive strengths:

      Large-Scale, Integrated Platform of Assets in Strategic Locations. The proposed merger will further expand our integrated natural gas and NGL transportation, fractionation, processing, storage and import/export network in North America. The operations of the combined company will be strategically located to serve the major supply basins for NGL-rich natural gas, the major NGL storage hubs in North America and international markets. We believe that the combined company’s location in these markets will provide better access to natural gas, NGL and petrochemical supply volumes, anticipated demand growth and business expansion opportunities. The geographic presence of the combined company will be strengthened in areas where we currently have no significant operations, such as the San Juan and Permian Basins.

      Strategic Platform for Continued Expansion and Distribution Growth. We believe that GulfTerra has significant development opportunities, and that the combination of our operations and GulfTerra’s operations will provide the combined company with incremental growth opportunities for both onshore and offshore projects. Many of the combined company’s assets will have additional capacity that can accommodate increased volumes at low incremental cost. We expect that taking advantage of these growth opportunities will increase the combined company’s cash flow from operations and result in accretion to distributable cash flow per unit.

      Enhanced Access to Capital. We believe that over the long term the combined company will have a lower cost of capital than many of its competitors, which will enable it to compete more effectively in acquiring assets and expanding its systems. In December 2002, we amended our partnership agreement to eliminate our general partner’s right to receive 50% of cash distributions with respect to that portion of quarterly cash distributions that exceed $0.392 per unit. We believe our unitholders will enjoy an advantage over unitholders of many other publicly traded partnerships whose general partners are either already sharing 50% of the cash distribution increases pursuant to their incentive distribution rights or are near the threshold for the effectiveness of their 50% incentive distribution rights.

      Relationships with Major Oil, Natural Gas and Petrochemical Companies. Both we and GulfTerra have long-term relationships with many of our suppliers and customers, and we believe that the combined company will continue to benefit from these relationships. The combined company will jointly own facilities with many of its customers who will either provide raw materials to or consume the end products from the combined company’s facilities. These joint venture partners include major oil, natural gas and petrochemical companies, including BP, Burlington Resources, ChevronTexaco, Dow Chemical, Duke Energy Field Services, El Paso Corporation, ExxonMobil, Marathon and Shell.

      Cash-Flow Stability Through Fee-Based Businesses and Balanced Asset Mix. The combined company’s cash flow will be derived primarily from fee-based businesses whose revenue will not be directly affected by volatility in energy commodity prices. We expect that the diversified asset portfolio of the combined company will provide operating income from a broader range of sources than our current operations. Additionally, GulfTerra’s operations currently benefit from higher natural gas prices and will provide a natural hedge to our NGL business, which generally benefits from stable or lower natural gas prices.

      Operating Cost Advantage. We believe that the combined company’s operating costs, especially for its large-scale facilities, will be competitive with, or lower than, those associated with the combined company’s competitors. We expect that the combined company’s annual operating costs will be lower than our and GulfTerra’s aggregate historical costs and expect that the combined company will achieve annual interest expense savings through its strategy for management of its debt obligations.

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      Experienced Operator and Management Team whose Interests are Aligned with Those of Our Unitholders. Both we and GulfTerra have historically operated our largest natural gas processing and fractionation facilities and most of our pipelines. As the leading provider of NGL-related services, we have established a reputation in the industry as a reliable and cost-effective operator. After the closing of the merger, affiliates of Dan L. Duncan, our co-founder and the chairman of our general partner, will own a 90.1% membership interest in our general partner, and El Paso Corporation will own a 9.9% membership interest in our general partner. In addition, after giving effect to this offering and the merger, Mr. Duncan and his affiliates will collectively own an approximate 34.7% limited partner interest in us. The persons whom we expect will serve as senior executive officers of the combined company, Dan L. Duncan, O.S. Andras and Robert G. Phillips, average more than 35 years of industry experience.

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The Offering

 
Common units offered 13,750,000 common units; or
 
15,812,500 common units if the underwriters exercise their over-allotment option in full.
 
Units outstanding after this offering 251,924,894 common units, or 253,987,394 common units if the underwriters exercise their over-allotment option in full, including 4,413,549 common units that were issued upon conversion of all of our 4,413,549 Class B special units following approval of the conversion by our common unitholders at the special meeting of our common unitholders held on July 29, 2004.
 
Use of proceeds We will use the net proceeds from this offering, including our general partner’s proportionate capital contribution, to temporarily reduce borrowings under our multi-year revolving credit facility and to fund a portion of the purchase price at the closing of the Step Two and Step Three merger transactions, or, if the merger does not close, for working capital purposes or for future acquisitions. For more information about the Step Two and Step Three Merger Transactions, please read “— The Merger and Related Transactions.”
 
Cash distributions Under our partnership agreement, we must distribute all of our cash on hand as of the end of each quarter, less reserves established by our general partner. We refer to this cash as “available cash,” and we define its meaning in our partnership agreement.
 
On May 12, 2004, we paid a quarterly cash distribution for the first quarter of 2004 of $0.3725 per unit, or $1.49 per unit on an annualized basis. On July 14, 2004, our general partner declared a quarterly cash distribution for the second quarter of 2004 of $0.3725 per unit, or $1.49 per unit on an annualized basis. The distribution will be paid on August 6, 2004 to unitholders of record at the close of business on July 30, 2004. Holders of units purchased in this offering will not be entitled to receive this distribution.
 
When quarterly cash distributions exceed $0.253 per unit in any quarter, our general partner receives a higher percentage of the cash distributed in excess of that amount, in increasing percentages up to 25% if the quarterly cash distributions exceed $0.3085 per unit. For a description of our cash distribution policy, please read “Cash Distribution Policy” in the accompanying prospectus.
 
We have agreed, subject to the terms of our partnership agreement, to increase the quarterly cash distribution for the first regular quarterly distribution after the closing of the merger to at least $0.395 per unit, or $1.58 per unit on an annualized basis.
 
Estimated ratio of taxable income to distributions We estimate that if you own the common units you purchase in this offering through December 31, 2006, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be less than 10% of the cash distributed with respect to that period. We expect this estimate to remain the same following the GulfTerra merger. Please read “Tax Consequences” in this prospectus supplement for the basis of this estimate.
 
New York Stock Exchange symbol EPD

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Risk Factors

      There are risks associated with the merger and the related transactions, risks associated with the combined company’s business and risks associated with our business. You should consider carefully the risk factors beginning on page S-26 of this prospectus supplement and beginning on page 2 of the accompanying prospectus before making a decision to purchase common units in this offering.

The Merger and Related Transactions

      Under the definitive agreements relating to the merger, the merger is to occur in several interrelated transactions described below. Step One occurred on December 15, 2003, concurrent with the announcement of the proposed merger and related transactions. With respect to Step Two and Step Three, we have entered into binding agreements subject to certain standard conditions. Please read “— Conditions to the Effectiveness of the Merger and Related Transactions.”

      Step One: Acquisition of 50% Membership Interest in GulfTerra’s General Partner. On December 15, 2003, we purchased a 50% membership interest in GulfTerra’s general partner for $425 million from El Paso Corporation, resulting in GulfTerra’s general partner now being 50% owned by El Paso Corporation and 50% owned by us. Our interest in GulfTerra’s general partner entitles us to receive, subject to the terms of GulfTerra’s general partner’s limited liability company agreement, quarterly distributions equal to 50% of all available cash held by GulfTerra’s general partner. At GulfTerra’s current distribution rate of $2.84 per unit annually, GulfTerra’s general partner is entitled to receive annual distributions of approximately $85 million. Our 50% membership interest in GulfTerra’s general partner would entitle us to receive approximately $42.5 million annually, assuming that no portion of such annual cash distribution is retained by GulfTerra’s general partner under its limited liability company agreement to establish cash reserves. El Paso Corporation serves as the managing member of the GulfTerra general partner, and our rights are limited to protective consent rights on specified material transactions affecting GulfTerra or its general partner or the rights and preferences associated with our membership interest in GulfTerra’s general partner. We will continue to own this 50% membership interest in GulfTerra’s general partner even if the merger does not close. We financed the $425 million Step One purchase through a combination of a $225 million interim term loan, which we repaid in full with a portion of the proceeds of our May 2004 common unit offering, and $200 million borrowed under our 364-day revolving credit facility.

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      The following organizational chart depicts our current organizational structure and our ownership immediately after giving effect to this offering.

(GRAPH)


(1)  Includes units held by affiliates of EPCO, Inc. (formerly Enterprise Products Company), or EPCO, as well as 4,413,549 common units that were issued upon the conversion of all of our 4,413,549 Class B special units on July 29, 2004.
 
(2)  The ownership of limited partner interests in GulfTerra is as of June 30, 2004.
 
(3)  Does not include any of GulfTerra’s common units that may be issued upon conversion of GulfTerra’s 25 remaining Series F1 convertible units and 80 Series F2 convertible units prior to the closing of the merger.

      The table below shows the current ownership of our common units and the ownership of our common units after giving effect to this offering.

                                   
Current Ownership Ownership After the Offering


Units Percentage Interest Units Percentage Interest




Public common units
    72,600,340       29.9 %     84,850,340       33.0 %
EPCO common units(1)
    124,574,554       51.2 %     126,074,554       49.0 %
Shell common units
    41,000,000       16.9 %     41,000,000       16.0 %
General partner interest
          2.0 %           2.0 %
     
     
     
     
 
 
Total
    238,174,894       100.0 %     251,924,894       100.0 %
     
     
     
     
 


(1)  Includes common units held by affiliates of EPCO, as well as 4,413,549 common units that were issued upon the conversion of all of our 4,413,549 Class B special units on July 29, 2004.

      Step Two: The Merger and Related Transactions. Immediately prior to the closing of the merger, El Paso Corporation will contribute its 50% membership interest in GulfTerra’s general partner to our general partner in exchange for a 9.9% membership interest in our general partner and $370 million in cash from our general partner. Our general partner will then make a capital contribution of that 50% membership interest in GulfTerra’s general partner to us (without increasing its interest in our earnings or cash distributions). In

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addition, we will purchase from El Paso Corporation all 10,937,500 outstanding GulfTerra Series C Units and 2,876,620 GulfTerra common units for $500 million, none of which will be converted into the right to receive our common units in the merger. We expect to use a portion of the net proceeds of this offering to fund a portion of this purchase, and we expect to finance the remaining portion of the purchase through one or more issuances of debt securities, a temporary acquisition term facility, borrowings under our revolving credit facilities, or through any combination of the foregoing. The size, terms and timing of any future debt offerings are subject to market conditions that are beyond our control. The purchase price of approximately $36.19 per unit is equal to 90% of the average closing prices of the GulfTerra common units on the New York Stock Exchange for the 20 trading days ending on December 12, 2003 (the last full trading day before the proposed merger was announced). Under the merger agreement, the remaining 7,433,425 GulfTerra common units owned by El Paso Corporation will be converted into the right to receive 13,454,499 Enterprise common units.

      Pursuant to the merger agreement, a subsidiary of our company will merge with and into GulfTerra. GulfTerra will survive the merger and become our wholly-owned subsidiary, and GulfTerra’s outstanding common units, other than the common units purchased by us prior to the merger, will be converted into the right to receive our common units. Each GulfTerra common unitholder will be entitled to receive 1.81 of our common units for each GulfTerra common unit that the unitholder owns at the effective time of the merger. Instead of receiving fractional common units, GulfTerra common unitholders will receive cash from us in an amount determined under the merger agreement. We have agreed, subject to the terms of our partnership agreement, to increase our quarterly cash distribution on our common units to at least $0.395 per unit, or $1.58 per unit on an annual basis, commencing with the first regular quarterly distribution after the merger closes.

      The following organizational chart depicts our anticipated organizational and ownership structure after giving effect to this offering and to Step Two of the merger transaction.

(GRAPH)


(1)  Includes common units held by affiliates of EPCO, as well as 4,413,549 common units that were issued upon the conversion of all of our 4,413,549 Class B special units on July 29, 2004. Also includes 409,965

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of our common units that will be issued upon conversion of GulfTerra common units owned by Mr. Duncan and his affiliates in connection with the merger.
 
(2)  Does not include any of our common units that may be issued upon conversion of GulfTerra’s remaining 25 Series F1 convertible units and 80 Series F2 convertible units. Pursuant to an assumption agreement to be entered into between us and GulfTerra at the effective time of the merger, we will assume all of GulfTerra’s obligations with respect to the outstanding Series F convertible units that have not been converted or expired.
 
(3)  The structure of the combined company’s subsidiaries may be different than what is depicted above. For example, GulfTerra Energy Partners, L.P. may become a wholly-owned subsidiary of our operating partnership.

      The table below shows the ownership of our common units after giving effect to this offering and the merger.

                   
Units Percentage Interest


Public common units(1)
    176,046,211       48.3 %
EPCO common units(2)
    126,484,519       34.7 %
Shell common units
    41,000,000       11.3 %
El Paso Corporation common units
    13,454,499       3.7 %
General partner interest
          2.0 %
     
     
 
 
Total
    356,985,229       100.0 %
     
     
 


(1)  Gives effect to the issuance of approximately 105.1 million of our common units in the merger. A maximum of 117.6 million of our common units could be issued in the merger if, prior to the closing of the merger, (1) all outstanding options to purchase 973,900 of GulfTerra’s common units are exercised, and (2) the maximum number of GulfTerra’s common units are issued in connection with the conversion of all of GulfTerra’s remaining outstanding Series F convertible units.
 
(2)  Includes common units held by affiliates of EPCO, as well as 4,413,549 common units that were issued upon the conversion of all of our 4,413,549 Class B special units on July 29, 2004. Also includes 409,965 of our common units that will be issued upon conversion of GulfTerra common units owned by Mr. Duncan and his affiliates in connection with the merger.

      Step Three: Acquisition of South Texas Midstream Assets from El Paso Corporation. In connection with the proposed merger, we entered into a purchase and sale agreement with El Paso Corporation to acquire 100% of the equity interests in two El Paso Corporation subsidiaries for $150 million, plus the value of inventory then outstanding. We anticipate that this acquisition will be financed initially through one or more issuances of debt securities, a temporary acquisition term facility, borrowings under our revolving credit facilities, or through any combination of the foregoing. The size, terms and timing of any future debt offerings are subject to market conditions that are beyond our control. Through our purchase of these equity interests, we will acquire nine cryogenic natural gas processing plants, one natural gas gathering pipeline, one natural gas treating plant and one small natural gas liquids connecting pipeline. These plants are located in South Texas and have historically been associated with and are integral to GulfTerra’s Texas intrastate natural gas pipeline system. The closing of this purchase is effectively conditioned upon, and is expected to occur immediately following, the closing of the merger. The closing of the merger, however, is not conditioned upon the closing of this purchase, provided that neither party breaches its obligation to close this purchase under the purchase and sale agreement. We refer to the assets that we will acquire from El Paso Corporation as the South Texas midstream assets.

      Transactions Following the Merger. We further agreed with El Paso Corporation that, for a period of three years following the closing of the merger:

  •  at the request of GulfTerra, El Paso Corporation will provide support services to GulfTerra similar to those provided by El Paso Corporation before the closing of the merger, and GulfTerra will reimburse El Paso Corporation for 110% of its direct costs of such services (excluding any overhead costs); and

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  •  El Paso Corporation will pay us annual transition support payments in amounts of $18 million, $15 million and $12 million for the first, second and third years of such period, respectively.

Management of the Combined Company

      Information regarding our current management and the management of the combined company is set forth under “Management” beginning on page S-51 of this prospectus supplement.

Conditions to the Effectiveness of the Merger and Related Transactions

      On July 29, 2004, both we and GulfTerra received the unitholder approvals necessary to complete the merger. Completion of the merger and the related transactions is expected to occur during the third quarter of 2004, but is subject to the conditions described below.

      The completion of the merger is also subject to customary regulatory approvals, including under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. We and GulfTerra made the required filings with the Federal Trade Commission, or FTC, and the Antitrust Division of the Department of Justice, or DOJ, relating to the merger on January 21, 2004, but we are not permitted to complete the merger until the applicable waiting periods have expired or otherwise terminated.

      We are in the process of negotiating a consent decree with the FTC for the divestiture of certain of our assets to resolve their competitive concerns. We do not believe these divestitures will be significant to the combined company’s business.

      In addition to the conditions described above, the transaction agreements contain many other conditions that, if not satisfied or waived, would result in the merger not occurring. Please read “Risk Factors — Risks Related to the Merger and Related Transactions” beginning on page S-26 of this prospectus supplement for a discussion of some of these conditions and for a discussion of the risks associated with the merger. The transaction agreements are filed as exhibits to our Current Reports on Form 8-K filed with the SEC on December 15, 2003 and April 21, 2004, and are incorporated by reference into this prospectus supplement.

Intended Financing Transactions in Connection with the Merger

      In connection with the closing of the merger, we intend to make a tender offer to purchase GulfTerra’s outstanding senior and senior subordinated notes at a market-based price and to finance the tender offer through one or more issuances of debt securities and/or through a temporary acquisition term facility. The size, terms and timing of any future debt offerings are subject to market conditions that are beyond our control.

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Our Other Recent Developments

Second Quarter 2004 Unaudited Results

      The following table sets forth our summarized results of operations for the periods indicated:

                                     
For the Three Months For the Six Months
Ended June 30, Ended June 30,


2003 2004 2003 2004




Income Statement Data:
                               
Revenues
  $ 1,210.6     $ 1,713.4     $ 2,692.3     $ 3,418.2  
Costs and expenses
    1,144.1       1,660.4       2,542.3       3,291.4  
Equity earnings from unconsolidated affiliates
    (0.2 )     12.1       1.4       25.5  
     
     
     
     
 
 
Operating income
    66.3       65.1       151.4       152.4  
Other income (expense)
    (31.4 )     (30.8 )     (70.5 )     (62.0 )
Provision for taxes
    (0.5 )     (0.4 )     (3.6 )     (2.0 )
Minority interest
    (1.3 )     (0.7 )     (3.7 )     (3.7 )
Cumulative effect of change in accounting principle
                      7.0  
     
     
     
     
 
 
Net income
  $ 33.1     $ 33.1     $ 73.6     $ 91.6  
     
     
     
     
 
Fully diluted earnings per unit
  $ 0.14     $ 0.11     $ 0.32     $ 0.35  
     
     
     
     
 
EBITDA
  $ 94.7     $ 97.2     $ 208.0     $ 220.5  
     
     
     
     
 
Gross operating margin:
                               
 
Pipelines
  $ 72.0     $ 67.1     $ 143.9     $ 150.1  
 
Fractionation
    35.9       35.9       64.9       66.2  
 
Processing
    2.7       4.4       32.7       22.4  
 
Octane enhancement
    (3.2 )     (0.7 )     (6.7 )     (1.9 )
 
Other
    (0.9 )     (0.6 )     (1.9 )     (1.0 )
     
     
     
     
 
Total gross operating margin
  $ 106.5     $ 106.1     $ 232.9     $ 235.8  
     
     
     
     
 
Selected Volumetric Operating Data:
                               
 
Pipelines, net volumes as shown
                               
   
NGL and petrochemical liquids pipelines (MBPD, net)
    1,295       1,331       1,303       1,381  
   
Natural gas pipelines (BBtus per day, net)
    1,033       1,068       1,033       1,071  
 
Fractionation, net volumes in MBPD
                               
   
NGL fractionation
    201       237       218       233  
   
Propylene fractionation
    58       60       59       57  
   
Isomerization
    82       78       81       69  
 
Natural gas processing, net volumes as shown
                               
   
Fee-based natural gas processing (MMcf per day, net)
    160       1,248       112       805  
   
Equity NGL production (MBPD, net)
    39       45       43       47  
 
Octane enhancement, net volumes in MBPD
    3       10       3       7  

      Please read “Non-GAAP Financial Measures” on pages S-22 through S-25 for an explanation of our gross operating margin and a reconciliation of gross operating margin to operating income, which is the financial measure calculated and presented in accordance with GAAP that is the most directly comparable to gross operating margin, and for an explanation of EBITDA and a reconciliation of EBITDA to net income and operating activities cash flows, which are the financial measures calculated and presented in accordance with GAAP that are the most directly comparable to EBITDA.

      As of June 30, 2004, our total debt balance was approximately $1.8 billion. Our debt as of June 30, 2004, pro forma for the application of the proceeds from this offering, was approximately $1.5 billion.

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     Overview of Second Quarter 2004 Unaudited Results

      The fundamentals for the NGL industry during the second quarter were the strongest that we have seen in the past two years. Ethane demand by the ethylene industry (which is the largest single consumer of ethane and propane) averaged 747 thousand barrels per day, or MBPD, in the second quarter of 2004 compared to 614 MBPD in the second quarter of 2003. Ethane demand in June 2004 was 765 MBPD compared to 560 MBPD in June 2003.

      As a result of global events, we expect that the unusual level of volatility in crude oil, natural gas and NGL prices will continue. The volatility in hydrocarbon prices impacts the prices we charge customers for products and services and those we pay vendors for feedstocks, fuel and other purchases. In addition, this volatility can result in lower of cost or market valuation adjustments to our inventories depending on the carrying values of products at the end of each reporting period.

      In addition, higher fuel costs (primarily for natural gas) continue to impact our profitability. This is due to the combination of higher prices for natural gas, natural gas fired electricity and NGLs and the fact that, unlike most of our other facilities, our transportation tariffs for the Mid-America and Seminole pipelines do not provide for automatic surcharges to customers for increased fuel costs. During the second quarter of 2004, we took additional steps to minimize our exposure to the volatility of fuel costs by converting NGL-fueled pipeline pump stations to electricity and by entering into a five-year fixed-price contract to purchase power from a coal-fired power plant in Texas. We are also evaluating a cost of service filing with the FERC for the recovery of the increased fuel costs on the Mid-America and Seminole pipelines through an increase in our transportation tariffs.

     Three Months Ended June 30, 2004 Compared to Three Months Ended June 30, 2003

      Revenues for the second quarter of 2004 increased $502.8 million over those recorded during the same period in 2003. Processing segment revenues increased $315.6 million quarter-to-quarter primarily due to higher sales volumes and NGL prices. On a weighted-average basis, NGL prices increased from 52 cents per gallon, or CPG, during the second quarter of 2003 to 66 CPG during the second quarter of 2004. Fractionation segment revenues increased $103.1 million quarter-to-quarter primarily due to a $131.4 million increase in propylene fractionation revenues resulting from higher sales volumes and polymer and refinery-grade propylene prices. In addition, the consolidation of BEF added $70.8 million in revenues. We began consolidating BEF’s results with those of our own after purchasing an additional 33.3% interest in BEF on September 30, 2003.

      Costs and expenses increased $516.3 million quarter-to-quarter primarily due to an increase in cost of sales related to NGL and propylene fractionation marketing activities. The increase in cost of sales was caused by higher purchase volumes and prices. In addition, the consolidation of BEF also increased operating costs and expenses. Lastly, depreciation and amortization in operating costs and expenses increased $3.9 million quarter-to-quarter as a result of capital expenditures and business acquisitions completed since June 30, 2003.

      Selling, general and administrative costs decreased $3 million quarter-to-quarter generally due to the timing of such expenditures and cost reduction programs. Earnings from equity method unconsolidated affiliates increased $12.3 million quarter-to-quarter primarily due to $10.7 million recorded from GulfTerra’s general partner in the second quarter of 2004. We acquired a 50% membership interest in GulfTerra’s general partner from El Paso Corporation in December 2003. The overall impact of increased operating expenses for the second quarter of 2004 lowered operating income $1.2 million quarter-to-quarter.

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

      Pipelines. Gross operating margin from our Pipelines segment was $67.1 million for the second quarter of 2004 compared to $72 million for the second quarter of 2003. On an energy-equivalent basis, net pipeline throughput was 1,612 MBPD for the second quarter of 2004 versus 1,566 MBPD for the second quarter of 2003. Gross operating margin for the second quarter of 2004 includes $10.7 million of equity earnings from GulfTerra’s general partner.

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      NGL and petrochemical volumes increased to 1,331 MBPD during the second quarter of 2004 from 1,295 MBPD during the second quarter of 2003. Gross operating margin from our Mid-America and Seminole pipelines for the second quarter of 2004 was $31.1 million compared to $39.9 million for the second quarter of 2003. Net NGL volumes transported by the two pipelines increased by 43 MBPD quarter-to-quarter. The $8.8 million decrease in gross operating margin from the second quarter of last year was primarily due to a one-time $3.8 million reduction in operating expense in 2003 that did not recur in 2004 and a $3.6 million increase in repair, maintenance and fuel expenses, including $1.8 million that was attributable to our pipeline integrity inspection program. The increase in expenses from the prior year more than offset the increase in gross operating margin associated with the higher transportation volumes. Beginning July 1, 2004, the tariffs on the Mid-America and Seminole pipeline will increase by approximately $7.2 million on an annual basis as the result of the annual adjustment for the increase in the Producer Price Index.

      Our NGL import facility posted a $2.2 million decrease in gross operating margin quarter-to-quarter primarily due to a 63 MBPD decrease in import volumes. Greater worldwide demand for NGLs during the second quarter of 2004 resulted in competition for NGLs and the diversion of volumes to other international markets that normally would have been delivered to the U.S. Gulf Coast. Gross operating margin from our Houston Ship Channel pipeline decreased $1.8 million quarter-to-quarter due to lower volumes originating from our NGL import facility.

      Gross operating margin from the Lou-Tex NGL pipeline decreased by $2.8 million quarter-to-quarter due to a 12 MBPD decrease in volume. This decrease in margin and volume was due to our election to maximize our overall total gross operating margin by diverting mixed NGLs and refinery-grade propylene to our other facilities.

      As a result of increased natural gas sales margins, gross operating margin from Acadian Gas increased $1.4 million quarter-to-quarter. Natural gas throughput on this system increased 29 billion British thermal units per day, or BBtu/d, quarter-to-quarter. Equity earnings from our Gulf of Mexico natural gas pipeline investments decreased $1.4 million quarter-to-quarter primarily due to the underperformance of the Brutus and Hickory fields and natural depletion of natural gas reserves served by our pipeline systems, which was partially offset by new production from other fields. Overall, natural gas pipeline throughput volumes were 1,068 BBtu/d during the second quarter of 2004 versus 1,033 BBtu/d during the second quarter of 2003.

      Total pipeline integrity inspection and testing expense for the second quarter of 2004 was approximately $3.1 million compared to $0.1 million in the second quarter of 2003. In addition, approximately $1.2 million of major pipeline integrity repair costs were capitalized during the second quarter of 2004 compared to $0.7 million in the second quarter of last year.

      Fractionation. Gross operating margin from our Fractionation segment was $35.9 million for the second quarters of both 2004 and 2003. Gross operating margin from NGL fractionation decreased $3.4 million quarter-to-quarter. NGL fractionation volumes were 237 MBPD during the second quarter of 2004 compared to 201 MBPD during the second quarter of 2003. Gross operating margin from our Mont Belvieu NGL fractionator decreased $8.7 million quarter-to-quarter primarily due to $6.8 million in net gains associated with the measurement of mixed NGLs in storage pending fractionation we recorded in the second quarter of 2003, which did not recur in the second quarter of 2004. Gross operating margin from our Norco facility increased $5 million quarter-to-quarter primarily due to (i) a 23 MBPD increase in volumes resulting from an expansion of the facility completed during the fourth quarter of 2003 and (ii) higher prices for NGL volumes sold by Norco that it takes ownership of as a result of percent-of-liquids arrangements.

      Gross operating margin from propylene fractionation increased $4.1 million quarter-to-quarter primarily due to an increase in petrochemical marketing sales volumes. Propylene fractionation volumes were 60 MBPD during the second quarter of 2004 compared to 58 MBPD during the second quarter of 2003. Gross operating margin from isomerization decreased $0.5 million quarter-to-quarter primarily due to a lower volumes and tolling revenues, which were partially offset by higher by-product revenues. Isomerization volumes were 78 MBPD during the second quarter of 2004 compared to 82 MBPD during the second quarter of 2003.

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      Processing. Gross operating margin from our Processing segment was $4.4 million for the second quarter of 2004 compared to $2.7 million for the second quarter of 2003. Gross operating margin from our gas processing plants increased $9.2 million quarter-to-quarter. Equity NGL production was 45 MBPD for the second quarter of 2004 compared to 39 MBPD for the second quarter of 2003. Fee-based natural gas processing volumes increased to 1,248 MMcf/d in the second quarter of 2004 from 160 MMcf/d in the second quarter of 2003 reflecting the conversion of our major processing agreements to fee-based arrangements.

      Gross operating margin from NGL marketing activities was a loss of $5.8 million for the second quarter of 2004 compared to a profit of $1.7 million in the second quarter of 2003. The second quarter of 2004 included a loss of $13.4 million associated with the ineffectiveness of a practice that we used to manage our NGL production and inventory on a seasonal basis. Historically, there has been a seasonal price decrease for NGLs from the first quarter to the second quarter of a given year, due in part to greater demand in the winter months for propane for space heating and for butanes in the production of motor gasoline. Part of our inventory practice at the beginning of the second quarter of 2004 was to sell NGLs at prices that were greater than our expected production or purchased volume costs in the second quarter of 2004 to take advantage of expected seasonal price differences. In prior years, this practice had been generally profitable. Unfortunately, this practice did not work for us in the second quarter of 2004 because of the unexpected increase and volatility in crude oil, natural gas and NGL prices due to global events. We expect that the unusual level of volatility in hydrocarbon prices will continue in the near term. As a result, we will limit the amount of NGLs that we will sell under this practice to about five days worth of our equity NGL production, or approximately 250,000 barrels.

      When current market prices are below the carrying cost of our various inventories, we are required to record a lower of cost or market adjustment to reduce the carrying costs to their respective market values. We recorded $1.8 million of lower of cost or market adjustments for the second quarter of 2004 compared to $3.4 million of such adjustments for the second quarter of 2003. Beginning with the third quarter of 2004, we will reclassify approximately 775,000 barrels of linefill that we own as a shipper on certain NGL pipelines from inventory to property on our consolidated balance sheet. This change is due to business reasons that require us to maintain volumes as permanent linefill and is consistent with our classification of linefill for other pipelines. Such volumes will be subject to periodic impairment testing under Statements of Financial Accounting Standards No. 144.

Special Meetings of Unitholders

      On July 29, 2004, we held a special meeting of our unitholders at which our unitholders approved the issuance of our common units pursuant to the merger agreement, and approved the conversion of our 4,413,549 Class B special units into an equal number of common units. On the same day, GulfTerra held a special meeting of its common unitholders at which GulfTerra’s common unitholders approved and adopted the merger agreement. For a discussion of the remaining conditions to the effectiveness of the merger, please read “— Conditions to the Effectiveness of the Merger and Related Transactions.”

May 2004 Common Unit Offering

      In May 2004, we completed a public offering of 17,250,000 common units (including 2,250,000 common units sold pursuant to the underwriters’ over-allotment option) from which we received net proceeds of approximately $353.1 million, including our general partner’s $7.1 million capital contribution. We used the net proceeds from the offering, including our general partner’s proportionate capital contribution, to repay in full our $225 million interim term loan and to temporarily reduce indebtedness under our revolving credit facilities by approximately $130 million.

Interest Expense Hedging Program

      In the first quarter of 2004, we entered into interest rate hedging arrangements in anticipation of entering into permanent debt financing for the proposed GulfTerra merger. On April 23, 2004, we terminated these arrangements and, on April 27, 2004 we received approximately $104.5 million in cash as a result of the

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termination. This amount is included in distributable cash flow for the second quarter of 2004 and is expected to increase net income for book purposes over the life of the future planned debt issuances.

Distribution Reinvestment Plan

      Our DRIP enables our limited partners to reinvest all or a portion of the quarterly cash distributions they receive from their common units in our company. In connection with the payment of our May 12, 2004 quarterly cash distribution, we issued 1,757,347 common units in connection with our DRIP from which we received net proceeds of approximately $35.3 million, including our general partner’s $0.7 million capital contribution to maintain its 2% general partner interest in us. The proceeds from the reinvested distributions were used for general partnership purposes.

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Summary Historical and Pro Forma Financial and Operating Data

      The following tables set forth, for the periods and at the dates indicated, summary historical financial and operating data for Enterprise and GulfTerra. The summary historical income statement and balance sheet data for the three years in the period ended December 31, 2003 are derived from and should be read in conjunction with the audited financial statements of Enterprise, GulfTerra and the South Texas midstream assets that are incorporated by reference into this prospectus supplement. The summary historical income statement data for the three-month periods ended March 31, 2003 and 2004 and balance sheet data at March 31, 2004 are derived from and should be read in conjunction with the unaudited financial statements of Enterprise, GulfTerra and the South Texas midstream assets that are incorporated by reference into this prospectus supplement.

      The summary pro forma adjusted financial statements of Enterprise show the pro forma effect of (i) the proposed merger with GulfTerra through Step Three of this transaction; (ii) our “other recent events”, which include (a) the application of $353.1 million in net proceeds from our May 2004 public offering of 17,250,000 common units (including our general partner’s $7.1 million net capital contribution) and the use of such proceeds to repay in full the $225 million outstanding under our interim term loan and to repay approximately $130 million outstanding under our revolving credit facilities; (b) the issuance of 1,757,347 common units in connection with our DRIP in May 2004 and the use of proceeds from that offering for general partnership purposes; and (c) the conversion of the 4,413,549 Class B special units into an equal number of our common units on July 29, 2004; and (iii) the completion of this offering and the application of the $281.7 million in net proceeds from this offering (including our general partner’s $5.7 million net capital contribution) to temporarily reduce borrowings under our multi-year revolving credit facility and to fund a portion of the purchase price at the closing of the Step Two and Step Three merger transactions. The proposed merger with GulfTerra involves the following three steps:

  •  Step One. On December 15, 2003, we purchased a 50% membership interest in GulfTerra’s general partner for $425 million. GulfTerra’s general partner owns a 1% general partner interest in GulfTerra. This investment is accounted for using the equity method and is already recorded in Enterprise’s historical balance sheet at December 31, 2003. This transaction is referred to as Step One of the proposed merger and will remain in effect even if the remainder of the proposed merger and post-merger transactions, which are referred to as Step Two and Step Three, do not occur.
 
  •  Step Two. If all necessary regulatory approvals are received and the other merger agreement conditions are either fulfilled or waived and the following steps are consummated, we will own 100% of the limited and general partner interests in GulfTerra. At that time, the proposed merger will be accounted for using the purchase method, and GulfTerra will be a consolidated subsidiary of Enterprise. Step Two of the proposed merger includes the following transactions:

  •  El Paso Corporation’s exchange of its remaining 50% membership interest in GulfTerra’s general partner for a cash payment by our general partner of $370 million (which will not be funded or reimbursed by us) and a 9.9% membership interest in our general partner, and the subsequent capital contribution by our general partner of such 50% membership interest in GulfTerra’s general partner to us (without increasing our general partner’s interest in our earnings or cash distributions).
 
  •  Our purchase of 10,937,500 GulfTerra Series C units and 2,876,620 GulfTerra common units owned by El Paso Corporation for $500 million.
 
  •  The exchange of each remaining GulfTerra common unit for 1.81 Enterprise common units, resulting in the issuance of approximately 105.1 million of our common units to GulfTerra unitholders.

  •  Step Three. Immediately after Step Two is completed, we expect to acquire the South Texas midstream assets from El Paso Corporation for $150 million plus the value of then outstanding inventory.

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      We anticipate that a portion of the purchase price at the closing of Steps Two and Three of the merger will be financed with the net proceeds from this offering. We expect to finance the remaining portion of this purchase price through one or more issuances of debt securities, a temporary acquisition term facility, borrowings under our credit facility, or through any combination of the foregoing. The size, terms and timing of any future debt offerings are subject to market conditions that are beyond our control.

      Our pro forma adjustments give effect to the sale of 13,750,000 of our common units to the public in this offering at an assumed offering price of $20.90 per unit. Net proceeds from this offering, including our general partner’s proportionate net capital contribution of $5.7 million, are $281.7 million after deducting applicable underwriting discounts, commissions and offering expenses of $11.6 million. The net proceeds from this offering, including our general partner’s proportionate net capital contribution, will be used to temporarily reduce borrowings under our multi-year revolving credit facility and to fund a portion of the purchase price at the closing of the Step Two and Step Three merger transactions, or, if the merger does not close, for working capital purposes or for future acquisitions. Please read “Use of Proceeds.”

      The unaudited pro forma condensed statement of consolidated operations for the year ended December 31, 2003 and for the three months ended March 31, 2004 assume the merger-related transactions, the May 2004 common unit offerings and this offering all occurred on January 1 of each period presented. The unaudited pro forma condensed consolidated balance sheet shows the financial effects of the merger and related transactions, the May 2004 common unit offerings and this offering as if they had occurred on March 31, 2004. Step One of the proposed merger is already included in the March 31, 2004 unaudited historical balance sheet and the unaudited historical statement of consolidated operations for the three months ended March 31, 2004 of Enterprise. The unaudited pro forma condensed consolidated financial statements for the year ended December 31, 2003 and for the three months ended March 31, 2004 do not include the effect of any future long-term financing transactions contemplated in connection with the closing of the merger. In addition, the unaudited pro forma condensed consolidated financial statements do not give effect to any divestiture of assets that may be required for governmental approval of the proposed merger.

      The non-generally accepted accounting principle, or non-GAAP, financial measures of gross operating margin and earnings before interest, income taxes, depreciation and amortization, which we refer to as “EBITDA,” are presented in the summary historical and pro forma financial data for Enterprise. In a supplemental section titled “Non-GAAP Financial Measures,” we have provided the necessary explanations and reconciliations for Enterprise’s non-GAAP financial measures.

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Summary Historical and Pro Forma Financial and Operating Data of Enterprise

                                                       
For Year Ended December 31, 2003

Consolidated Historical

Adjusted Adjusted
Through Enterprise Enterprise
For Year Ended December 31, Step Three Pro Forma Pro Forma

Enterprise for Other for this
2001 2002 2003 Pro Forma Recent Events Offering






(Unaudited)
(Dollars in millions, except per unit amounts)
Income Statement Data:
                                               
 
Revenues
  $ 3,154.4     $ 3,584.8     $ 5,346.4     $ 7,153.0     $ 7,153.0     $ 7,153.0  
 
Costs and expenses:
                                               
   
Operating costs and expenses
    2,862.6       3,382.8       5,046.8       6,474.1       6,474.1       6,474.1  
   
Selling, general and administrative
    30.3       42.9       37.5       93.5       93.5       93.5  
     
     
     
     
     
     
 
     
Total costs and expenses
    2,892.9       3,425.7       5,084.3       6,567.6       6,567.6       6,567.6  
     
     
     
     
     
     
 
 
Equity in income (loss) of unconsolidated affiliates
    25.3       35.2       (14.0 )     (2.6 )     (2.6 )     (2.6 )
     
     
     
     
     
     
 
 
Operating income
    286.8       194.3       248.1       582.8       582.8       582.8  
     
     
     
     
     
     
 
 
Other income (expense):
                                               
   
Interest expense
    (52.4 )     (101.6 )     (140.8 )     (282.6 )     (276.8 )     (270.8 )
   
Other, net
    10.3       7.3       6.4       (28.5 )     (28.5 )     (28.5 )
     
     
     
     
     
     
 
     
Total other income (expense)
    (42.1 )     (94.3 )     (134.4 )     (311.1 )     (305.3 )     (299.3 )
     
     
     
     
     
     
 
 
Income before provision for income taxes and minority interest
    244.7       100.0       113.7       271.7       277.5       283.5  
 
Provision for income taxes
          (1.6 )     (5.3 )     (5.3 )     (5.3 )     (5.3 )
     
     
     
     
     
     
 
 
Income before minority interest
    244.7       98.4       108.4       266.4       272.2       278.2  
 
Minority interest
    (2.5 )     (2.9 )     (3.9 )     (3.9 )     (3.9 )     (3.9 )
     
     
     
     
     
     
 
 
Income from continuing operations
  $ 242.2     $ 95.5     $ 104.5     $ 262.5     $ 268.3     $ 274.3  
                             
     
     
 
 
Cumulative effect of change in accounting principle
                                         
     
     
     
                         
 
Net income
  $ 242.2     $ 95.5     $ 104.5                          
     
     
     
                         
Basic earnings per unit (net of general partner interest):
                                               
 
Income from continuing operations per unit
  $ 1.70     $ 0.55     $ 0.42     $ 0.75     $ 0.71     $ 0.70  
     
     
     
     
     
     
 
Diluted earnings per unit (net of general partner interest):
                                               
 
Income from continuing operations per unit
  $ 1.39     $ 0.48     $ 0.41     $ 0.73     $ 0.70     $ 0.69  
     
     
     
     
     
     
 
Distributions to limited partners:
                                               
 
Per common unit
  $ 1.19     $ 1.36     $ 1.47                          
     
     
     
                         
Balance sheet data:
                                               
 
Total assets
  $ 2,424.7     $ 4,230.3     $ 4,802.8                          
 
Total debt
    855.3       2,246.5       2,139.5                          
 
Total partners’ equity
    1,146.9       1,200.9       1,705.9                          
Other financial data:
                                               
 
Cash provided by operating activities
  $ 283.3     $ 329.8     $ 424.7                          
 
Cash flows used in investing activities
    491.2       1,708.3       657.0                          
 
Cash provided by financing activities
    279.5       1,260.3       248.9                          
 
Distributions received from unconsolidated affiliates
    45.1       57.7       31.9                          
 
Equity in income (loss) of unconsolidated affiliates
    25.4       35.3       (14.0 )                        
 
Gross operating margin
    375.9       332.3       410.4     $ 887.4     $ 887.4     $ 887.4  
 
EBITDA
    345.8       284.8       366.4       771.1       771.1       771.1  
 
Commodity hedging income (losses)
    101.3       (51.3 )     (0.6 )                        

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Table of Contents

Summary Historical and Pro Forma Financial and Operating Data of Enterprise (Continued)

                                               
For Three Months Ended March 31, 2004

Enterprise Adjusted
Consolidated Historical Enterprise Adjusted
For Three Months Through Pro Forma Enterprise
Ended March 31, Step Three for Other Pro Forma

Enterprise Recent for this
2003 2004 Pro Forma Events Offering





(Dollars in millions, except per unit amounts)
Income Statement Data:
                                       
 
Revenues
  $ 1,481.6     $ 1,704.9     $ 2,120.6     $ 2,120.6     $ 2,120.6  
 
Costs and expenses:
                                       
   
Operating costs and expenses
    1,386.7       1,621.5       1,928.3       1,928.3       1,928.3  
   
Selling, general and administrative
    11.5       9.5       22.9       22.9       22.9  
     
     
     
     
     
 
     
Total costs and expenses
    1,398.2       1,631.0       1,951.2       1,951.2       1,951.2  
     
     
     
     
     
 
 
Equity in income of unconsolidated affiliates
    1.6       13.4       5.0       5.0       5.0  
     
     
     
     
     
 
 
Operating income
    85.0       87.3       174.4       174.4       174.4  
     
     
     
     
     
 
 
Other income (expense):
                                       
   
Interest expense
    (41.9 )     (32.6 )     (62.0 )     (61.3 )     (59.8 )
   
Other, net
    2.8       1.4       1.7       1.7       1.7  
     
     
     
     
     
 
     
Total other income (expense)
    (39.1 )     (31.2 )     (60.3 )     (59.6 )     (58.1 )
     
     
     
     
     
 
 
Income before provision for income taxes, minority interest and change in accounting principle
    45.9       56.1       114.1       114.8       116.3  
 
Provision for income taxes
    (3.1 )     (1.6 )     (1.6 )     (1.6 )     (1.6 )
     
     
     
     
     
 
 
Income before minority interest
    42.8       54.5       112.5       113.2       114.7  
 
Minority interest
    (2.3 )     (3.0 )     (3.0 )     (3.0 )     (3.0 )
     
     
     
     
     
 
 
Income from continuing operations
    40.5       51.5     $ 109.5     $ 110.2     $ 111.7  
                     
     
     
 
 
Cumulative effect of change in accounting principle
          7.0                          
     
     
                         
 
Net income
  $ 40.5     $ 58.5                          
     
     
                         
Basic earnings per unit (net of general partner interest):
                                       
 
Income from continuing operations per unit
  $ 0.20     $ 0.21     $ 0.30     $ 0.29     $ 0.28  
     
     
     
     
     
 
Diluted earnings per unit (net of general partner interest):
                                       
 
Income from continuing operations per unit
  $ 0.19     $ 0.20     $ 0.30     $ 0.29     $ 0.28  
     
     
     
     
     
 
Distributions to limited partners:
                                       
 
Per common unit
  $ 0.3625     $ 0.3725                          
Balance sheet data:
                                       
 
Total assets
  $ 4,266.4     $ 4,782.3     $ 10,539.8     $ 10,574.1     $ 10,574.1  
 
Total debt
    2,001.6       2,210.9       4,789.9       4,436.5       4,155.1  
 
Total partners’ equity
    1,438.8       1,720.9       4,639.6       5,027.0       5,308.7  
Other financial data:
                                       
 
Cash provided by operating activities
  $ 141.5     $ 29.6                          
 
Cash used in investing activities
    73.1       15.8                          
 
Cash provided by (used in) financing activities
    (59.7 )     0.5                          
 
Distributions received from unconsolidated affiliates
    15.6       15.7                          
 
Equity in income of unconsolidated affiliates
    1.6       13.4                          
 
Gross operating margin
    126.4       129.7     $ 258.0     $ 258.0     $ 258.0  
 
EBITDA
    113.1       123.2       231.4       231.4       231.4  
 
Commodity hedging losses
    (0.8 )     (0.1 )                        
                                             
Enterprise Consolidated Historical

For Three
Months
For Year Ended Ended
December 31, March 31,


2001 2002 2003 2003 2004





Selected Volumetric Operating Data:
                                       
 
Pipelines, net volumes as shown
                                       
   
NGL and petrochemical liquids pipelines (MBPD, net)
    453       1,352       1,343       1,313       1,431  
   
Natural gas pipelines (BBtus per day, net)
    1,349       1,201       1,032       1,034       1,075  
 
Fractionation, net volumes in MBPD
                                       
   
NGL fractionation
    204       235       227       235       229  
   
Propylene fractionation
    31       55       57       60       54  
   
Isomerization
    80       84       77       80       60  
 
Natural gas processing, net volumes as shown
                                       
   
Fee-based natural gas processing (MMcf per day, net)
    *       *       194       65       362  
   
Equity NGL production (MBPD, net)
    63       73       43       47       48  
 
Octane enhancement, net volumes in MBPD
    5       5       4       3       5  


Fee-based natural gas processing volumes prior to 2003 were negligible.

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Table of Contents

Summary Historical Financial and Operating Data of GulfTerra

                                             
Consolidated Historical

For Three Months
For Year Ended December 31, Ended March 31,


2001 2002 2003 2003 2004





(Dollars in millions, except per unit amounts)
Consolidated Statements of Income Data:
                                       
 
Operating revenues
  $ 193.4     $ 457.4     $ 871.5     $ 230.1     $ 220.3  
 
Operating expenses
    134.9       296.6       557.0       155.0       139.1  
     
     
     
     
     
 
 
Operating income
    58.5       160.8       314.5       75.1       81.2  
     
     
     
     
     
 
 
Other income (expense):
                                       
   
Equity in income (loss) of unconsolidated affiliates
    8.5       13.6       11.4       3.3       2.2  
   
Interest expense
    (41.5 )     (81.1 )     (127.8 )     (34.5 )     (28.0 )
   
Loss due to early redemptions of debt
          (2.4 )     (36.9 )     (3.8 )      
   
Other, net
    28.6       1.6       0.2       0.4       0.2  
     
     
     
     
     
 
   
Total other income (expense)
    (4.4 )     (68.3 )     (153.1 )     (34.6 )     (25.6 )
     
     
     
     
     
 
 
Income from continuing operations
  $ 54.1     $ 92.5     $ 161.4     $ 40.5     $ 55.6  
     
     
     
     
     
 
Basic and diluted earnings per unit:
                                       
 
Income from continuing operations per common unit
  $ 0.35     $ 0.80     $ 1.30     $ 0.40     $ 0.49  
     
     
     
     
     
 
Distributions to limited partners:
                                       
 
Per common unit
  $ 2.31     $ 2.60     $ 2.76     $ 0.68     $ 0.71  
     
     
     
     
     
 
Balance sheet data:
                                       
 
Total assets
  $ 1,357.4     $ 3,130.9     $ 3,321.6     $ 3,167.5     $ 3,364.0  
 
Total debt
    820.0       1,906.3       1,811.8       1,948.7       1,824.2  
 
Total partners’ equity
    500.7       949.9       1,252.6       934.3       1,281.9  
Other financial data:
                                       
 
Cash provided by operating activities
  $ 87.4     $ 176.0     $ 268.2     $ 71.4     $ 63.5  
 
Cash used in investing activities
    499.7       1,215.4       287.2       79.0       53.5  
 
Cash provided by (used in) financing activities
    405.1       1,062.4       13.4       (16.3 )     (17.1 )
Operating data (in MBPD, except as noted):
                                       
 
Natural gas pipelines and plants (Gross MDth/d)
    2,344       5,302       7,685       7,599       7,647  
 
Oil pipelines
    168       154       172       190       164  
 
NGL logistics
    63       72       89       86       104  
 
Natural gas platform volumes (Gross MDth/d)
    189       151       271       183       385  
 
Oil platform volumes
    5       5       5       4       5  

S-21


Table of Contents

Non-GAAP Financial Measures

      We include in this prospectus supplement the non-GAAP financial measures of gross operating margin and EBITDA for Enterprise, and provide reconciliations of these non-GAAP financial measures to their most directly comparable financial measure or measures calculated and presented in accordance with GAAP.

Gross Operating Margin

      We define gross operating margin as operating income before: (1) depreciation and amortization expense; (2) operating lease expenses for which we do not have the cash payment obligation; (3) gains and losses on the sale of assets; and (4) selling, general and administrative expenses. We view gross operating margin as 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 our 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. The GAAP measure most directly comparable to gross operating margin is operating income.

EBITDA

      EBITDA is defined as net income (income from continuing operations with regards to pro forma information) plus interest expense, provision for income taxes and depreciation and amortization expense. EBITDA is used as a supplemental financial measure by our management and by external users of financial statements such as investors, commercial banks, research analysts and ratings agencies, to assess:

  •  the financial performance of our assets without regard to financing methods, capital structures or historical costs basis;
 
  •  the ability of our assets to generate cash sufficient to pay interest cost and support its indebtedness;
 
  •  our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing and capital structure; and
 
  •  the viability of projects and the overall rates of return on alternative investment opportunities.

      EBITDA should not be considered an alternative to net income or income from continuing operations, operating income, cash flow from operating activities or any other measure of financial performance presented in accordance with GAAP. This non-GAAP financial measure is not intended to represent GAAP-based cash flows. We have reconciled our historical and pro forma EBITDA amounts to our consolidated net income (income from continuing operations with regards to pro forma information) and historical EBITDA amounts further to operating activities cash flows.

S-22


Table of Contents

Enterprise Non-GAAP Reconciliations

      The following table presents a reconciliation of our non-GAAP financial measures of total gross operating margin to the GAAP financial measure of operating income and a reconciliation of the non-GAAP financial measure of EBITDA to the GAAP financial measures of net income (income from continuing operations with regards to pro forma information) and of operating activities cash flows, on a historical and pro forma as adjusted basis, as applicable, for each of the periods indicated:

                                                     
For Year Ended December 31, 2003
Enterprise
Consolidated Historical

Adjusted Adjusted
Through Enterprise Enterprise
For Year Ended December 31, Step Three Pro Forma Pro Forma

Enterprise for Other for this
2001 2002 2003 Pro Forma Recent Events Offering






(Unaudited)
(Dollars in millions)
Reconciliation of Non-GAAP “Total Gross Operating Margin” to GAAP “Operating Income”
                                               
Operating Income
  $ 286.8     $ 194.3     $ 248.1     $ 582.8     $ 582.8     $ 582.8  
 
Adjustments to reconcile Operating Income to Total Gross Operating Margin:
                                               
   
Depreciation and amortization in operating costs and expenses
    48.8       86.0       115.7       220.7       220.7       220.7  
   
Retained lease expense, net in operating costs and expenses
    10.4       9.1       9.1       9.1       9.1       9.1  
   
Gain on sale of assets in operating costs and expenses
    (0.4 )                     (18.7 )     (18.7 )     (18.7 )
   
Selling, general and administrative costs
    30.3       42.9       37.5       93.5       93.5       93.5  
     
     
     
     
     
     
 
Total Gross Operating Margin
  $ 375.9     $ 332.3     $ 410.4     $ 887.4     $ 887.4     $ 887.4  
     
     
     
     
     
     
 
Reconciliation of Non-GAAP “EBITDA” to GAAP “Net Income” or “Income from Continuing Operations” and GAAP “Cash Provided by Operating Activities”
                                               
Net Income (or Income from Continuing Operations with regards to pro forma information)
  $ 242.2     $ 95.5     $ 104.5     $ 262.5     $ 268.3     $ 274.3  
 
Adjustments to derive EBITDA:
                                               
   
Interest expense
    52.5       101.6       140.8       282.6       276.8       270.7  
   
Provision for income taxes
            1.6       5.3       5.3       5.3       5.3  
   
Depreciation and amortization (excluding amortization component in interest expenses)
    51.1       86.1       115.8       220.7       220.7       220.8  
     
     
     
     
     
     
 
EBITDA
    345.8       284.8       366.4     $ 771.1     $ 771.1     $ 771.1  
                             
     
     
 
 
Interest expense
    (52.5 )     (101.6 )     (140.8 )                        
 
Amortization in interest expense
    0.8       8.8       12.6                          
 
Provision for income taxes
            (1.6 )     (5.3 )                        
 
Provision for impairment charge
                    1.2                          
 
Earnings from unconsolidated affiliates
    (25.4 )     (35.3 )     14.0                          
 
Distributions from unconsolidated affiliates
    45.1       57.7       31.9                          
 
Loss (gain) on sale of assets
    (0.4 )                                        
 
Operating lease expense paid by EPCO (excluding minority interest portion)
    10.3       9.0       9.0                          
 
Other expenses paid by EPCO
                    0.4                          
 
Minority interest
    2.5       3.0       3.9                          
 
Deferred income tax expense
            2.1       10.5                          
 
Changes in fair market value of financial instruments
    (5.7 )     10.2                                  
 
Net effect of changes in operating accounts
    (37.2 )     92.7       120.9                          
     
     
     
                         
Cash provided by operating activities
  $ 283.3     $ 329.8     $ 424.7                          
     
     
     
                         

S-23


Table of Contents

Enterprise Non-GAAP Reconciliations (Continued)

                                             
Enterprise For Three Months Ended March 31, 2004
Consolidated
Historical Adjusted Adjusted
For Three Months Through Enterprise Enterprise
Ended March 31, Step Three Pro Forma Pro Forma

Enterprise for Other for this
2003 2004 Pro Forma Recent Events Offering





(Dollars in millions)
Reconciliation of Non-GAAP “Total Gross Operating Margin” to GAAP “Operating Income”
                                       
Operating Income
  $ 85.0     $ 87.3     $ 174.4     $ 174.4     $ 174.4  
 
Adjustments to reconcile Operating Income to Total Gross Operating Margin:
                                       
   
Depreciation and amortization in operating costs and expenses
    27.6       30.5       58.3       58.3       58.3  
   
Retained lease expense, net in operating costs and expenses
    2.3       2.3       2.3       2.3       2.3  
   
Gain on sale of assets in operating costs and expenses
            0.1       0.1       0.1       0.1  
   
Selling, general and administrative costs
    11.5       9.5       22.9       22.9       22.9  
     
     
     
     
     
 
Total Gross Operating Margin
  $ 126.4     $ 129.7     $ 258.0     $ 258.0     $ 258.0  
     
     
     
     
     
 
Reconciliation of Non-GAAP “EBITDA” to GAAP “Net Income” or “Income from Continuing Operations” and GAAP “Cash Provided by Operating Activities”
                                       
Net income (Income from Continuing Operations with regards to pro forma information)
  $ 40.5     $ 58.5     $ 109.5     $ 110.2     $ 111.7  
 
Adjustments to derive EBITDA:
                                       
   
Interest expense
    41.9       32.6       62.0       61.3       59.8  
   
Provision for income taxes
    3.1       1.6       1.6       1.6       1.6  
   
Depreciation and amortization (excluding amortization component in interest expenses)
    27.6       30.5       58.3       58.3       58.3  
     
     
     
     
     
 
EBITDA
    113.1       123.2     $ 231.4     $ 231.4     $ 231.4  
                     
     
     
 
 
Interest expense
    (41.9 )     (32.6 )                        
 
Amortization in interest expense
    11.6       0.8                          
 
Provision for income taxes
    (3.1 )     (1.6 )                        
 
Cumulative effect of change in accounting principle
            (7.0 )                        
 
Earnings from unconsolidated affiliates
    (1.6 )     (13.4 )                        
 
Distributions from unconsolidated affiliates
    15.6       15.7                          
 
Loss (gain) on sale of assets
            0.1                          
 
Operating lease expense paid by EPCO (excluding minority interest portion)
    2.3       2.3                          
 
Minority interest
    2.3       3.0                          
 
Deferred income tax expense
    2.7       1.7                          
 
Decrease (increase) in restricted cash
    (10.0 )     5.8                          
 
Net effect of changes in operating accounts
    50.5       (68.4 )                        
     
     
                         
Cash provided by operating activities
  $ 141.5     $ 29.6                          
     
     
                         

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      The following is a reconciliation of Enterprise’s Non-GAAP financial measures of gross operating margin and EBITDA as presented on page S-12 to their respective GAAP measures:

                                     
For the Three
Months Ended For the Six Months
June 30, Ended June 30,


2003 2004 2003 2004




Reconciliation of Non-GAAP “Total Gross Operating Margin” to GAAP “Operating Income”
                               
Operating income
  $ 66.3     $ 65.1     $ 151.4     $ 152.4  
Adjustments to reconcile Operating Income to Total Gross Operating Margin:
                               
 
Depreciation and amortization in operating costs and expenses
    27.8       31.7       55.5       62.2  
 
Retained lease expense, net in operating costs and expenses
    2.3       2.3       4.5       4.6  
 
Selling, general and administrative expenses and other
    10.1       7.0       21.5       16.6  
     
     
     
     
 
Total Gross Operating Margin
  $ 106.5     $ 106.1     $ 232.9     $ 235.8  
     
     
     
     
 
Reconciliation of Non-GAAP “EBITDA” to GAAP “Net Income” and GAAP “Cash Provided by (Used in) Operating Activities”
                               
Net income
  $ 33.1     $ 33.1     $ 73.6     $ 91.6  
Adjustments to derive EBITDA:
                               
 
Interest expense (including related amortization)
    33.3       31.9       75.2       64.5  
 
Provision for income taxes
    0.5       0.4       3.6       2.0  
 
Depreciation and amortization in operating costs and expenses
    27.8       31.8       55.6       62.4  
     
     
     
     
 
EBITDA
    94.7       97.2       208.0       220.5  
 
Interest expense
    (33.3 )     (31.9 )     (75.2 )     (64.5 )
 
Amortization in interest expense
    0.3       1.1       11.9       1.8  
 
Provision for income taxes
    (0.5 )     (0.4 )     (3.6 )     (2.0 )
 
Deferred income tax expense
    2.7       1.2       5.5       2.9  
 
Cumulative effect of change in accounting principle
                            (7.0 )
 
Equity in loss (income) of unconsolidated affiliates
    0.2       (12.1 )     (1.4 )     (25.5 )
 
Distributions received from unconsolidated affiliates
    5.2       18.0       20.9       33.7  
 
Operating lease expense paid by EPCO, net of applicable
                               
   
minority interest portion
    2.3       2.3       4.5       4.6  
 
Minority interest
    1.3       0.7       3.6       3.7  
 
Increase in restricted cash
    (2.8 )     (15.1 )     (12.8 )     (9.3 )
 
Net effect of changes in operating accounts and other
    (91.4 )     17.3       (41.1 )     (51.0 )
     
     
     
     
 
Cash provided by (used in) operating activities
  $ (21.3 )   $ 78.3     $ 120.3     $ 107.9  
     
     
     
     
 

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RISK FACTORS

      An investment in our common units involves risks. You should consider carefully the risk factors included below and under the caption “Risk Factors” beginning on page 2 of the accompanying prospectus, together with all of the other information included in, or incorporated by reference into, this prospectus supplement, when evaluating an investment in our common units. If any of these risks were to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, the trading price of our common units could decline, and you could lose all or part of your investment.

Risks Related to the Merger and the Related Transactions

      Discussed below are some of the risks associated with our pending merger with GulfTerra and the related transactions.

 
The transactions contemplated by the merger agreement may not be consummated.

      The merger agreement contains conditions that, if not satisfied or waived, would result in the merger not occurring. The conditions remaining to be satisfied include:

  •  the expiration or early termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976;
 
  •  the continued accuracy of the representations and warranties contained in the merger agreement and the parent company agreement;
 
  •  the closing of the purchase of specified GulfTerra securities from subsidiaries of El Paso Corporation, which in turn is conditioned upon, among other things, neither party breaching its obligations to close the acquisition of the South Texas midstream assets;
 
  •  the performance by each party of its obligations under the merger agreement, the parent company agreement and the purchase and sale agreement;
 
  •  the absence of any decree, order, injunction or law that prohibits the merger or makes the merger unlawful;
 
  •  the receipt of legal opinions from counsel for each of us and GulfTerra as to the treatment of the merger for U.S. federal income tax purposes; and
 
  •  the receipt of legal opinions from counsel for each of us, GulfTerra and El Paso Corporation as to non-contravention with respect to selected material agreements.

      In addition, we and GulfTerra can agree to terminate the merger agreement at any time without completing the merger, even after unitholder approvals have been obtained. Further, we or GulfTerra could terminate the merger agreement without the other party’s agreement and without completing the merger if:

  •  the merger is not completed by March 31, 2005, other than due to a breach of the merger agreement by the terminating party;
 
  •  the conditions to the merger cannot be satisfied; or
 
  •  any legal prohibition to completing the merger has become final and non-appealable.

      Our purchase of the South Texas midstream assets is expected to occur immediately following the closing of the merger. These assets have historically been associated with and are integral to GulfTerra’s Texas intrastate pipeline system. Even if the merger closes, the purchase of these assets may not occur, which could require the combined company to find substitute resources to support its Texas intrastate pipeline system or to enter into agreements with El Paso Corporation for the use of these plants. This could result in the combined company incurring unanticipated costs and not realizing a portion of its potential cost savings from the proposed merger.

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      If the merger is not completed, we will continue to own the 50% membership interest in GulfTerra’s general partner that we purchased at the time the merger agreement was signed, and our investment will be subject to significant risks, including the following:

  •  El Paso Corporation owns the remaining 50% membership interest in, and serves as the managing member of, GulfTerra’s general partner, and our rights are limited to protective consent rights on specified material transactions affecting GulfTerra or its general partner or the rights and preferences associated with our membership interest in GulfTerra’s general partner. If the merger does not occur, we will not control GulfTerra’s general partner, and the performance of our investment in GulfTerra will be substantially dependent on the decisions of El Paso Corporation; and
 
  •  El Paso Corporation is not obligated to repurchase this interest from us if the merger does not close. Furthermore, because El Paso Corporation serves as managing member of GulfTerra’s general partner until the merger occurs and because of contractual restrictions on our right to sell our membership interest, we might not be able to sell our membership interest, or we might not be able to sell our membership interest for the price we paid for it if the merger does not occur.

      Finally, our 50% membership interest in GulfTerra’s general partner entitles us to receive quarterly distributions equal to 50% of all available cash held by GulfTerra’s general partner. Available cash consists of GulfTerra’s general partner’s cash and cash equivalents on hand less an amount of cash reserves that are necessary to provide for the proper conduct of the business and to comply with applicable law and the terms of agreements to which it is a party. To the extent that GulfTerra’s general partner incurs expenses and obligations, the amount of cash available for distribution to us in respect of our 50% membership interest in GulfTerra’s general partner will decrease. Moreover, GulfTerra’s general partner’s most significant asset is the 1% general partner interest it owns in GulfTerra. This interest entitles GulfTerra’s general partner to receive its share of quarterly distributions of cash, which increases when both common unitholders are paid a minimum quarterly distribution and certain target distribution levels are achieved. If GulfTerra’s distributable cash flow decreases, the amount distributable to GulfTerra’s general partner and, thus, the amount of available cash held by GulfTerra’s general partner and available for distribution to us, could decline.

 
While the merger agreement is in effect, we may lose opportunities to enter into different business combination transactions with other parties on more favorable terms.

      The merger agreement prohibits us from entering into or soliciting, initiating or encouraging any inquiries or proposals that may lead to a proposal, or offering to enter into certain transactions such as a merger, sale of assets or other business combination, with any other person. As a result of this no-solicitation provision in the merger agreement, we may lose opportunities to enter into more favorable transactions.

      Moreover, the merger agreement provides for the payment of $112 million in break-up fees by us to GulfTerra if we materially and willfully breach our no-solicitation covenant. This break-up fee is intended to provide a financial incentive for us to seek to complete the proposed merger with GulfTerra rather than to explore alternative transactions that potentially could be more favorable to our unitholders.

      We and GulfTerra have also agreed to refrain from taking certain actions with respect to our respective businesses and financial affairs pending completion of the merger or termination of the merger agreement. These restrictions and the no solicitation provision described above could be in effect for an extended period of time if completion of the merger is delayed.

      In addition to the economic costs associated with pursuing a merger, our management is devoting substantial time and other human resources to the proposed transaction and related matters, which could limit our ability to pursue other attractive business opportunities, including potential joint ventures, stand-alone projects and other transactions. If we are unable to pursue such other attractive business opportunities, then the growth prospects and the long-term strategic position of our business could be adversely affected.

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We could be required to divest significant assets to complete the merger.

      We cannot complete the merger until the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 has expired or terminated. As a prerequisite to obtaining FTC approval for the proposed merger, we may be required to divest certain Enterprise or GulfTerra assets as described under “Summary — The Merger and Related Transactions — Conditions to the Effectiveness of the Merger and Related Transactions.” Our divesting any assets required by the FTC is also a condition to the merger agreement. GulfTerra is required to divest any assets required by the FTC to the extent such divestitures are recommended by us, and we are required to divest any assets required by the FTC to the extent such divestitures, together with all required GulfTerra divestitures (but excluding the FTC consent decree assets), do not exceed $150 million. In addition, if such divestitures required by the FTC exceed $150 million, we and, with our consent, GulfTerra have the right to comply with such divestiture requirements to consummate the merger.

      Divestitures of assets can be time consuming and may delay completion of the proposed merger. Because there may be a limited number of potential buyers for the assets subject to divestiture and because potential buyers likely will be aware of the circumstances of the sale, these assets could be sold at prices lower than their fair market value or lower than the prices we or GulfTerra paid for these assets. Asset divestitures could also significantly reduce the value of the combined company, eliminate potential cost savings opportunities or lessen the anticipated benefits of the merger.

Risks Related to the Combined Company’s Business

      In addition to the risk factors contained under “Risk Factors — Risks Related to Our Business” beginning on page 2 of the accompanying prospectus, which relate to Enterprise as a stand-alone company, the following risks will apply to the combined company following the closing of the merger.

 
We may not be able to integrate successfully our operations with GulfTerra’s operations.

      Integration of the two previously independent companies will be a complex, time consuming and costly process. Failure to timely and successfully integrate these companies may have a material adverse effect on the combined company’s business, financial condition and results of operations. The difficulties of combining the companies will present challenges to the combined company’s management, including:

  •  operating a significantly larger combined company with operations in geographic areas and business lines in which we have not previously operated;
 
  •  managing relationships with new joint venture partners with whom we have not previously partnered;
 
  •  integrating personnel with diverse backgrounds and organizational cultures;
 
  •  experiencing operational interruptions or the loss of key employees, customers or suppliers;
 
  •  establishing the internal controls and procedures that the combined company will be required to maintain under the Sarbanes-Oxley Act of 2002; and
 
  •  consolidating other corporate and administrative functions.

      The combined company will also be exposed to risks that are commonly associated with transactions similar to the merger, such as unanticipated liabilities and costs, some of which may be material, and diversion of management’s attention. As a result, the anticipated benefits of the merger may not be fully realized, if at all.

 
Changes in the prices of hydrocarbon products may materially adversely affect the results of operations, cash flows and financial condition of the combined company.

      The combined company will operate predominantly in the midstream energy sector which includes gathering, transporting, processing, fractionating and storing natural gas, NGLs and crude oil. As such, the combined company’s results of operations, cash flows and financial condition may be materially adversely

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affected by changes in the prices of these hydrocarbon products and by changes in the relative price levels among these hydrocarbon products. In general terms, the prices of natural gas, NGLs, crude oil and other hydrocarbon products are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are impossible to control. These factors include:

  •  the level of domestic production;
 
  •  the availability of imported oil and natural gas;
 
  •  actions taken by foreign oil and natural gas producing nations;
 
  •  the availability of transportation systems with adequate capacity;
 
  •  the availability of competitive fuels;
 
  •  fluctuating and seasonal demand for oil, natural gas and NGLs; and
 
  •  conservation and the extent of governmental regulation of production and the overall economic environment.

      The profitability of the combined company’s NGL and natural gas processing operations will depend upon the spread between NGL product prices and natural gas prices. A reduction in the spread between NGL product prices and natural gas prices can result in a reduction in demand for fractionation, processing, NGL storage and NGL transportation services and, thus, may materially adversely affect the combined company’s results of operations and cash flows. In addition, a portion of the combined company’s natural gas processing activities will be exposed to commodity price risk associated with the relative price of NGLs to natural gas under its “keep-whole” natural gas processing contracts. Under keep-whole agreements, the combined company will take title to NGLs that it extracts from the natural gas stream and will be obligated to pay market value, based on natural gas prices, for the energy extracted from the natural gas stream. When prices for natural gas increase, the cost to the combined company of making these keep-whole payments will increase, and, where NGL prices do not experience a commensurate increase, the combined company will realize lower margins from these transactions. As a result, changes in prices for natural gas compared to NGLs could have a material adverse affect on the results of operations, cash flows and financial position of the combined company.

      The combined company will also be exposed to natural gas and NGL commodity price risk under natural gas processing and gathering and NGL fractionation contracts that provide for the combined company’s fee to be calculated based on a regional natural gas or NGL price index or to be paid in-kind by taking title to natural gas or NGLs. A decrease in natural gas and NGL prices can result in lower margins from these contracts which may materially adversely affect the combined company’s results of operations, cash flows and financial position.

 
A decline in the volume of natural gas, NGLs and crude oil delivered to the combined company’s facilities could adversely affect the results of operations, cash flows and financial condition of the combined company.

      The combined company’s profitability could be materially impacted by a decline in the volume of natural gas, NGLs and crude oil transported, gathered or processed at its facilities. A material decrease in natural gas or crude oil production or crude oil refining, as a result of depressed commodity prices, a decrease in exploration and development activities or otherwise, could result in a decline in the volume of natural gas, NGLs and crude oil handled by the combined company’s facilities.

      The crude oil, natural gas and NGLs available to the combined company’s facilities will be derived from reserves produced from existing wells, which reserves naturally decline over time. To offset this natural decline, the combined company’s facilities will need access to additional reserves. Additionally, some of the combined company’s facilities will be dependent on reserves that are expected to be produced from newly discovered properties that are currently being developed.

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      Exploration and development of new oil and natural gas reserves is capital intensive, particularly offshore in the Gulf of Mexico. Many economic and business factors are out of the combined company’s control and can adversely affect the decision by producers to explore for and develop new reserves. These factors include relatively low oil and natural gas prices, cost and availability of equipment, regulatory changes, capital budget limitations or the lack of available capital. For example, a sustained decline in the price of natural gas and crude oil could result in a decrease in natural gas and crude oil exploration and development activities in the regions where the combined company’s facilities are located. This could result in a decrease in volumes to the combined company’s offshore platforms, natural gas processing plants, natural gas, crude oil and NGL pipelines, and NGL fractionators which would have a material adverse affect on the combined company’s results from operations cash flows and financial position. Additional reserves, if discovered, may not be developed in the near future or at all.

 
A reduction in demand for NGL products by the petrochemical, refining or heating industries could materially adversely affect the combined company’s results of operations, cash flows and financial position.

      A reduction in demand for NGL products by the petrochemical, refining or heating industries, whether because of general economic conditions, reduced demand by consumers for the end products made with NGL products, increased competition from petroleum-based products due to pricing differences, adverse weather conditions, government regulations affecting prices and production levels of natural gas or the content of motor gasoline or other reasons, could materially adversely affect the combined company’s results of operations, cash flows and financial position. For example:

        Ethane. If natural gas prices increase significantly in relation to ethane prices, it may be more profitable for natural gas producers to leave the ethane in the natural gas stream to be burned as fuel than to extract the ethane from the mixed NGL stream for sale.
 
        Propane. The demand for propane as a heating fuel is significantly affected by weather conditions. Unusually warm winters could cause the demand for propane to decline significantly and could cause a significant decline in the volumes of propane that the combined company transports.
 
        Isobutane. Any reduction in demand for motor gasoline additives may reduce demand for isobutane. During periods in which the difference in market prices between isobutane and normal butane is low or inventory values are high relative to current prices for normal butane or isobutane, the combined company’s operating margin from selling isobutane could be reduced.
 
        Propylene. Any downturn in the domestic or international economy could cause reduced demand for propylene, which could cause a reduction in the volumes of propylene that the combined company produces and expose the combined company’s investment in inventories of propane/propylene mix to pricing risk due to requirements for short-term price discounts in the spot or short-term propylene markets.
 
The combined company will face competition from third parties in its midstream businesses.

      Even if reserves exist in the areas accessed by the combined company’s facilities and are ultimately produced, the combined company may not be chosen by the producers in these areas to gather, transport, process, fractionate, store or otherwise handle the hydrocarbons that are produced. The combined company will compete with others, including producers of oil and natural gas, for any such production on the basis of many factors, including:

  •  geographic proximity to the production;
 
  •  costs of connection;
 
  •  available capacity;
 
  •  rates; and
 
  •  access to markets.

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The combined company’s debt level may limit its future financial and operating flexibility; Enterprise’s credit ratings were lowered recently.

      As of March 31, 2004, we had approximately $2.2 billion of consolidated debt outstanding. As of the same date, GulfTerra had approximately $1.8 billion of consolidated debt. The consolidated balance sheet of the combined company will have significant leverage. Assuming that this offering, the May 2004 common unit offerings and the merger had been completed on March 31, 2004, the combined company would have had approximately $4.2 billion of consolidated debt on a pro forma as adjusted basis. The amount of the combined company’s debt could have several important effects on its future operations, including, among other things:

  •  a significant portion of the combined company’s cash flow from operations will be dedicated to the payment of principal and interest on outstanding debt and will not be available for other purposes, including payment of distributions;
 
  •  credit rating agencies may view the combined company’s debt level negatively;
 
  •  covenants contained in our and GulfTerra’s existing debt arrangements will require the combined company to continue to meet financial tests that may adversely affect its flexibility in planning for and reacting to changes in its business;
 
  •  the combined company’s ability to obtain additional financing for working capital, capital expenditures, acquisitions and general partnership purposes may be limited;
 
  •  the combined company may be at a competitive disadvantage relative to similar companies that have less debt; and
 
  •  the combined company may be more vulnerable to adverse economic and industry conditions as a result of its significant debt level.

      Our public debt indentures currently do not limit the amount of future indebtedness that we can create, incur, assume or guarantee. Our revolving credit facilities and the merger agreement, however, restrict our ability to incur additional debt, though any debt we may incur in compliance with these restrictions may still be substantial. Likewise, GulfTerra’s public debt indentures, its revolving credit facility and the merger agreement restrict its ability to incur additional debt; however, any debt that it may incur in compliance with these restrictions may still be substantial. The incurrence of additional debt by us or GulfTerra could exacerbate any risks associated with the liquidity of the combined company.

      Each of our and GulfTerra’s revolving credit facilities and indentures for its public debt contain conventional financial covenants and other restrictions. A breach of any of these restrictions by Enterprise or GulfTerra, as applicable, could permit the lenders to declare all amounts outstanding under those debt agreements to be immediately due and payable and, in the case of the credit facilities, to terminate all commitments to extend further credit.

      In May 2004, both Moody’s Investors Service and Standard & Poor’s Ratings Services lowered their corporate credit ratings on Enterprise. Moody’s lowered its rating on Enterprise from Baa2 (investment grade) to Baa3 (investment grade) with a negative outlook. Standard & Poor’s lowered its rating on Enterprise from BBB- (investment grade) with a negative outlook to BB+ (non-investment grade) with a stable outlook. Moody’s and Standard & Poor’s current corporate credit rating on GulfTerra are Ba3 (non-investment grade) and BB (non-investment grade), respectively. After completion of the merger, these credit rating agencies may continue to view our debt, and therefore the debt of the combined company, negatively.

      If one or both of these credit rating agencies were to further downgrade our or the combined company’s corporate credit, then we or the combined company could experience a further increase in our borrowing costs, difficulty accessing capital markets or a reduction in the market price of our common units. Such a development could adversely affect our or the combined company’s ability to obtain financing for working capital, capital expenditures, acquisitions and to refinance existing indebtedness and could adversely affect our ability to make cash distributions to our unitholders. Additionally, if our credit rating by Moody’s declines below Baa3 (investment grade) in combination with our credit rating at Standard & Poor’s remaining at BB+

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(non-investment grade) or below, the $54 million principal balance of our loan from Mississippi Business Finance Corporation, or MBFC, and all related accrued and unpaid interest would become immediately due and payable 120 days following such event. If such an event occurred, we would have to either redeem the MBFC loan or provide an alternative credit agreement to support our obligation under the MBFC loan.

      The combined company’s ability to access the capital markets to raise capital on favorable terms will be affected by the combined company’s debt level, the amount of its debt maturing in the next several years and current maturities, and by adverse market conditions resulting from, among other things, general economic conditions, contingencies and uncertainties that are difficult to predict and impossible to control. If the combined company is unable to access the capital markets on favorable terms in the future, it might be forced to seek extensions for some of its short-term securities or to refinance some of its debt obligations through bank credit, as opposed to long-term public debt securities or equity securities. The price and terms upon which the combined company might receive such extensions or additional bank credit, if at all, could be more onerous than those contained in existing debt agreements. Any such arrangements could, in turn, increase the risk that the combined company’s leverage may adversely affect its future financial and operating flexibility and its ability to pay cash distributions at expected rates.

 
The closing of the merger will trigger a repurchase obligation with respect to GulfTerra’s outstanding senior notes and senior subordinated notes and will require GulfTerra to amend or refinance its credit facility.

      The closing of the merger will constitute a “change of control” under GulfTerra’s indentures for its senior notes and senior subordinated notes. As a result, under the indentures GulfTerra (as our wholly-owned subsidiary after the merger) will be obligated to offer to purchase each holder’s senior subordinated notes at 101% of their principal amount, plus accrued interest. GulfTerra will also be obligated to offer to purchase each holder’s senior notes at 101% of their principal amount, plus accrued interest, unless, among other things, the change of control (1) does not result in a ratings downgrade of the GulfTerra senior notes by either Moody’s Investors Services or Standard & Poor’s no later than 30 days after the change of control has occurred and (2) less than $250 million in aggregate principal amount of the GulfTerra senior subordinated notes are repurchased in response to the same change of control. GulfTerra currently has $250 million aggregate principal amount of senior notes outstanding and $672 million aggregate principal amount of senior subordinated notes outstanding.

      Separately from the indenture requirements, in connection with the closing of the merger, we intend to make a tender offer to purchase GulfTerra’s outstanding senior and senior subordinated notes at a market-based price and to finance the tender offer through one or more issuances of debt securities and/or through a temporary acquisition term facility. The size, terms and timing of any future debt offerings are subject to market conditions that are beyond our control.

      If we are unable to complete these financing plans, GulfTerra or the combined company will need to make an offer to repurchase these notes, or GulfTerra may seek to amend the indentures to waive the repurchase obligation or otherwise refinance its senior and senior subordinated notes. If GulfTerra makes an offer to repurchase the notes, it is possible that holders of a large amount of GulfTerra’s notes may exercise their repurchase right, in which case the combined company would be required to raise significant amounts of capital in the short term to fulfill GulfTerra’s repurchase obligations. If GulfTerra were unable to meet its repurchase obligations, it would result in an event of default under GulfTerra’s indentures, which would trigger an event of default under GulfTerra’s credit facility, which includes its revolving credit facility and senior secured term loan facility.

      The closing of the merger will also constitute a “change of control” and, thus, an event of default under GulfTerra’s credit facility. To avoid a default, we, GulfTerra or the combined company must refinance or amend that facility at or before the closing of the merger. We currently intend to refinance GulfTerra’s credit facility at or before the closing of the merger, however, if we are not able to do so, we have reasonable grounds to believe that we will have the ability to amend the facility prior to the closing of the merger. If GulfTerra’s

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credit facility is not refinanced or amended prior to closing, the resulting default would have a material adverse effect on the combined company.
 
The combined company may not be able to fully execute its growth strategy if it encounters illiquid capital markets or increased competition for qualified assets.

      The strategy of the combined company contemplates growth through the development and acquisition of a wide range of midstream and other energy infrastructure assets while maintaining a strong balance sheet. This strategy includes constructing and acquiring additional assets and businesses to enhance the combined company’s ability to compete effectively and diversify its asset portfolio, thereby providing more stable cash flow. Both companies regularly consider and enter into discussions regarding, and are currently contemplating, potential joint ventures, stand alone projects or other transactions that they believe will present opportunities to realize synergies, expand their respective roles in the energy infrastructure business and increase their respective market positions.

      The combined company may require substantial new capital to finance the future development and acquisition of assets and businesses. Limitations on the combined company’s access to capital will impair its ability to execute this strategy. Expensive capital will limit the combined company’s ability to develop or acquire accretive assets. The combined company may not be able to raise the necessary funds on satisfactory terms, if at all.

      In addition, both companies are experiencing increased competition for the assets they purchase or contemplate purchasing. Increased competition for a limited pool of assets could result in the combined company losing to other bidders more often or acquiring assets at higher prices. Either occurrence would limit the combined company’s ability to fully execute its growth strategy. The combined company’s inability to execute its growth strategy may materially adversely impact the market price of its securities.

 
The combined company’s growth strategy may adversely affect its results of operations if it does not successfully integrate the businesses that it acquires or if the combined company substantially increases its indebtedness and contingent liabilities to make acquisitions.

      The combined company’s ability to successfully execute its growth strategy is dependent upon making accretive acquisitions. As a result, from time to time, the combined company will evaluate and acquire assets and businesses that it believes complement its existing operations. Similar to the risks associated with integrating Enterprise’s operations with GulfTerra’s operations, the combined company may be unable to integrate successfully businesses it acquires in the future. The combined company may incur substantial expenses or encounter delays or other problems in connection with its growth strategy that could negatively impact its results of operations, cash flows and financial condition. Moreover, acquisitions and business expansions involve numerous risks, including:

  •  difficulties in the assimilation of the operations, technologies, services and products of the acquired companies or business segments;
 
  •  inefficiencies and complexities that can arise because of unfamiliarity with new assets and the businesses associated with them, including with their markets; and
 
  •  diversion of the attention of management and other personnel from day-to-day business to the development or acquisition of new businesses and other business opportunities.

      If consummated, any acquisition or investment would also likely result in the incurrence of indebtedness and contingent liabilities and an increase in interest expense and depreciation, depletion and amortization expenses. As a result, the combined company’s capitalization and results of operations may change significantly following an acquisition. A substantial increase in the combined company’s indebtedness and contingent liabilities could have a material adverse effect on its business.

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The combined company’s operating cash flows from its capital projects may not be immediate.

      GulfTerra is engaged in several capital expansion projects and “greenfield” projects for which significant capital has been expended, and the combined company’s operating cash flow from a particular project may not increase immediately following its completion. For instance, if the combined company builds a new pipeline or platform or expands an existing facility, the design, construction, development and installation may occur over an extended period of time, and the combined company may not receive any material increase in operating cash flow from that project until after it is placed in service. If the combined company experiences unanticipated or extended delays in generating operating cash flow from these projects, it may be required to reduce or reprioritize its capital budget, sell non-core assets, access the capital markets or decrease distributions to unitholders in order to meet its capital requirements.

 
The combined company’s actual construction, development and acquisition costs could exceed forecasted amounts.

      The combined company will have significant expenditures for the development, construction or other acquisition of energy infrastructure assets, including some construction and development projects with significant technological challenges. For example, underwater operations, especially those in water depths in excess of 600 feet, are very expensive and involve much more uncertainty and risk, and if a problem occurs, the solution, if one exists, may be very expensive and time consuming. Accordingly, there is an increase in the frequency and amount of cost overruns related to underwater operations, especially in depths in excess of 600 feet. The combined company may not be able to complete its projects, whether in deep water or otherwise, at the costs currently estimated.

 
The combined company may be unable to cause its joint ventures to take or not to take certain actions unless some or all of its joint venture participants agree.

      We and GulfTerra participate in several joint ventures, and the combined company will continue that participation after the merger. Due to the nature of some of these joint ventures, each participant in each of these joint ventures has made substantial investments in the joint venture and, accordingly, has required that the relevant organizational documents contain certain features designed to provide each participant with the opportunity to participate in the management of the joint venture and to protect its investment in that joint venture, as well as any other assets which may be substantially dependent on or otherwise affected by the activities of that joint venture. These participation and protective features include a corporate governance structure that requires at least a majority in interest vote to authorize many basic activities and requires a greater voting interest (sometimes up to 100%) to authorize more significant activities. Examples of these more significant activities are large expenditures or contractual commitments, the construction or acquisition of assets, borrowing money or otherwise raising capital, transactions with affiliates of a joint venture participant, litigation and transactions not in the ordinary course of business, among others. Thus, without the concurrence of joint venture participants with enough voting interests, the combined company may be unable to cause any of its joint ventures to take or not to take certain actions, even though those actions may be in the best interest of the particular joint venture or the combined company.

      Moreover, any joint venture owner may sell, transfer or otherwise modify its ownership interest in a joint venture, whether in a transaction involving third parties or the other joint venture owners. Any such transaction could result in the combined company partnering with different or additional parties.

 
The interruption of distributions to the combined company from its subsidiaries and joint ventures may affect the combined company’s ability to satisfy its obligations and to make cash distributions to its unitholders.

      Like our company and GulfTerra, the combined company will be a holding company with no business operations. The only significant asset of the combined company will be the equity interests it owns in its subsidiaries and joint ventures. As a result, the combined company will depend upon the earnings and cash

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flow of its subsidiaries and joint ventures and the distribution of that cash to the combined company in order to meet the combined company’s obligations and to allow it to make distributions to its unitholders.

      GulfTerra is party to senior and senior subordinated note indentures under which approximately $922 million in principal amount of debt securities currently is outstanding. These indentures restrict GulfTerra’s and its subsidiaries’ ability to make cash distributions. If we and GulfTerra are not able to effect amendments to these indentures or to refinance the senior and senior subordinated notes, these restrictions could significantly limit GulfTerra’s ability to distribute cash to us after the merger.

      In addition, our and GulfTerra’s joint venture charter documents typically vest in its management committee sole discretion regarding the occurrence and amount of distributions. Some of the joint ventures in which the combined company will participate have separate credit arrangements that contain various restrictive covenants. Among other things, those covenants may limit or restrict the joint venture’s ability to make distributions to the combined company under certain circumstances. Accordingly, the combined company’s joint ventures may, following the merger, be unable to make distributions to the combined company at current levels or at all.

 
A natural disaster, catastrophe or other event could result in severe personal injury, property damage and environmental damage, which could curtail the combined company’s operations and otherwise materially adversely affect its cash flow.

      Some of the combined company’s operations will involve risks of personal injury, property damage and environmental damage, which could curtail the combined company’s operations and otherwise materially adversely affect its cash flow. For example, natural gas facilities operate at high pressures, sometimes in excess of 1,100 pounds per square inch. The combined company will also operate oil and natural gas facilities located underwater in the Gulf of Mexico, which can involve complexities, such as extreme water pressure. Virtually all of the combined company’s operations will be exposed to potential natural disasters, including hurricanes, tornadoes, storms, floods and earthquakes.

      If one or more facilities that are owned by the combined company or that deliver oil, natural gas or other products to the combined company are damaged by severe weather or any other disaster, accident, catastrophe or event, the combined company’s operations could be significantly interrupted. Similar interruptions could result from damage to production or other facilities that supply the combined company’s facilities or other stoppages arising from factors beyond its control. These interruptions might involve significant damage to people, property or the environment, and repairs might take from a week or less for a minor incident to six months or more for a major interruption. Additionally, some of the storage contracts that the combined company will be a party to will obligate it to indemnify its customers for any damage or injury occurring during the period in which the customers’ natural gas is in its possession. Any event that interrupts the fees generated by the combined company’s energy infrastructure assets, or which causes it to make significant expenditures not covered by insurance, could reduce the combined company’s cash available for paying its interest obligations as well as unitholder distributions and, accordingly, adversely affect the market price of the combined company’s securities.

      We expect that the combined company will maintain adequate insurance coverage, although insurance will not cover many types of interruptions that might occur. As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. As a result, the combined company may not be able to renew its existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all. If the combined company were to incur a significant liability for which it were not fully insured, it could have a material adverse effect on the combined company’s financial position and results of operations. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur.

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An impairment of goodwill could reduce the combined company’s earnings.

      We had recorded only $82.4 million of goodwill on our consolidated balance sheet as of March 31, 2004. Based on information currently available, we expect to record approximately $2.6 billion of goodwill or other intangible assets upon completion of the merger, but that estimate is subject to change. Please read “Pro Forma Sensitivity Analysis” beginning on page F-19 of this prospectus supplement. Consequently, following the merger, we expect that approximately $2.7 billion, representing approximately 25% of the combined company’s consolidated assets on a pro forma basis, may be recorded as goodwill or other intangible assets. Goodwill is recorded when the purchase price of a business exceeds the fair market value of the tangible and separately measurable intangible net assets. GAAP will require the combined company to test goodwill for impairment on an annual basis or when events or circumstances occur indicating that goodwill might be impaired. Long-lived assets such as intangible assets with finite useful lives are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If the combined company were to determine that any of its goodwill or intangible assets were impaired, it would be required to take an immediate charge to earnings with a correlative effect on partners’ equity and balance sheet leverage as measured by debt to total capitalization.

 
Increases in interest rates could adversely affect the combined company’s business.

      In addition to the combined company’s exposure to commodity prices, the combined company will have significant exposure to increases in interest rates. Assuming that the merger, the May 2004 common unit offerings and this offering had been completed on March 31, 2004, the combined company would have approximately $4.2 billion of consolidated debt on a pro forma basis (before any intended refinancing transactions), of which $3.3 billion would be at fixed interest rates and $0.9 billion would be at variable interest rates. As a result, the combined company’s results of operations, cash flows and financial condition, could be materially adversely affected by significant increases in interest rates. Please read “Pro Forma Sensitivity Analysis” beginning on page F-19 of this prospectus supplement.

 
The use of derivative financial instruments could result in material financial losses to the combined company.

      Both Enterprise and GulfTerra historically have sought to limit a portion of the adverse effects resulting from changes in oil and natural gas commodity prices and interest rates by using financial derivative instruments and other hedging mechanisms from time to time. To the extent that the combined company hedges its commodity price and interest rate exposures, it will forego the benefits it would otherwise experience if commodity prices or interest rates were to change in its favor. In addition, even though monitored by management, hedging activities can result in losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the hedge arrangement, the hedge is imperfect, or hedging policies and procedures are not followed.

 
The combined company’s pipeline integrity program may impose significant costs and liabilities on it.

      In December 2003, the U.S. Department of Transportation issued a final rule (effective as of February 14, 2004) requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” The final rule resulted from the enactment of the Pipeline Safety Improvement Act of 2002. At this time, we cannot predict the outcome of this rule on the combined company. However, the combined company will continue Enterprise’s and GulfTerra’s pipeline integrity testing programs, which are intended to assess and maintain the integrity of their pipelines. While the costs associated with the pipeline integrity testing itself are not large, the results of these tests could cause the combined company to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of its pipelines.

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Environmental costs and liabilities and changing environmental regulation could materially affect the combined company’s cash flow.

      The combined company’s operations will be subject to extensive federal, state and local regulatory requirements relating to environmental affairs, health and safety, waste management and chemical and petroleum products. Governmental authorities have the power to enforce compliance with applicable regulations and permits and to subject violators to civil and criminal penalties, including substantial fines, injunctions or both. Third parties may also have the right to pursue legal actions to enforce compliance.

      The combined company will make expenditures in connection with environmental matters as part of normal capital expenditure programs. However, future environmental law developments, such as stricter laws, regulations, permits or enforcement policies, could significantly increase some costs of the combined company’s operations, including the handling, manufacture, use, emission or disposal of substances and wastes. Moreover, as with other companies engaged in similar or related businesses, the combined company’s operations will have some risk of environmental costs and liabilities because it handles petroleum products.

 
Federal, state or local regulatory measures could materially adversely affect our business and the business of the combined company.

      The Federal Energy Regulatory Commission, or FERC, regulates our interstate natural gas pipelines and interstate NGL and petrochemical pipelines, while state regulatory agencies regulate our intrastate natural gas and NGL pipelines, intrastate storage facilities and gathering lines. This federal and state regulation extends to such matters as:

  •  rate structures;
 
  •  rates of return on equity;
 
  •  recovery of costs;
 
  •  the services that our regulated assets are permitted to perform;
 
  •  the acquisition, construction and disposition of assets; and
 
  •  to an extent, the level of competition in that regulated industry.

      Our 2003 Annual Report on Form 10-K, which is incorporated by reference into this prospectus supplement, contains a general overview of FERC and state regulation applicable to the combined company’s energy infrastructure assets. This regulatory oversight can affect certain aspects of the combined company’s business and the market for our products and could materially adversely affect our cash flow. Please read “Business and Properties — Regulation and Environmental Matters” in our Annual Report on Form 10-K for the year ended December 31, 2003.

      Under the Natural Gas Act, FERC has authority to regulate our natural gas companies that provide natural gas pipeline transportation services in interstate commerce. Its authority to regulate those services includes the rates charged for the services, terms and conditions of service, certification and construction of new facilities, the extension or abandonment of services and facilities, the maintenance of accounts and records, the acquisition and disposition of facilities, the initiation and discontinuation of services, and various other matters. Pursuant to FERC’s jurisdiction over interstate gas pipeline rates, existing pipeline rates may be challenged by complaint and proposed rate increases may be challenged by protest.

      FERC also has authority under the Interstate Commerce Act, or ICA, to regulate the rates, terms, and conditions applied to our interstate pipelines engaged in the transportation of NGLs and petrochemicals (commonly known as “oil pipelines”). Pursuant to the ICA, oil pipeline rates can be challenged at FERC either by protest, when they are initially filed or increased, or by complaint at any time they remain on file with the jurisdictional agency.

      We have interests in offshore natural gas pipeline facilities offshore from Texas and Louisiana. These facilities are subject to regulation by FERC and other federal agencies, including the Department of Interior,

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under the Outer Continental Shelf Lands Act, and by the Department of Transportation’s Office of Pipeline Safety under the Natural Gas Pipeline Safety Act.

      Our intrastate NGL and gas pipelines are subject to regulation by state regulatory agencies. Our natural gas gathering lines are also subject to regulation in many states. Our intrastate natural gas pipelines are located in Louisiana, while our intrastate NGL pipelines are located in Texas and Louisiana. We also have natural gas underground storage facilities in Louisiana, Mississippi and Texas. Although state regulation is typically less onerous than at FERC, proposed and existing rates subject to state regulation are also subject to challenge by protest and complaint, respectively.

      We are subject to ratable take and common purchaser statutes in certain states where we operate. Ratable take statues generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to purchase or transport natural gas. Federal law leaves any economic regulation of natural gas gathering to the states, and some of the states in which we operate have adopted complaint-based or other limited economic regulation of natural gas gathering activities. States in which we operate that have adopted some form of complaint-based regulation, like Texas, generally allow natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and rate discrimination.

      If the proposed merger with GulfTerra is consummated, the combined company will be subject to increased regulatory oversight by FERC and state regulatory agencies as certain of GulfTerra’s companies, assets and service are regulated by FERC, including its interstate natural gas pipeline system, interstate natural gas storage facilities and service provided by its intrastate natural gas pipelines pursuant to Section 311 of the Natural Gas Policy Act. For example, High Island Offshore System, L.L.C., or HIOS, an interstate natural gas pipeline owned by GulfTerra, is subject to a pending rate case before FERC. GulfTerra is seeking to increase its transportation rates, but several parties have protested the increased rate. FERC accepted HIOS’ tariff sheets implementing the new rates subject to refund and set certain issues for hearing before an Administrative Law Judge, or ALJ. A hearing was held in November 2003. The ALJ issued her initial decision on that hearing on April 22, 2004, finding, inter alia, that HIOS’s overall cost-of-service should be approximately thirty percent lower than HIOS’s proposed cost-of-service. The initial decision has no binding effect, however, and several parties, including HIOS, have filed briefs on exceptions to the initial decision with the FERC. FERC action on those briefs is currently pending. FERC’s decision will dictate HIOS’ rates, thereby impacting the combined company’s cash flow.

      Additionally, in December 1999, GulfTerra Texas (formerly EPGT Texas) filed a petition with the FERC for approval of its rates for interstate transportation service pursuant to Section 311 of the NGPA. In June 2002, the FERC issued an order that required revisions to GulfTerra Texas’ proposed maximum rates. The changes ordered by the FERC involve reductions to rate of return and depreciation rates, and revisions to the proposed rate design, including a requirement to state separately rates for gathering service. The FERC also ordered refunds to customers for the difference, if any, between the originally proposed levels and the revised rates ordered by the FERC. In July 2002, GulfTerra Texas requested rehearing on certain issues raised by the FERC’s order, including the depreciation rates and the requirement to state separately a gathering rate. On February 25, 2004, the FERC issued an order denying GulfTerra Texas’ request for rehearing and ordering GulfTerra Texas to file a calculation of refunds and a refund plan. GulfTerra Texas filed that information with the FERC on July 12, 2004. GulfTerra Texas’s filing includes its calculation of approximately $1,200 in refunds due to GulfTerra Texas and notes that GulfTerra Texas would update the calculation, upon a final FERC order in the proceeding, to include any additional amounts, including interest due to GulfTerra Texas. A final FERC order is currently pending. Additionally, the FERC’s February 25, 2004 order directed GulfTerra Texas to file a new rate case or justification of existing rates within three years. GulfTerra Texas has filed a timely request for rehearing of that requirement, which request is currently pending.

      On July 20, 2004, the United States Court of Appeals for the District of Columbia Circuit issued its opinion in BP West Coast Products, LLC v. FERC, which upheld FERC’s determination that SFPP’s rates

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were grandfathered rates under the Energy Policy Act and that SFPP’s shippers had not demonstrated substantially changed circumstances that would justify modification of those rates. The court also vacated the FERC’s Lakehead policy. In Lakehead, the FERC allowed a regulated entity organized as a master limited partnership to include in its cost of service an income tax allowance to the extent that its unitholders were corporations subject to income tax. The court remanded the issue of whether SFPP’s revised cost of service without the tax allowance would qualify as a substantially changed circumstance that would justify modification of SFPP’s rates. Because the court remanded to the FERC and because the FERC’s ruling on the substantially changed circumstances issue will focus on the facts and record presented to it, it is not clear what impact, if any, the opinion will have on our rates or on the rates of other FERC-jurisdictional pipelines organized as tax pass-through entities. Moreover, it is not clear whether FERC’s action taken in response to BP West Coast will be challenged and, if so, whether it will withstand further FERC or judicial review.

      The combined company will also be subject to regulatory oversight by state regulatory agencies in additional jurisdictions. GulfTerra owns significant assets, such as its interests in gathering systems in Alabama, Colorado, Mississippi, New Mexico and Texas, that are regulated by state regulatory agencies. GulfTerra also has intrastate natural gas pipelines regulated by state regulatory agencies in Alabama and Texas. GulfTerra’s NGL gathering and intrastate transportation pipelines are located in Texas. All of these facilities are regulated to some degree by state regulatory agencies.

      GulfTerra’s offshore oil and gas pipelines also are subject to oversight by FERC and other federal agencies under Outer Continental Shelf Lands Act, and the Department of Transportation’s Office of Pipeline Safety under the Natural Gas Pipeline Safety Act of 1968.

Risk Related to Our Common Units as a Result of Our Partnership Structure

      In addition to the risks set forth in the accompanying prospectus under “Risk Factors — Risks Relating to Our Common Units as a Result of Our Partnership Structure,” the following risk will also apply to an investment in our common units.

 
A large number of our outstanding common units or GulfTerra’s common units may be sold in the market following this offering, which may depress the market price of our common units.

      Sales of a substantial number of our common units in the public market following this offering could cause the market price of our common units to decline. Upon completion of this offering, a total of approximately 251,924,894 of our common units will be outstanding. Shell US Gas & Power LLC, which will own 41,000,000 of our common units following this offering, representing approximately 16.0% of our outstanding common units after giving effect to this offering, has publicly announced its intention to reduce its holdings of our common units on an orderly schedule over a period of years, taking into account market conditions. Under a registration rights agreement, we are obligated, subject to certain limitations and conditions, to register the common units held by Shell US Gas & Power for resale.

      Additionally, after the closing of the merger, El Paso Corporation will own 13,454,499 of our common units, representing approximately 3.7% of the combined company. Six months after the closing of the merger, or earlier in certain circumstances, El Paso Corporation will have the right for three years to contribute all of its 9.9% membership interest in our general partner to our general partner in return for a number of common units equal to 9.9% of the aggregate quarterly distribution paid by us to our general partner divided by the preceding quarterly distribution per unit paid to the holders of our common units. Our general partner may elect to deliver Enterprise common units that it owns (which it may acquire from an affiliate of EPCO), an equivalent cash amount or a combination of Enterprise common units and cash. Under a registration rights agreement, we are obligated, subject to certain limitations and conditions, to register the common units held by El Paso Corporation for resale. Sales of a substantial number of these units in the trading markets, whether in a single transaction or series of transactions, or the possibility that these sales may occur, could reduce the market price of our outstanding common units. In addition, these sales, or the possibility that these sales may occur, could make it more difficult for us to sell our common units in the future.

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      GulfTerra has outstanding 25 Series F1 convertible units and 80 Series F2 convertible units, all of which are owned by one holder. Subject to certain limitations, the holder may, upon payment of a conversion price determined by reference to the market price of GulfTerra’s common units at the time of conversion, convert its Series F convertible units into a maximum of 6,921,824 GulfTerra common units. The GulfTerra common units to be issued upon conversion have been registered with the SEC. Following the announcement of our proposed merger with GulfTerra, the trading prices of GulfTerra common units and Enterprise common units have influenced one another due to market expectations concerning the likelihood of the consummation of the proposed merger and the future prospects of the combined company. If the holder were to dispose of a substantial portion of the GulfTerra common units it owns or receives upon conversion of the Series F convertible units in the trading markets, it could depress the market price of Enterprise’s common units.

Tax Risks Related to Owning Enterprise Common Units

      Discussed below are federal income tax risks related to the merger and owning and disposing of common units received in the merger. You are urged to read “Tax Consequences” in this prospectus supplement and “Tax Consequences” and “Risk Factors — Tax Risks to Common Unitholders” in the accompanying prospectus for a more complete discussion of the federal income tax risks related to owning and disposing of common units.

 
It is possible that income from the settlement of certain interest rate swap agreements may cause us to be treated as a corporation for federal income tax purposes, which would substantially reduce the cash available for distribution to our unitholders.

      On April 27, 2004, we received approximately $104.5 million upon settlement of interest rate swap agreements entered into on March 17, 2004 to hedge interest rate risk with respect to debt of varying maturities expected to be incurred in connection with the proposed merger with GulfTerra. If, within a reasonable interval around September 30, 2004, we incur the expected debt or other debt for which the interest rate swap agreements served to reasonably reduce risk (“hedged debt”), our income with respect to the agreements will be taken into account over the life of that debt for federal income tax purposes. To the extent we are unable to timely incur that hedged debt, the income from the interest rate swap agreements will be recognized in 2004 for federal income tax purposes.

      We have received an opinion of counsel that, based on current law and certain representations made by us and our general partner, we will be classified as a partnership for federal income tax purposes. In rendering its opinion, our counsel has relied upon a factual representation with respect to the interest rate swap agreements regarding our intent and ability to timely enter into the hedged debt. The continuing validity of our counsel’s opinion that we will be classified as a partnership for federal income tax purposes may be impacted to the extent this or any of the representations made by us and our general partner are factually incorrect. If all of the income from the interest rate swap agreements is recognized in 2004 because we are unable to timely incur the hedged debt, and if that income is not “qualifying income” within the meaning of Section 7704(d) of the Internal Revenue Code, then it is possible that less than 90% of our gross income will be “qualifying income” and that we will therefore be treated as a corporation, rather than as a partnership, for federal income tax purposes effective as of January 1, 2004. This risk may increase if our proposed merger with GulfTerra is delayed or does not occur. For more information on the assumptions underlying counsel’s opinion, please read “Tax Consequences.”

      If we were classified as a corporation for federal income tax purposes, we would pay federal income tax on our income at the corporate tax rate, which is currently a maximum of 35%, and we likely would pay state taxes as well. Distributions to you would generally be taxed again to you as corporate distributions, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, the cash available for distribution to you would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the after-tax return to you, likely causing a substantial reduction in the value of the common units. For further explanation of the consequences if we fail to meet the “qualifying income” exception and are taxable as a corporation, please see “Tax Consequences — Partnership Status” in the accompanying prospectus.

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The merger may result in income recognition by GulfTerra and Enterprise unitholders.

      As a result of the merger, each Enterprise and GulfTerra common unitholder’s share of nonrecourse liabilities will be recalculated. Each Enterprise and GulfTerra unitholder will be treated as receiving a deemed cash distribution equal to the excess, if any, of such unitholder’s share of nonrecourse liabilities immediately before the merger and such unitholder’s share of nonrecourse liabilities immediately following the merger. If the amount of the deemed cash distribution received by a GulfTerra or Enterprise common unitholder exceeds the unitholder’s basis in its partnership interest, such unitholder will recognize gain in an amount equal to such excess. The application of the rules governing the allocation of nonrecourse liabilities in the context of the merger is complex and subject to uncertainty. While Enterprise has agreed to apply these rules, to the extent permissible, in a manner that minimizes the amount of any net decrease in the amount of debt allocable to the GulfTerra and Enterprise unitholders, there can be no assurance that there will not be a net decrease in the amount of nonrecourse liabilities allocable to a GulfTerra common unitholder or an Enterprise common unitholder as a result of the merger.

 
No ruling has been obtained with respect to the tax consequences of the merger.

      While it is anticipated that no gain or loss will be recognized by an Enterprise unitholder or GulfTerra unitholder as a result of the merger (except with respect to a net decrease in a unitholder’s share of nonrecourse liabilities discussed below), no ruling has been or will be requested from the Internal Revenue Service with respect to the tax consequences of the merger. Instead, Enterprise and GulfTerra are relying on the opinions of their respective counsel as to the tax consequences of the merger, and counsel’s conclusions may not be sustained if challenged by the Internal Revenue Service.

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USE OF PROCEEDS

      We expect to receive net proceeds of approximately $281.7 million from the sale of the 13,750,000 common units we are offering (including the net capital contribution of $5.7 million from our general partner to maintain its 2% general partner interest). The net proceeds are based on an assumed public offering price of $20.90 per common unit after deducting underwriting discounts and commissions and estimated offering expenses payable by us. The underwriters will receive no discount or commission on the sale of an aggregate 1,751,500 common units to an entity controlled by Mr. Duncan, to Mr. Andras and to two other members of our senior management team. If the underwriters exercise their over-allotment option in full, we will receive net proceeds of approximately $323.9 million, including a proportionate net capital contribution of $6.5 million from our general partner.

      We will use a portion of the net proceeds from this offering, including our general partner’s proportionate capital contribution, (i) to temporarily reduce borrowings outstanding under our multi-year revolving credit facility, which indebtedness was incurred for working capital purposes and to finance various business acquisitions and investments, and (ii) to fund a portion of the purchase price at the closing of the Step Two and Step Three merger transactions or, in the event the merger does not close, for working capital purposes or for future acquisitions. We will use the net proceeds from any exercise of the underwriters’ over-allotment option, including any additional capital contribution from our general partner, in the manner discussed in the preceding sentence. As of July 29, 2004, our multi-year revolving credit facility had an interest rate of approximately 2.2%. Amounts paid on our multi-year revolving credit facility may be reborrowed from time to time.

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PRICE RANGE OF COMMON UNITS AND DISTRIBUTIONS

      On July 29, 2004, we had 238,174,894 common units outstanding, beneficially held by approximately 43,000 holders. Our common units are traded on the New York Stock Exchange under the symbol “EPD.”

      The following table sets forth, for the periods indicated, the high and low sales price ranges for our common units, as reported on the New York Stock Exchange Composite Transaction Tape, and the amount, record date and payment date of the quarterly cash distributions paid per common unit. The last reported sales price of our common units on the New York Stock Exchange on July 29, 2004 was $20.90 per common unit.

                                           
Cash Distribution History
Price Ranges

Per
High Low Unit(1) Record Date Payment Date





2002
                                       
 
1st Quarter
  $ 25.80     $ 22.95     $ 0.3350       April 30, 2002       May 10, 2002  
 
2nd Quarter
    24.50       16.25       0.3350       July 31, 2002       August 11, 2002  
 
3rd Quarter
    22.23       15.00       0.3450       October 31, 2002       November 12, 2002  
 
4th Quarter
    19.80       16.41       0.3450       January 31, 2003       February 11, 2003  
2003
                                       
 
1st Quarter
  $ 21.00     $ 17.85     $ 0.3625       April 30, 2003       May 12, 2003  
 
2nd Quarter
    24.69       20.62       0.3625       July 31, 2003       August 11, 2003  
 
3rd Quarter
    24.10       20.25       0.3725       October 31, 2003       November 12, 2003  
 
4th Quarter
    24.98       20.76       0.3725       January 30, 2004       February 11, 2004  
2004
                                       
 
1st Quarter
  $ 24.72     $ 21.75     $ 0.3725       April 30, 2004       May 12, 2004  
 
2nd Quarter
    23.84       20.00       0.3725 (2)     July 30, 2004       August 6, 2004  
 
3rd Quarter (through July 29, 2004)
    22.89       20.84        —              


(1)  For each quarter, we paid an identical cash distribution on all outstanding subordinated units. The remaining outstanding subordinated units converted into an equal number of common units on August 1, 2003. In addition, we paid an identical cash distribution per unit to the holder of our Class B special units prior to their conversion to common units on July 29, 2004.
 
(2)  On July 14, 2004, our general partner declared a quarterly cash distribution for the second quarter of 2004 of $0.3725 per unit. The distribution will be paid on August 6, 2004 to unitholders of record at the close of business on July 30, 2004. Holders of units purchased in this offering will not be entitled to receive this distribution.

      Under the merger agreement, we have agreed, subject to the terms of our partnership agreement, to increase the quarterly cash distribution for the first regular quarterly distribution after the merger closes to at least $0.395 per unit, or $1.58 per unit on an annualized basis.

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CAPITALIZATION

      The following table sets forth our capitalization as of March 31, 2004 on a consolidated historical basis and on a pro forma basis to give effect to the completion of Step Three of the proposed merger with GulfTerra and on an as adjusted basis to give effect to the May 2004 equity offering, the issuance of common units pursuant to our DRIP in May 2004, the conversion of the 4,413,549 Class B special units into an equal number of our common units and this offering. The historical data in the table is derived from and should be read in conjunction with our historical financial statements, including the accompanying notes, incorporated by reference in this prospectus supplement. The pro forma as adjusted financial information in the following table gives effect to:

  •  the completion of the proposed merger with GulfTerra and our acquisition of the South Texas midstream energy assets (through Step Three of the proposed merger);
 
  •  our other recent events, which include:

  •  the issuance of 17,250,000 common units in our May 2004 public equity offering and the application of the net proceeds (including our general partner’s proportionate contribution) to repay in full our $225 million interim term loan, and the use of the remaining proceeds to temporarily reduce debt under our revolving credit facilities;
 
  •  the issuance of 1,757,347 common units in connection with our DRIP in May 2004 and the use of proceeds from that offering for general partnership purposes; and
 
  •  the conversion of the 4,413,549 Class B special units into an equal number of our common units on July 29, 2004; and

  •  the issuance of 13,750,000 common units offered by this prospectus supplement, our general partner’s proportionate capital contribution and the application of the net proceeds from this offering to reduce borrowings under our multi-year revolving credit facility and to fund a portion of the purchase price at the closing of the Step Two and Step Three merger transactions.

      Please read our unaudited pro forma financial statements included elsewhere in this prospectus supplement for a complete description of the adjustments we have made to arrive at the pro forma financial measures that we present in the following table. You should also read our financial statements and notes that are incorporated by reference in this prospectus supplement for additional information regarding our capital structure.

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Enterprise Historical and Pro Forma Capitalization

As of March 31, 2004
                                     
Through As Adjusted
Step Three for Other As Adjusted
Enterprise Recent for this
Historical Pro Forma Events Offering(1)




(Dollars in millions)
Cash and cash equivalents
  $ 52.8     $ 85.1     $ 120.4     $ 120.4  
     
     
     
     
 
Long-term borrowings including current portion:
                               
 
Enterprise amounts:
                               
   
Interim Term Loan, repaid in May 2004
  $ 225.0     $ 225.0     $     $  
   
Acquisition term loans (Step Two and Step Three of proposed merger)
            669.9       669.9       510.1  
   
364-Day Revolving Credit facility, due October 2004
    90.0       90.0              
   
Multi-Year Revolving Credit facility, due November 2005
    160.0       160.0       121.9        
   
Senior Notes A, 8.25% fixed-rate, due March 2005
    350.0       350.0       350.0       350.0  
   
MBFC Loan, 8.70%, fixed-rate, due March 2005
    54.0       54.0       54.0       54.0  
   
Senior Notes B, 7.50% fixed-rate, due February 2011
    450.0       450.0       450.0       450.0  
   
Senior Notes C, 6.375% fixed-rate, due February 2013
    350.0       350.0       350.0       350.0  
   
Senior Notes D, 6.875% fixed-rate, due March 2033
    500.0       500.0       500.0       500.0  
   
Seminole Notes, 6.67% fixed-rate, $15 million due each December, 2004 through 2005
    30.0       30.0       30.0       30.0  
   
Other
    1.9       1.9       1.9       1.9  
 
GulfTerra amounts:
                               
   
Revolving credit facility
            387.0       387.0       387.0  
   
Senior secured term loan due 2007
            300.0       300.0       300.0  
   
Senior notes, 6.25% fixed-rate, due June 2010
            250.0       250.0       250.0  
   
Senior subordinated notes, 10.375% fixed-rate, due June 2009
            175.0       175.0       175.0  
   
Senior subordinated notes, 8.50% fixed-rate, due June 2010
            255.0       255.0       255.0  
   
Senior subordinated notes, 8.50% fixed-rate, due 2011
            167.5       167.5       167.5  
   
Senior subordinated notes, 8.50% fixed-rate, due June 2011
            154.0       154.0       154.0  
   
Senior subordinated notes, 10.625% fixed-rate, due December 2012
            134.0       134.0       134.0  
   
Unamortized balance of estimated increase in fair value related to assumption of GulfTerra debt upon completion of Step Two of proposed merger
            84.9       84.9       84.9  
   
Other
            1.7       1.7       1.7  
     
     
     
     
 
   
Total debt obligations
    2,210.9       4,789.9       4,436.8       4,155.1  
Minority interest
    88.5       90.3       90.3       90.3  
Partners’ equity:
                               
 
Common units
    1,576.6       4,401.4       4,916.1       5,192.1  
 
Class B special units
    99.6       135.1              
 
General partner
    34.2       92.6       100.4       106.1  
 
Treasury units
    (11.4 )     (11.4 )     (11.4 )     (11.4 )
 
Accumulated other comprehensive income
    21.9       21.9       21.9       21.9  
     
     
     
     
 
   
Total partners’ equity
    1,720.9       4,639.6       5,027.0       5,308.7  
     
     
     
     
 
   
Total capitalization
  $ 4,020.3     $ 9,519.8     $ 9,554.1     $ 9,554.1  
     
     
     
     
 

(1)  The amounts do not reflect related borrowing costs, the impact of our interest rate swaps or purchase accounting adjustments related to GulfTerra’s debt.

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BUSINESS AND PROPERTIES

Our Business and Properties

      This section summarizes information from our Annual Report on Form 10-K for the year ended December 31, 2003. For a more detailed discussion of our business, please read the “Business and Properties” section contained in our 2003 Annual Report on Form 10-K.

      Formed in 1998 as a limited partnership, our company is a leading North American midstream energy company that provides a wide range of services to producers and consumers of natural gas and NGLs. We provide integrated services to our customers and generate fee-based cash flow from multiple sources along our natural gas and NGL “value chain.” Our services include the:

  •  gathering and transmission of raw natural gas from both onshore and offshore Gulf of Mexico developments;
 
  •  processing of raw natural gas into a marketable product that meets industry quality specifications by removing mixed NGLs and impurities;
 
  •  purchase of natural gas for resale to our industrial, utility and municipal customers;
 
  •  transportation of mixed NGLs to fractionation facilities by pipeline;
 
  •  fractionation (or separation) of mixed NGLs produced as by-products of crude oil refining and natural gas production into component NGL products: ethane, propane, isobutene, normal butane and natural gasoline;
 
  •  transportation of NGL products to end-users by pipeline, railcar and truck;
 
  •  import and export of NGL products and petrochemical products through our dock facilities;
 
  •  fractionation of refinery-sourced propane/propylene mix into high purity propylene, propane and mixed butane;
 
  •  transportation of high purity propylene to end-users by pipeline;
 
  •  storage of natural gas, mixed NGLs, NGL products and petrochemical products;
 
  •  conversion of normal butane to isobutane through the process of isomerization;
 
  •  production of high-octane additives for motor gasoline from isobutane; and
 
  •  sale of NGLs and petrochemical products we produce and/or purchase for resale.

      In addition to our current strategic position in the Gulf of Mexico, we have access to major natural gas and NGL supply basins throughout the United States and Canada, including the Rocky Mountains, the San Juan and Permian basins, the Mid-Continent region and, through third-party pipeline connections, north into Canada’s Western Sedimentary basin. Our asset platform in the Gulf Coast region of the United States, combined with our Mid-America and Seminole pipeline systems, creates the only integrated natural gas and NGL transportation, fractionation, processing, storage and import/export network in North America.

Our Business Segments

      Our business has five reportable segments:

  •  Pipelines;
 
  •  Fractionation;
 
  •  Processing;
 
  •  Octane Enhancement; and
 
  •  Other.

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Pipelines

      Our Pipelines segment includes approximately 14,200 miles of NGL, petrochemical and natural gas pipelines located primarily in the Rocky Mountain, Mid-Continent and Gulf Coast regions of the United States. This segment also includes our storage and import/export terminalling businesses.

 
Fractionation

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

 
Processing

      Our Processing segment is comprised of our natural gas processing business and related NGL marketing activities. At the core of our natural gas processing business are 12 gas plants, located primarily in south Louisiana, that process raw natural gas into a product that meets pipeline and industry specifications by removing NGLs and impurities. In connection with our processing businesses, we receive a portion of the NGL production from these gas plants. This equity NGL production, together with the NGLs we purchase, supports the NGL marketing activities included in this operating segment.

      South Texas Midstream Assets. At the closing of the merger, we will also acquire selected natural gas treating and processing plants and related assets from subsidiaries of El Paso Corporation. These assets are located in Texas and have historically been associated with and are integral to GulfTerra’s Texas intrastate natural gas pipeline system.

      The South Texas midstream assets include nine turbo-expander cryogenic natural gas processing plants, in which NGLs are extracted from natural gas. The following table describes the capacities of the cryogenic plants to be acquired:

         
Capacity
Plant Name (MMcf/d)


Armstrong
    250  
Delmita
    135  
Gilmore
    260  
Matagorda
    250  
San Martin
    200  
Shilling
    110  
Shoup
    285  
Sonora
    100  
Thompsonville
    300  

      In addition to these cryogenic processing plants, we are acquiring the Brushy Creek treating plant, which removes carbon dioxide from natural gas and has a capacity of up to 150 MMcf/d of natural gas, and the Delmita natural gas gathering system, which consists of approximately 294 miles of pipeline and ties approximately 140 connected wells to the Delmita Cryogenic Processing Plant.

 
Octane Enhancement and Other

      Our Octane Enhancement segment consists of a 66.7% ownership interest in BEF, which owns a facility that produces motor gasoline additives used to enhance octane. Our Other segment consists primarily of fee-based marketing services and unallocated cost of services that support its operations and business activities.

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GulfTerra’s Business and Properties

      This section summarizes information from GulfTerra’s Annual Report on Form 10-K for the year ended December 31, 2003. While we are not incorporating the report by reference into this prospectus supplement, for a more detailed discussion of GulfTerra’s business, please read the “Business” section contained in its 2003 Annual Report on Form 10-K.

      Formed in 1993, GulfTerra is one of the largest publicly-traded MLPs in terms of market capitalization. GulfTerra manages a balanced, diversified portfolio of interests and assets relating to the midstream energy sector, which involves gathering, transporting, separating, handling, processing, fractionating and storing natural gas, oil and NGLs. GulfTerra considers this portfolio, which generates relatively stable cash flows, to be balanced due to its diversity of geographic locations, business segments, customers and product lines. GulfTerra’s interests and assets include:

  •  onshore natural gas pipelines and processing facilities in Alabama, Colorado, Louisiana, Mississippi, New Mexico and Texas;
 
  •  offshore oil and natural gas pipelines, platforms, processing facilities and other energy infrastructure in the Gulf of Mexico, primarily offshore Louisiana and Texas;
 
  •  onshore NGL pipelines and fractionation facilities in Texas; and
 
  •  onshore natural gas and NGL storage facilities in Louisiana, Mississippi and Texas.

      GulfTerra is one of the largest natural gas gatherers, based on miles of pipeline, in the prolific natural gas supply regions offshore in the Gulf of Mexico and onshore in Texas and the San Juan Basin, which covers a significant portion of the four corners region of Arizona, Colorado, New Mexico and Utah. These regions, especially the deeper water regions of the Gulf of Mexico, one of the United States’ fastest growing oil and natural gas producing regions, offer GulfTerra significant infrastructure growth potential through the acquisition and construction of pipelines, platforms, processing and storage facilities and other infrastructure.

GulfTerra’s Business Segments

      GulfTerra’s business has four reportable segments:

  •  Natural gas pipelines and plants;
 
  •  Oil and NGL logistics;
 
  •  Natural gas storage; and
 
  •  Platform services.

      These segments are strategic business units that provide a variety of energy related services. For information relating to revenues from external customers, operating income and total assets of each segment, please read GulfTerra’s historical financial statements filed with the SEC on Enterprise’s Current Reports on Form 8-K on April 20, 2004 and August 2, 2004 and incorporated by reference into this prospectus supplement.

 
Natural Gas Pipelines and Plants

      GulfTerra owns interests in natural gas pipeline systems extending over 15,500 miles, with a combined maximum design capacity (net to GulfTerra’s interest) of over 10.9 billion cubic feet per day, or Bcf/d, of natural gas. GulfTerra owns or has interests in gathering systems onshore in Alabama, Colorado, Louisiana, Mississippi, New Mexico and Texas, including the San Juan gathering system and the Texas Intrastate system. In addition to its onshore natural gas pipeline systems, GulfTerra’s offshore natural gas pipeline systems are strategically located to serve production activities in some of the most active drilling and development regions in the Gulf of Mexico, including select locations offshore of Texas, Louisiana and Mississippi, and to provide relatively low cost access to long-line transmission pipelines that access multiple markets in the eastern half of the United States.

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      GulfTerra also owns interests in five processing and treating plants in New Mexico, Texas and Colorado. These plants have a combined maximum capacity of over 1.5 Bcf/d of natural gas and 50 thousand barrels per day, or MBbl/d, of NGL, including the Chaco cryogenic natural gas processing plant, the fifth largest natural gas processing plant in the United States measured by liquids produced.

 
Oil and NGL Logistics

      GulfTerra owns interests in three offshore oil pipeline systems, which extend over 340 miles and have a combined capacity of approximately 635 MBbl/d of oil with the addition of pumps and the use of friction reducers, and is constructing the 390-mile Cameron Highway Oil Pipeline. In addition to being strategically located in the vicinity of some prolific oil-producing regions in the Gulf of Mexico, GulfTerra’s oil pipeline systems are parallel to and interconnect with key segments of some of its natural gas pipeline systems and offshore platforms, which contain separation and handling facilities. This distinguishes GulfTerra from its competitors by allowing it to provide some producing properties with a unique single point of contact through which they may access a wide range of midstream services and assets.

      GulfTerra also owns over 1,000 miles of intrastate NGL gathering and transportation pipelines and four fractionation plants, all located in Texas and delivering fractionated and unfractionated NGL from South Texas to Houston and refineries and petrochemical plants along the Texas Gulf Coast. GulfTerra’s fractionation facilities have a combined capacity of approximately 120 MBbl/d.

      Additionally, GulfTerra owns a 3.3 million barrel, or MMBbl, propane storage business in Mississippi and owns or leases NGL storage facilities in Louisiana and Texas with aggregate capacity of approximately 21.3 MMBbls.

 
Natural Gas Storage

      GulfTerra owns the Petal and Hattiesburg salt dome natural gas storage facilities located in Mississippi, which are strategically situated to serve the Northeast, Mid-Atlantic and Southeast natural gas markets. These two facilities have a combined current working capacity of 13.5 Bcf, and are capable of delivering in excess of 1.2 Bcf/d of natural gas into five interstate pipeline systems: Transco, Destin Pipeline, Gulf South Pipeline, Southern Natural Gas Pipeline and Tennessee Gas Pipeline. Each of these facilities is capable of making deliveries at the high rates necessary to satisfy peak requirements in the electric generation industry.

      In addition, GulfTerra has the exclusive right to use the Wilson natural gas storage facility, which is comprised of 62 acres in Wharton County, Texas, and consists of four caverns with a working gas capacity of 6.4 Bcf and a maximum withdrawal capacity of 800 MMcf/d of natural gas.

 
Platform Services

      Offshore platforms are critical components of the offshore infrastructure in the Gulf of Mexico, supporting drilling and production operations, and therefore play a key role in the overall development of offshore oil and natural gas reserves. Platforms are used to:

  •  interconnect the offshore pipeline grid;
 
  •  provide an efficient means to perform pipeline maintenance;
 
  •  locate compression, separation, production handling and other facilities; and
 
  •  conduct drilling operations during the initial development phase of an oil and natural gas property.

      GulfTerra has interests in seven multi-purpose offshore hub platforms in the Gulf of Mexico, including the recently completed Marco Polo tension leg platform. These platforms were specifically designed to be used as deepwater hubs and production handling and pipeline maintenance facilities. Through these facilities, GulfTerra is able to provide a variety of midstream services to increase deliverability for, and attract new volumes into, its offshore pipeline systems.

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Other Assets

      GulfTerra owns interests in four oil and natural gas properties located in waters offshore of Louisiana. Production is gathered, transported, and processed through its pipeline systems and platform facilities, and sold to various third parties and subsidiaries of El Paso Corporation. GulfTerra has announced that it intends to continue to concentrate on fee-based operations that traditionally provide more stable cash flow and de-emphasize its commodity-based activities, including withdrawal from the oil and natural gas production business by not acquiring additional properties.

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MANAGEMENT

Our Management

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

             
Position with General Partner
Name Age of Combined Company



Dan L. Duncan
    71     Director and Chairman of the Board
O.S. Andras
    69     Director, President and Chief Executive Officer
Richard H. Bachmann
    51     Executive Vice President, Chief Legal Officer and Secretary
Michael A. Creel
    50     Executive Vice President and Chief Financial Officer
A.J. Teague
    59     Executive Vice President
William D. Ray
    69     Executive Vice President
Charles E. Crain
    71     Senior Vice President
W. Ordemann
    45     Senior Vice President
Gil H. Radtke
    43     Senior Vice President
James M. Collingsworth
    49     Senior Vice President
James A. Cisarik
    46     Senior Vice President
Lynn L. Bourdon
    42     Senior Vice President
Michael J. Knesek
    50     Vice President, Controller and Principal Accounting Officer
W. Randall Fowler
    47     Vice President and Treasurer
Dr. Ralph S. Cunningham
    63     Director
Lee W. Marshall, Sr.
    71     Director
Richard S. Snell
    62     Director

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

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

      Richard H. Bachmann was elected Executive Vice President, Chief Legal Officer and Secretary of our general partner and EPCO in January 1999. Mr. Bachmann served as a director of our general partner from June 2000 to January 2004.

      Michael A. Creel was elected an Executive Vice President of our general partner and EPCO in February 2001, having served as a Senior Vice President of our general partner and EPCO since November 1999. In June 2000, Mr. Creel, a certified public accountant, assumed the role of Chief Financial Officer of our general partner and EPCO along with his other responsibilities.

      A.J. Teague was elected an Executive Vice President of our general partner in November 1999. From 1998 to 1999 he served as President of Tejas Natural Gas Liquids, LLC, then a Shell affiliate.

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

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

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      William Ordemann joined us as a Vice President of our general partner in October 1999 and was elected a Senior Vice President in September 2001. From January 1997 to February 1998, Mr. Ordemann was a Vice President of Shell Midstream Enterprises, LLC, and from February 1998 to September 1999 was a Vice President of Tejas Natural Gas Liquids, LLC, both Shell affiliates.

      Gil H. Radtke was elected a Senior Vice President of our general partner in February 2002. Mr. Radtke joined us in connection with our purchase of Diamond-Koch’s storage and propylene fractionation assets in January and February 2002. Before joining us, Mr. Radtke served as President of the Diamond-Koch joint venture from 1999 to 2002, where he was responsible for its storage, propylene fractionation, pipeline and NGL fractionation businesses. From 1997 to 1999 he was Vice President, Petrochemicals and Storage of Diamond-Koch.

      James M. Collingsworth joined our general partner as a Vice President in November 2001 and was elected a Senior Vice President in November 2002. Previously, he served as a board member of Texaco Canada Petroleum Inc. from July 1998 to October 2001 and was employed by Texaco from 1991 to 2001 in various management positions, including Senior Vice President of NGL Assets and Business Services from July 1998 to October 2001.

      James A. Cisarik was elected a Senior Vice President of our general partner in February 2003. Mr. Cisarik joined us in April 2001 when we acquired Acadian Gas from Shell. His primary responsibility since joining us has been oversight of the commercial activities of our natural gas businesses, principally those of Acadian Gas and our Gulf of Mexico natural gas pipeline investments. From February 1999 through March 2001, Mr. Cisarik was a Senior Vice President of Coral Energy, LLC, and from 1997 to February 1999 was Vice President, Market Development of Tejas Energy, LLC, both affiliates of Shell, with responsibilities in market development for their Texas and Louisiana natural gas pipeline systems.

      Lynn L. Bourdon, III was elected a Senior Vice President of our general partner on December 10, 2003. His primary responsibility since joining us has been oversight of all NGL supply and marketing functions. Previously, Mr. Bourdon served as Senior Vice President and Chief Commercial Officer of Orion Refining Corporation from July 2001 through November 2003, and was a shareholder in En*Vantage, Inc., a business investment and energy services company serving the petrochemicals and energy industries, from September 1999 through July 2001. He also served as a Senior Vice President of PG&E Corporation for gas transmission commercial operations from August 1997 through August 1999.

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

      W. Randall Fowler joined us as director of investor relations in January 1999 and was elected to the positions of Treasurer and a Vice President of our general partner and EPCO in August 2000.

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

      Lee W. Marshall, Sr. was elected a Director of our general partner in April 1998. Mr. Marshall has been the Managing Partner and principal owner of Bison Resources, LLC, (a privately held oil and gas production company) since 1993. Previously, he held senior management positions with Union Pacific Resources, as Senior Vice President, Refining, Manufacturing and Marketing, with Wolverine Exploration Company as Executive Vice President and Chief Financial Officer and with Tenneco Oil Company as Senior Vice President, Marketing. Mr. Marshall is a member of our Audit and Conflicts Committee.

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      Richard W. Snell was elected a Director of our general partner in June 2000. Mr. Snell was an attorney with the Snell & Smith, P.C. law firm in Houston, Texas from the founding of the firm in 1993 until May 2000. Since May 2000 he has been a partner with the law firm of Thompson & Knight LLP in Houston, Texas. Mr. Snell is also a certified public accountant. Mr. Snell is a member of our Audit and Conflicts Committee.

Management of the Combined Company

      Under the limited liability company agreement of the general partner of the combined company, Dan L. Duncan, acting through a wholly owned subsidiary, will have the right to designate not less than five nor more than 10 persons to the board of directors of the general partner, a majority of whom must be independent directors under the criteria established by the NYSE.

      The following persons will be appointed to the director and officer positions set forth opposite their names in the table below. We expect that further appointments will be made in the future.

             
Position with General Partner
Name Age of Combined Company



Dan L. Duncan
    71     Director and Chairman of the Board
O. S. Andras
    69     Director and Vice Chairman of the Board and Chief Executive Officer
Robert G. Phillips
    49     Director and President and Chief Operating Officer
Dr. Ralph S. Cunningham
    63     Director*
Lee W. Marshall
    71     Director*
Richard S. Snell
    62     Director*
W. Matt Ralls
    55     Director*
Richard H. Bachmann
    51     Executive Vice President, Secretary and Chief Legal Officer
Michael A. Creel
    50     Executive Vice President and Chief Financial Officer
James H. Lytal
    46     Executive Vice President
A. James Teague
    59     Executive Vice President
Charles E. Crain
    71     Senior Vice President
Gil H. Radtke
    43     Senior Vice President


Independent directors

      Biographical information regarding Messrs. Duncan, Andras, Cunningham, Marshall, Snell, Bachmann, Creel, Teague, Crain and Radtke is set forth above under “— Our Management.” Biographical information regarding Messrs. Phillips, Ralls and Lytal is set forth below.

      Robert G. Phillips has served as a Director of GulfTerra’s general partner since August 1998. He has served as Chief Executive Officer for GulfTerra and its general partner since November 1999 and as Chairman since October 2002. He served as Executive Vice President from August 1998 to October 1999. Mr. Phillips has served as President of El Paso Field Services Company since June 1997. He served as President of El Paso Energy Resources Company from December 1996 to June 1997, President of El Paso Field Services Company from April 1996 to December 1996 and Senior Vice President of El Paso Corporation from September 1995 to April 1996. For more than five years prior, Mr. Phillips was Chief Executive Officer of Eastex Energy, Inc.

      W. Matt Ralls has served as a Director of GulfTerra’s general partner since May 2003 and is the Senior Vice President and Chief Financial Officer of GlobalSantaFe, an international contract drilling company. From 1997 to 2001, he was Vice President, Chief Financial Officer, and Treasurer of Global Marine, Inc.

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Previously, he served as Executive Vice President, Chief Financial Officer, and Director of Kelley Oil and Gas Corporation and as Vice President of Capital Markets and Corporate Development for The Meridian Resource Corporation before joining Global Marine. He spent the first 17 years of his career in commercial banking at the senior management level.

      James H. Lytal has served as a Director of GulfTerra’s general partner since August 1994 and as GulfTerra’s President and the President of GulfTerra’s general partner since July 1995. He served as Senior Vice President of GulfTerra and its general partner from August 1994 to June 1995. Prior to joining GulfTerra, Mr. Lytal served in various capacities in the oil and gas exploration and production and gas pipeline industries with United Gas Pipeline Company, Texas Oil and Gas, Inc. and American Pipeline Company.

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TAX CONSEQUENCES

Tax Consequences of an Investment in Our Common Units

      The tax consequences to you of an investment in common units will depend in part on your own tax circumstances. For a discussion of the principal federal income tax considerations associated with our operations and the ownership and disposition of common units, please read “Tax Consequences” beginning on page 39 of the accompanying prospectus. We recommend that you consult your own tax advisor about the federal, state, local and foreign tax consequences peculiar to your circumstances.

      We estimate that if you purchase common units in this offering and own them through December 31, 2006, then you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be less than 10% of the cash distributed with respect to that period. We expect this estimate to remain the same following the GulfTerra merger. If you own common units purchased in this offering for a shorter period, the percentage of federal taxable income allocated to you may be higher. These estimates are based upon the assumption that our available cash for distribution will approximate the amount required to distribute cash to the holders of the common units in an amount equal to the quarterly distribution of $0.3725 per unit and other assumptions with respect to capital expenditures, cash flow and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and certain tax reporting positions that we have adopted with which the IRS could disagree. In addition, subsequent issuances of equity securities by us could also affect the percentage of distributions that will constitute taxable income. Accordingly, we cannot assure you that the estimates will be correct. The actual percentage of distributions that will constitute taxable income could be higher or lower, and any differences could be material and could materially affect the value of the common units.

      No ruling has been or will be sought from the IRS and the IRS has made no determination as to our status or the status of the operating partnership as partnerships for federal income tax purposes or whether our operations generate “qualifying income” under Section 7704 of the Internal Revenue Code. Instead, we will rely on the opinion of counsel that, based upon the Internal Revenue Code, its regulations, published revenue rulings and court decisions and the representations described below, we and the operating partnership will be classified as a partnership for federal income tax purposes.

      In rendering its opinion, counsel has relied on factual representations made by us and the general partner. The representations made by us and our general partner upon which counsel has relied include:

        (a) Neither we nor the operating partnership will elect to be treated as a corporation;
 
        (b) For each taxable year, more than 90% of our gross income will be income from sources that our counsel has opined or will opine is “qualifying income” within the meaning of Section 7704(d) of the Internal Revenue Code; and
 
        (c) The interest rate swaps entered into on March 17, 2004 by our operating partnership in an aggregate notional amount of $1.85 billion were (i) properly identified as hedging transactions under applicable treasury regulations and (ii) entered into in order to hedge interest rate risk with respect to debt expected to be incurred on or around September 30, 2004 in connection with the proposed merger with GulfTerra. Enterprise intends to enter into the financings to which the swap agreements relate in connection with the proposed merger. In the event the merger and related financings do not occur within a reasonable period of time around September 30, 2004, our operating partnership intends to and is capable of entering into financings similar to those financings to which the swap agreements relate, in an amount sufficient and within the time period sufficient to assure that the representation in clause (b) above continues to be accurate, taking into account the gain recognized on the swap agreements.

      For an explanation of the consequences if we fail to meet the “qualifying income” exception, please see “Tax Consequences — Partnership Status” in the accompanying prospectus.

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Tax Consequences of the Merger

      For U.S. federal income tax purposes, except as described below with respect to a net decrease in a unitholder’s share of nonrecourse liabilities no gain or loss will be recognized by a GulfTerra unitholder or an Enterprise unitholder as a result of the merger. The merger will, however, result in the recalculation of each Enterprise and GulfTerra common unitholder’s share of nonrecourse liabilities. Each Enterprise and GulfTerra unitholder will be treated as receiving a deemed cash distribution equal to the excess, if any, of the unitholder’s share of nonrecourse liabilities immediately before the merger and the unitholder’s share of the nonrecourse liabilities immediately following the merger. If the amount of the deemed cash distribution received by a GulfTerra or Enterprise common unitholder exceeds such unitholder’s basis in its partnership interest, such unitholder will recognize gain in an amount equal to such excess.

      The application of the rules governing the allocation of nonrecourse liabilities in the context of the merger is complex and subject to uncertainty. We have agreed to apply these rules, to the extent permissible, in a manner that minimizes the amount of any net decrease in the amount of nonrecourse liabilities allocable to the GulfTerra and Enterprise unitholders. We and GulfTerra do not anticipate that there will be a material decrease in the amount of nonrecourse liabilities allocable to a GulfTerra common unitholder or an Enterprise common unitholder as a result of the merger.

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UNDERWRITING

      Subject to the terms and conditions stated in the underwriting agreement dated the date of this prospectus supplement, which we will file as an exhibit to a Form 8-K following the pricing of this offering, each underwriter named below has agreed to purchase from us the number of common units set forth opposite the underwriter’s name.

           
Number of
Name of Underwriters Common Units


Citigroup Global Markets Inc. 
       
Morgan Stanley & Co. Incorporated
       
Lehman Brothers Inc.
       
UBS Securities LLC
       
Wachovia Capital Markets, LLC
       
A.G. Edwards & Sons, Inc.
       
Merrill Lynch, Pierce, Fenner & Smith
Incorporated
       
RBC Capital Markets Corporation 
       
Sanders Morris Harris Inc. 
       
J.P. Morgan Securities Inc. 
       
KeyBanc Capital Markets, a Division of McDonald Investments Inc. 
       
     
 
 
Total
    13,750,000  
     
 

      An entity controlled by Dan L. Duncan, the Chairman of our general partner, O.S. Andras, the President and Chief Executive Officer of our general partner, and two other members of our senior management team will purchase an aggregate of 1,751,500 common units in this offering directly from the underwriters at a price equal to the public offering price. The underwriters will not receive any discount or commission on the sale of these 1,751,500 common units.

      The underwriting agreement provides that the underwriters’ obligations to purchase the common units depend on the satisfaction of the conditions contained in the underwriting agreement, and that if any of the common units are purchased by the underwriters, all of the common units must be purchased. The conditions contained in the underwriting agreement include the condition that all the representations and warranties made by us to the underwriters are true, that there has been no material adverse change in the condition of us or in the financial markets and that we deliver to the underwriters customary closing documents.

Commission and Expenses

      The following table shows the underwriting fees to be paid to the underwriters by us in connection with this offering. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional common units. This underwriting fee is the difference between the offering price to the public and the amount the underwriters pay to us to purchase the common units.

                   
Paid By Us

No Exercise Full Exercise


Per common unit
  $       $    
 
Total
  $       $    

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

      We estimate that total expenses of the offering, other than underwriting discounts and commissions, will be approximately $900,000.

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Indemnification

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

Over-Allotment Option

      We have granted to the underwriters an option to purchase up to an aggregate of 2,062,500 additional common units at the offering price to the public less the underwriting discount set forth on the cover page of this prospectus supplement exercisable to cover over-allotments. Such option may be exercised in whole or in part at any time until 30 days after the date of this prospectus supplement. If this option is exercised, each underwriter will be committed, subject to satisfaction of the conditions specified in the underwriting agreement, to purchase a number of additional common units proportionate to the underwriter’s initial commitment as indicated in the preceding table, and we will be obligated, pursuant to the option, to sell these common units to the underwriters.

Lock-Up Agreements

      We, our general partner, our operating partnership, certain of our affiliates that own common units, the directors and executive officers of our general partner, an affiliate of Shell and El Paso Corporation have agreed that we and they will not, directly or indirectly, sell, offer, pledge or otherwise dispose of any common units or enter into any derivative transaction with similar effect as a sale of common units for a period of 60 days after the date of this prospectus supplement without the prior written consent of Citigroup Global Markets Inc. The restrictions described in this paragraph do not apply to:

  •  the issuance and sale of common units to the underwriters pursuant to the underwriting agreement;
 
  •  the issuance and sale of common units, phantom units, restricted units and options under our existing employee benefits plans;
 
  •  the issuance and sale of common units pursuant to the merger; or
 
  •  the issuance and sale of common units pursuant to our distribution reinvestment plan.

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

Stabilization, Short Positions And Penalty Bids

      In connection with this offering, the underwriters may engage in stabilizing transactions, overallotment transactions, syndicate covering transactions and penalty bids in accordance with Regulation M under the Securities Exchange Act of 1934.

  •  Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.
 
  •  Over-allotment transactions involve sales by the underwriters of the common units in excess of the number of units the underwriters are obligated to purchase, which creates a syndicate short position. The short position may be either a covered short position or a naked short position. In a covered short position, the number of units over-allotted by the underwriters is not greater than the number of units they may purchase in the over-allotment option. In a naked short position, the number of units involved is greater than the number of units in the over-allotment option. The underwriters may close out any short position by either exercising their over-allotment option and/or purchasing common units in the open market.

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

      These stabilizing transactions, over-allotment transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of the common units or preventing or retarding a decline in the market price of the common units. As a result, the price of the common units may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the New York Stock Exchange or otherwise and, if commenced, may be discontinued at any time.

      Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the common units. In addition, neither we nor any of the underwriters make any representation that the underwriters will engage in these stabilizing transactions or that any transaction, if commenced, will not be discontinued without notice.

Listing

      Our common units are traded on the New York Stock Exchange under the symbol “EPD.”

Affiliations

      Some of the underwriters and their affiliates have performed investment banking, commercial banking and advisory services for us from time to time for which they have received customary fees and expenses. The underwriters and their affiliates may, from time to time in the future, engage in transactions with and perform services for us in the ordinary course of business. We expect that some of the underwriters or their affiliates may engage in transactions with and perform services for us with respect to our intended financing transactions in connection with the closing of the proposed merger.

      In addition, affiliates of Citigroup Global Markets Inc., Wachovia Capital Markets, LLC, RBC Capital Markets Corporation and J.P. Morgan Securities Inc. are lenders under our multi-year revolving credit facility. Each of these lenders will receive a share of the repayment by us of amounts outstanding under our multi-year revolving credit facility from a portion of the net proceeds of this offering.

NASD Conduct Rules

      The National Association of Securities Dealers, Inc. views the common units offered hereby as interests in a direct participation program because of the flow-through tax consequences to our limited partners. As a result, this offering is being made in compliance with Rule 2810 of the NASD’s Conduct Rules, which imposes specific requirements on NASD members participating in an offering relating to suitability standards for an investment in common units, due diligence, disclosure in the prospectus and underwriters’ compensation. These requirements as applied to this offering are similar to those imposed on members participating in public offerings of other securities that are listed on a national securities exchange.

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Electronic Distribution

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

      Other than the prospectus in electronic format, the information on any underwriter’s or selling group member’s web site and any information contained in any other web site maintained by an underwriter or selling group member is not part of the prospectus or the registration statement of which this prospectus supplement forms a part, has not been approved and/or endorsed by us or any underwriter or selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors in deciding whether to purchase any of the common units. The underwriters and selling group members are not responsible for information contained on web sites that they do not maintain.

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INCORPORATION OF DOCUMENTS BY REFERENCE

      The Commission allows us to incorporate by reference into this prospectus supplement and the accompanying prospectus the information we file with it, which means that we can disclose important information to you by referring you to those documents. The information incorporated by reference is considered to be part of this prospectus supplement and the accompanying prospectus, and later information that we file with the Commission will automatically update and supersede this information. We incorporate by reference the documents listed below and any future filings we make with the Commission under section 13(a), 13(c), 14 or 15(d) of the Securities Exchange Act of 1934 until our offering is completed (other than information furnished under Item 9 or Item 12 of any Form 8-K that is listed below or is filed in the future and which is not deemed filed under the Exchange Act):

  •  Our Annual Report on Form 10-K for the year ended December 31, 2003, Commission File No. 1-14323;
 
  •  Our Quarterly Report on Form 10-Q for the quarter ended March 31, 2004, Commission File No. 1-14323;
 
  •  Our Current Reports on Form 8-K filed with the Commission on January 6, 2004, February 10, 2004, March 22, 2004, April 16, 2004, April 20, 2004, April 21, 2004, April 26, 2004, April 27, 2004, May 3, 2004, June 16, 2004, July 29, 2004 and August 2, 2004, Commission File Nos. 1-14323; and
 
  •  Our Current Report on Form 8-K (containing the description of our common units, which description amends and restates the description of our common units contained in the Registration Statement on Form 8-A, initially filed with the Commission on July 21, 1998) filed with the Commission on February 10, 2004, Commission File No. 1-14323.

LEGAL MATTERS

      Certain legal matters with respect to the common units will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas. Certain legal matters with respect to the common units will be passed upon for the underwriters by Baker Botts L.L.P., Houston, Texas. Baker Botts L.L.P. performs legal services for us and our affiliates from time to time unrelated to this offering. Attorneys at Vinson & Elkins L.L.P. who have participated in the preparation of this prospectus supplement, the accompanying prospectus, the registration statement of which they are a part and the related transaction documents beneficially own approximately 1,000 common units of Enterprise and 1,200 common units of GulfTerra.

EXPERTS

      The (1) consolidated financial statements and the related consolidated financial statement schedule of Enterprise Products Partners L.P. and subsidiaries as incorporated in this prospectus supplement, by reference from Enterprise Products Partners L.P.’s Annual Report on Form 10-K for the year ended December 31, 2003, and (2) the balance sheet of Enterprise Products GP, LLC as of December 31, 2003, incorporated in this prospectus supplement by reference from Exhibit 99.1 to Enterprise Products Partners L.P.’s Current Report on Form 8-K filed with the Securities and Exchange Commission on March 22, 2004, have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their reports, which are incorporated herein by reference (each such report expresses an unqualified opinion and the report for Enterprise Products Partners L.P. includes an explanatory paragraph referring to a change in method of accounting for goodwill in 2002 and derivative instruments in 2001 as discussed in Notes 8 and 1, respectively, to Enterprise Products Partners L.P.’s consolidated financial statements), and have been so incorporated in reliance upon the reports of such firm given upon their authority as experts in accounting and auditing.

      The (1) consolidated financial statements of GulfTerra Energy Partners, L.P. (“GulfTerra”), (2) the financial statements of Poseidon Oil Pipeline Company, L.L.C. (“Poseidon”) and (3) the combined financial statements of El Paso Hydrocarbons, L.P. and El Paso NGL Marketing Company, L.P. (the “Companies”)

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all incorporated in this prospectus supplement by reference to Enterprise Products Partners L.P.’s Current Reports on Form 8-K dated April 20, 2004 for (1) and (2) and April 16, 2004 for (3), have been so incorporated in reliance on the reports (which (i) report on the consolidated financial statements of GulfTerra contains an explanatory paragraph relating to GulfTerra’s agreement to merge with Enterprise Products Partners L.P. as described in Note 2 to the consolidated financial statements, (ii) report on the financial statements of Poseidon contains an explanatory paragraph relating to Poseidon’s restatement of its prior year financial statements as described in Note 1 to the financial statements, and (iii) report on the combined financial statements of the Companies contains an explanatory paragraph relating to the Companies’ significant transactions and relationships with affiliated entities as described in Note 5 to the combined financial statements) of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

      Information derived from the report of Netherland, Sewell & Associates, Inc., independent petroleum engineers and geologists, with respect to GulfTerra’s estimated oil and natural gas reserves incorporated in this prospectus supplement and accompanying base prospectuses by reference to our Current Report on Form 8-K dated April 20, 2004 has been so incorporated in reliance on the authority of said firm as experts with respect to such matters contained in their report.

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INDEX TO UNAUDITED PRO FORMA FINANCIAL STATEMENTS

Enterprise Products Partners L.P. Unaudited Pro Forma Consolidated Financial Statements:

         
Introduction
    F-2  
Unaudited Pro Forma Condensed Statement of Consolidated Operations for the three months ended March 31, 2004
    F-4  
Unaudited Pro Forma Condensed Statement of Consolidated Operations for the year ended December 31, 2003
    F-6  
Unaudited Pro Forma Condensed Consolidated Balance Sheet at March 31, 2004
    F-8  
Notes to Unaudited Pro Forma Condensed Consolidated Financial Statements
    F-10  
Pro Forma Sensitivity Analysis
    F-20  

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ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Introduction

      The following unaudited pro forma condensed consolidated financial statements have been prepared to assist in the analysis of financial effects of the proposed merger between Enterprise Products Partners L.P. and GulfTerra Energy Partners, L.P. announced on December 15, 2003. The unaudited pro forma condensed statements of consolidated operations for the three months ended March 31, 2004 and the year ended December 31, 2003 assume the merger-related transactions (as described beginning on page F-10) all occurred on January 1 of each period presented. The unaudited pro forma condensed consolidated balance sheet shows the financial effects of the merger-related transactions as if they had occurred on March 31, 2004 (to the extent not already recorded). In addition, these pro forma financial statements give effect to (i) Enterprise’s sale of 17,250,000 common units (including the over-allotment of 2,250,000 common units) in May 2004; (ii) the issuance of 1,757,347 Enterprise common units pursuant to its DRIP in May 2004; and (iii) the conversion of Enterprise’s 4,413,549 Class B special units into an equal number of its common units on July 29, 2004. These adjustments are found under the column labeled “Adjustments Due to Other Recent Events.” These pro forma financial statements also reflect Enterprise’s sale of 13,750,000 common units in this offering.

      The unaudited pro forma condensed consolidated financial statements are based on assumptions that Enterprise and GulfTerra believe are reasonable under the circumstances and are intended for informational purposes only. They are not necessarily indicative of the financial results that would have occurred if the transactions described herein had taken place on the dates indicated, nor are they indicative of the future consolidated results of the combined company. Please read “Pro Forma Sensitivity Analysis” beginning on page F-20 for assumptions related to variable interest rates, fair value estimates and long-term financing scenarios.

      Unless the context requires otherwise, references to “Enterprise” are intended to mean the consolidated business and operations of Enterprise Products Partners L.P. References to “GulfTerra” are intended to mean the consolidated business and operations of GulfTerra Energy Partners, L.P. References to “El Paso Corporation” are intended to mean El Paso Corporation, its subsidiaries and affiliates (other than GulfTerra). El Paso Corporation was the majority owner of GulfTerra’s general partner prior to December 15, 2003 and owns a limited partner interest in GulfTerra.

      The unaudited pro forma condensed consolidated financial statements of Enterprise should be read in conjunction with and are qualified in their entirety by reference to the notes accompanying such unaudited pro forma condensed consolidated financial statements and with the historical consolidated financial statements and related notes of Enterprise included in its Annual Report on Form 10-K for the year ended December 31, 2003 and Quarterly Report on Form 10-Q for the three months ended March 31, 2004. The condensed consolidated financial statements of GulfTerra included herein are qualified in their entirety by reference to the historical consolidated financial statements and related notes of GulfTerra included in its Annual Report on Form 10-K and 10-K/A for the year ended December 31, 2003 and Quarterly Report on Form 10-Q for the three months ended March 31, 2004. The combined financial statements of El Paso Hydrocarbons, L.P. and El Paso NGL Marketing Company, L.P. (collectively, the “South Texas midstream assets”) included herein are qualified in their entirety by reference to the historical combined financial statements and related notes of the South Texas midstream assets included in Enterprise’s Current Reports on Form 8-K filed with the Commission on April 16, 2004 and June 16, 2004 and incorporated by reference into this document.

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      The pending merger-related transactions will be accounted for using the purchase method of accounting. For purposes of this pro forma financial information, “goodwill” represents potential intangible assets, excess of fair values over GulfTerra’s historical carrying values of tangible assets, and remaining goodwill, if any. The estimates of fair value of the acquired assets and liabilities are based on preliminary assumptions which will be updated and will change from the amounts shown. Such changes could impact amounts allocated to goodwill, intangible assets and other balance sheet accounts.

      The unaudited pro forma condensed consolidated financial statements do not give effect to any divestiture of assets that may be required for governmental approval of the proposed merger.

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ENTERPRISE PRODUCTS PARTNERS

UNAUDITED PRO FORMA CONDENSED STATEMENT OF CONSOLIDATED OPERATIONS

For the Three Months Ended March 31, 2004 (Part 1)
                                                           
South Texas Step Three
Step Two Midstream Enterprise
Enterprise GulfTerra Step Two Enterprise Assets Step Three Pro Forma
Historical Historical Adjustments Pro Forma Historical Adjustments (to Part 2)







(Amount in millions, except per unit amounts)
REVENUES
  $ 1,704.9     $ 220.3     $ (0.2 )(m)   $ 1,925.0     $ 376.0     $ (26.5 )(r)   $ 2,120.6  
                                              (153.9 )(t)        
COSTS AND EXPENSES
                                                       
Operating costs and expenses
    1,621.5       139.1       (0.2 )(m)     1,745.2       366.2       (1.6 )(s)     1,928.3  
                      (15.2 )(n)                     (26.5 )(r)        
                                              (152.7 )(t)        
                                              (2.3 )(u)        
Selling, general and administrative
    9.5               11.1  (n)     20.6               2.3  (u)     22.9  
     
     
     
     
     
     
     
 
 
Total
    1,631.0       139.1       (4.3 )     1,765.8       366.2       (180.8 )     1,951.2  
     
     
     
     
     
     
     
 
EQUITY IN INCOME (LOSS) OF UNCONSOLIDATED AFFILIATES
    13.4               (10.6 )(h)     5.0                       5.0  
                      2.2  (n)                                
     
     
     
     
     
     
     
 
OPERATING INCOME
    87.3       81.2       (4.3 )     164.2       9.8       0.4       174.4  
     
     
     
     
     
     
     
 
OTHER INCOME (EXPENSE)
                                                       
Interest expense
    (32.6 )     (28.0 )     2.2  (i)     (61.1 )             (0.9 )(p)     (62.0 )
                      (2.7 )(j)                                
Earnings from unconsolidated affiliates
            2.2       (2.2 )(n)                                
Other, net
    1.4       0.2       0.2  (l)     1.8       (0.1 )             1.7  
     
     
     
     
     
     
     
 
 
Total
    (31.2 )     (25.6 )     (2.5 )     (59.3 )     (0.1 )     (0.9 )     (60.3 )
     
     
     
     
     
     
     
 
INCOME BEFORE PROVISION FOR INCOME TAXES AND MINORITY INTEREST
    56.1       55.6       (6.8 )     104.9       9.7       (0.5 )     114.1  
PROVISION FOR INCOME TAXES
    (1.6 )                     (1.6 )                     (1.6 )
     
     
     
     
     
     
     
 
INCOME BEFORE MINORITY INTEREST
    54.5       55.6       (6.8 )     103.3       9.7       (0.5 )     112.5  
MINORITY INTEREST
    (3.0 )                     (3.0 )                     (3.0 )
     
     
     
     
     
     
     
 
INCOME FROM CONTINUING OPERATIONS
  $ 51.5     $ 55.6     $ (6.8 )   $ 100.3     $ 9.7     $ (0.5 )   $ 109.5  
     
     
     
     
     
     
     
 
ALLOCATION OF INCOME FROM CONTINUING OPERATIONS:
                                                       
 
Limited Partners
  $ 44.3                                             $ 98.2  
     
                                             
 
 
General Partner
  $ 7.2                                             $ 11.3  
     
                                             
 
BASIC EARNINGS PER UNIT:
                                                       
 
Number of units used in denominator
    218.5               105.1  (f)                             323.6  
     
             
                             
 
 
Income from continuing operations
  $ 0.21                                             $ 0.30  
     
                                             
 
DILUTED EARNINGS PER UNIT:
                                                       
 
Number of units used in denominator
    219.0               105.1  (f)                             324.1  
     
             
                             
 
 
Income from continuing operations
  $ 0.20                                             $ 0.30  
     
                                             
 

F-4


Table of Contents

ENTERPRISE PRODUCTS PARTNERS

UNAUDITED PRO FORMA CONDENSED STATEMENT OF CONSOLIDATED OPERATIONS

For the Three Months Ended March 31, 2004 (Part 2)
                                           
Adjustments
Step Three Due to Adjustments Further
Enterprise Other Adjusted Due to Adjusted
Pro Forma Recent Enterprise This Enterprise
(from Part 1) Events Pro Forma Offering Pro Forma





(Amount in millions, except per unit amounts)
REVENUES
  $ 2,120.6             $ 2,120.6             $ 2,120.6  
COSTS AND EXPENSES
                                       
Operating costs and expenses
    1,928.3               1,928.3               1,928.3  
Selling, general and administrative
    22.9               22.9               22.9  
     
             
             
 
 
Total
    1,951.2               1,951.2               1,951.2  
     
             
             
 
EQUITY IN INCOME (LOSS) OF UNCONSOLIDATED AFFILIATES
    5.0               5.0               5.0  
     
             
             
 
OPERATING INCOME
    174.4               174.4               174.4  
     
             
             
 
OTHER INCOME (EXPENSE)
                                       
Interest expense
    (62.0 )   $ 0.7 (v)     (61.3 )   $ 1.5 (w)     (59.8 )
Other, net
    1.7               1.7               1.7  
     
     
     
     
     
 
 
Total
    (60.3 )     0.7       (59.6 )     1.5       (58.1 )
     
     
     
     
     
 
INCOME BEFORE PROVISION FOR INCOME TAXES AND MINORITY INTEREST
    114.1       0.7       114.8       1.5       116.3  
PROVISION FOR INCOME TAXES
    (1.6 )             (1.6 )             (1.6 )
     
     
     
     
     
 
INCOME BEFORE MINORITY INTEREST
    112.5       0.7       113.2       1.5       114.7  
MINORITY INTEREST
    (3.0 )             (3.0 )             (3.0 )
     
     
     
     
     
 
INCOME FROM CONTINUING OPERATIONS
  $ 109.5     $ 0.7     $ 110.2     $ 1.5     $ 111.7  
     
     
     
     
     
 
ALLOCATION OF INCOME FROM CONTINUING OPERATIONS:
                                       
 
Limited Partners
  $ 98.2                             $ 99.5  
     
                             
 
 
General Partner
    11.3                             $ 12.2  
     
                             
 
BASIC EARNINGS PER UNIT:
                                       
 
Number of units used in denominator
    323.6       19.0 (v)             13.8 (w)     356.4  
     
                             
 
 
Income from continuing operations
  $ 0.30                             $ 0.28  
     
                             
 
DILUTED EARNINGS PER UNIT:
                                       
 
Number of units used in denominator
    324.1       19.0 (v)             13.8 (w)     356.9  
     
                             
 
 
Income from continuing operations
    0.30                             $ 0.28  
     
                             
 

F-5


Table of Contents

ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED PRO FORMA CONDENSED STATEMENT OF CONSOLIDATED OPERATIONS

For the Year Ended December 31, 2003 (Part 1)
                                                     
Step Two
Step One Enterprise
Enterprise Step One Enterprise GulfTerra Step Two Pro Forma
Historical Adjustments Pro Forma Historical Adjustments (to Part 2)






(Amounts in millions, except per unit amounts)
REVENUES
  $ 5,346.4             $ 5,346.4     $ 871.5     $ (26.8 )(m)   $ 6,191.1  
COSTS AND EXPENSES
                                               
Operating costs and expenses
    5,046.8               5,046.8       557.0       (26.8 )(m)     5,528.2  
                                      (48.8 )(n)        
Selling, general and administrative
    37.5               37.5               48.8  (n)     86.3  
     
             
     
     
     
 
   
Total
    5,084.3               5,084.3       557.0       (26.8 )     5,614.5  
     
             
     
     
     
 
EQUITY IN INCOME (LOSS) OF UNCONSOLIDATED AFFILIATES
    (14.0 )   $ 34.7  (b)     20.7               11.4  (n)     (2.6 )
                                      (34.7 )(h)        
     
     
     
     
     
     
 
OPERATING INCOME
    248.1       34.7       282.8       314.5       (23.3 )     574.0  
     
     
     
     
     
     
 
OTHER INCOME (EXPENSE)
                                               
Interest expense
    (140.8 )     (8.7 )(c)     (149.5 )     (127.8 )     9.0  (i)     (279.0 )
                                      (10.7 )(j)        
Loss due to early redemptions of debt
                            (36.9 )             (36.9 )
Earnings from unconsolidated affiliates
                            11.4       (11.4 )(n)        
Other, net
    6.4               6.4       1.1       0.8  (l)     8.3  
     
     
     
     
     
     
 
   
Total
    (134.4 )     (8.7 )     (143.1 )     (152.2 )     (12.3 )     (307.6 )
     
     
     
     
     
     
 
INCOME BEFORE PROVISION FOR INCOME TAXES AND MINORITY INTEREST
    113.7       26.0       139.7       162.3       (35.6 )     266.4  
PROVISION FOR INCOME TAXES
    (5.3 )             (5.3 )                     (5.3 )
     
     
     
     
     
     
 
INCOME BEFORE MINORITY INTEREST
    108.4       26.0       134.4       162.3       (35.6 )     261.1  
MINORITY INTEREST
    (3.9 )     0.9  (a)     (3.0 )     (0.9 )             (3.9 )
     
     
     
     
     
     
 
INCOME FROM CONTINUING OPERATIONS
  $ 104.5     $ 26.9     $ 131.4     $ 161.4     $ (35.6 )   $ 257.2  
     
     
     
     
     
     
 
ALLOCATION OF INCOME FROM CONTINUING OPERATIONS:
                                               
 
Limited Partners
  $ 83.8                                     $ 222.3  
     
                                     
 
 
General Partner
  $ 20.7                                     $ 34.9  
     
                                     
 
BASIC EARNINGS PER UNIT:
                                               
 
Number of units used in denominator
    199.9                               105.1  (f)     305.0  
     
                             
     
 
 
Income from continuing operations
  $ 0.42                                     $ 0.73  
     
                                     
 
DILUTED EARNINGS PER UNIT:
                                               
 
Number of units used in denominator
    206.4                               105.1  (f)     311.5  
     
                             
     
 
 
Income from continuing operations
  $ 0.41                                     $ 0.71  
     
                                     
 

The accompanying notes are an integral part of these unaudited pro forma

condensed consolidated financial statements.

F-6


Table of Contents

ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED PRO FORMA CONDENSED STATEMENT OF CONSOLIDATED OPERATIONS

For the Year Ended December 31, 2003 (Part 2)
                                                                     
Adjustments
Step Two South Texas Due to Adjustments Further
Enterprise Midstream Step Three Other Adjusted Due to Adjusted
Pro Forma Assets Step Three Enterprise Recent Enterprise This Enterprise
(from Part 1) Historical Adjustments Pro Forma Events Pro Forma Offering Pro Forma








(Amounts in millions, except per unit amounts)
REVENUES
  $ 6,191.1     $ 1,430.7     $ (36.9 )(r)   $ 7,153.0             $ 7,153.0             $ 7,153.0  
                      (431.9 )(t)                                        
COSTS AND EXPENSES
                                                               
Operating costs and expenses
    5,528.2       1,423.2       (36.9 )(r)     6,474.1               6,474.1               6,474.1  
                      (6.0 )(s)                                        
                      (427.2 )(t)                                        
                      (7.2 )(u)                                        
Selling, general and administrative
    86.3               7.2  (u)     93.5               93.5               93.5  
     
     
     
     
             
             
 
   
Total
    5,614.5       1,423.2       (470.1 )     6,567.6               6,567.6               6,567.6  
     
     
     
     
             
             
 
EQUITY IN INCOME (LOSS) OF UNCONSOLIDATED AFFILIATES
    (2.6 )                     (2.6 )             (2.6 )             (2.6 )
     
     
     
     
             
             
 
OPERATING INCOME
    574.0       7.5       1.3       582.8               582.8               582.8  
     
     
     
     
             
             
 
OTHER INCOME (EXPENSE)
                                                               
Interest expense
    (279.0 )             (3.6 )(p)     (282.6 )   $ 5.8 (v)     (276.8 )   $ 6.0 (w)     (270.8 )
Loss due to early redemptions of debt
    (36.9 )                     (36.9 )             (36.9 )             (36.9 )
Other, net
    8.3       0.1               8.4               8.4               8.4  
     
     
     
     
     
     
     
     
 
   
Total
    (307.6 )     0.1       (3.6 )     (311.1 )     5.8       (305.3 )     6.0       (299.3 )
     
     
     
     
     
     
     
     
 
INCOME BEFORE PROVISION FOR INCOME TAXES AND MINORITY INTEREST
    266.4       7.6       (2.3 )     271.7       5.8       277.5       6.0       283.5  
PROVISION FOR INCOME TAXES
    (5.3 )                     (5.3 )             (5.3 )             (5.3 )
     
     
     
     
     
     
     
     
 
INCOME BEFORE MINORITY INTEREST
    261.1       7.6       (2.3 )     266.4       5.8       272.2       6.0       278.2  
MINORITY INTEREST
    (3.9 )                     (3.9 )             (3.9 )             (3.9 )
     
     
     
     
     
     
     
     
 
INCOME FROM CONTINUING OPERATIONS
  $ 257.2     $ 7.6     $ (2.3 )   $ 262.5     $ 5.8     $ 268.3     $ 6.0     $ 274.3  
     
     
     
     
     
     
     
     
 
ALLOCATION OF INCOME FROM CONTINUING OPERATIONS:
                                                               
 
Limited Partners
  $ 222.3                                                     $ 236.0  
     
                                                     
 
 
General Partner
  $ 34.9                                                     $ 38.3  
     
                                                     
 
BASIC EARNINGS PER UNIT:
                                                               
 
Number of units used in denominator
    305.0         &nbs