e424b5

We are selling 15,000,000 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 2,250,000 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 August 4, 2004 was $20.20 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.


(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.

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.

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.”

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 $274.7 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 $173.3 million and net income of $110.7 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.

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;

• 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.

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 34.6% 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.

The Offering


Common units offered		15,000,000 common units; or

		17,250,000 common units if the underwriters exercise their over-allotment option in full.

Units outstanding after this offering		253,174,894 common units, or 255,424,894 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

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.

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	%		86,100,340		33.3	%
EPCO common units(1)			124,574,554		51.2	%		126,074,554		48.8	%
Shell common units			41,000,000		16.9	%		41,000,000		15.9	%
General partner interest			—		2.0	%		—		2.0	%

	Total		238,174,894		100.0	%		253,174,894		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

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


	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)			177,297,116		48.5	%
EPCO common units(2)			126,484,519		34.6	%
Shell common units			41,000,000		11.2	%
El Paso Corporation common units			13,454,499		3.7	%
General partner interest			—		2.0	%

	Total		358,236,134		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 974,400 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

• 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.

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.

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 $41.8 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. Overall, the 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.

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 related to acquisition costs 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 revenue 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 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 net 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 $4.2 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.

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 partly 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 Statement of Financial Accounting Standards No. 144.

Cash Tender Offers for GulfTerra’s Senior and Senior Subordinated Notes

On August 4, 2004, we commenced four cash tender offers to purchase any and all of the outstanding senior subordinated and senior notes of GulfTerra having a total outstanding principal amount of approximately $921.5 million. In connection with the tender offers, we are soliciting consents to proposed amendments that would eliminate certain restrictive covenants and default provisions contained in the indentures governing the notes. We commenced the tender offers and consent solicitations in anticipation of completing our merger with GulfTerra, and the closing of the merger is a non-waivable condition to the completion of the tender offers and consent solicitations.

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 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.

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 $296.9 million in net proceeds from this offering (including our general partner’s $5.9 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.

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 15,000,000 of our common units to the public in this offering at an offering price of $20.20 per unit. Net proceeds from this offering, including our general partner’s proportionate net capital contribution of $5.9 million, are $296.9 million after deducting applicable underwriting discounts, commissions and offering expenses of $12.3 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.

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	)		(270.4	)
		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	)		(298.9	)

	Income before provision for income taxes and minority interest				244.7			100.0			113.7			271.7			277.5			283.9
	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			278.6
	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		$	274.7

	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		$	0.68

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	)

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			1,929.4			1,929.4			1,929.4
		Selling, general and administrative			11.5			9.5			22.9			22.9			22.9

			Total costs and expenses		1,398.2			1,631.0			1,952.3			1,952.3			1,952.3

	Equity in income of unconsolidated affiliates				1.6			13.4			5.0			5.0			5.0

	Operating income				85.0			87.3			173.3			173.3			173.3

	Other income (expense):
		Interest expense			(41.9	)		(32.6	)		(62.0	)		(61.3	)		(59.7	)
		Other, net			2.8			1.4			1.7			1.7			1.7

			Total other income (expense)		(39.1	)		(31.2	)		(60.3	)		(59.6	)		(58.0	)

	Income before provision for income taxes, minority interest and change in accounting principle				45.9			56.1			113.0			113.7			115.3
	Provision for income taxes				(3.1	)		(1.6	)		(1.6	)		(1.6	)		(1.6	)

	Income before minority interest				42.8			54.5			111.4			112.1			113.7
	Minority interest				(2.3	)		(3.0	)		(3.0	)		(3.0	)		(3.0	)

	Income from continuing operations				40.5			51.5		$	108.4		$	109.1		$	110.7

	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		$	0.28		$	0.28

Diluted earnings per unit (net of general partner interest):
	Income from continuing operations per unit			$	0.19		$	0.20		$	0.30		$	0.28		$	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			4,436.8			4,139.9
	Total partners’ equity				1,438.8			1,720.9			4,639.6			5,027.0			5,323.9
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		$	256.9		$	256.9		$	256.9
	EBITDA				113.1			123.2			230.3			230.3			230.3
	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.

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

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.

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 (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

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		$	173.3	$	173.3	$	173.3
	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		$	256.9	$	256.9	$	256.9

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		$	108.4	$	109.1	$	110.7
	Adjustments to derive EBITDA:
		Interest expense		41.9			32.6			62.0		61.3		59.7
		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		$	230.3	$	230.3	$	230.3

	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

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

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.

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

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.

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.

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.

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.

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.

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.

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


	•	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.

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.

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, 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.

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.

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 $4.1 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+

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 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, on August 4, 2004, we commenced four cash tender offers to purchase any and all of GulfTerra’s outstanding senior subordinated and senior notes having a total outstanding principal amount of approximately $921.5 million. In connection with the tender offers, we are soliciting consents to proposed amendments that would eliminate certain restrictive covenants and default provisions contained in the indentures governing the notes. We expect 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

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 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.

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 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.

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.

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

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.

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.

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-20 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.

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 $4.1 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 $0.8 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-20 of this prospectus supplement.

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.

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.

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.

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,

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

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.

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.

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 253,174,894 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 15.9% 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.

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.

Discussed below are federal income tax risks related to the merger and owning and disposing of common units. 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.

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.

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.

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.

We will receive net proceeds of approximately $296.9 million from the sale of the 15,000,000 common units we are offering (including the net capital contribution of $5.9 million from our general partner to maintain its 2% general partner interest) 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 $341.3 million, including a proportionate net capital contribution of $6.8 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 August 4, 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.

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 August 4, 2004 was $20.20 per common unit.


(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.

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 15,000,000 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.


(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.

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.


	•	Pipelines;

	•	Fractionation;

	•	Processing;

	•	Octane Enhancement; and

	•	Other.

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.

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.

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:

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.

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.

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.


	•	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 Commission 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.

GulfTerra owns interests in natural gas pipeline systems extending over 15,650 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.

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.

GulfTerra owns interests in four offshore oil pipeline systems, which extend over 380 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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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 $0.52 per unit. The underwriters may allow, and the dealers may reallow, a concession not in excess of $0.10 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.

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.

We have granted to the underwriters an option to purchase up to an aggregate of 2,250,000 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.

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. and Morgan Stanley & Co. Incorporated. 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. and Morgan Stanley & Co. Incorporated 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. and Morgan Stanley & Co. Incorporated 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.

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.

	•	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. As of the date of this prospectus, Citigroup Global Markets Inc. purchased 15,000 common units on behalf of the underwriters at a price of $20.20 per common unit.

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.

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

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.

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’ compensa-

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.

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, July 29, 2004 and August 2, 2004, Commission File Nos. 1-14323;

	•	Our Current Report on Form 8-K filed with the Commission on June 16, 2004, as amended by our Current Report on Form 8-K/A (Amendment No. 1) filed with the Commission on August 4, 2004, Commission File No. 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.

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.

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”) 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.

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

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 15,000,000 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 (as amended by Amendment No. 1 thereto filed on August 4, 2004) and incorporated by reference into this document.

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.

These unaudited pro forma condensed consolidated financial statements and underlying pro forma adjustments are based upon currently available information and certain estimates and assumptions made by management of Enterprise and GulfTerra; therefore, actual results could materially differ from the pro forma information. However, Enterprise and GulfTerra believe the assumptions provide a reasonable basis for presenting the significant effects of the transactions noted herein. Enterprise and GulfTerra believe the pro forma adjustments give appropriate effect to those assumptions and are properly applied in the pro forma information. 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.

The proposed merger between Enterprise and GulfTerra involves the following three steps:


	•	Step One. On December 15, 2003, Enterprise 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 currently accounted for by Enterprise 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, Enterprise will own 100% of the limited and general partner interests in GulfTerra. At that time, the proposed merger will be accounted for by Enterprise 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 Enterprise’s general partner of $370 million (which will not be funded or reimbursed by Enterprise) and a 9.9% membership interest in Enterprise’s general partner, and the subsequent capital contribution by Enterprise’s general partner of such 50% membership interest in GulfTerra’s general partner to Enterprise (without increasing Enterprise’s general partner’s interest in Enterprise’s earnings or cash distributions);

	—	Enterprise’s purchase of 10,937,500 GulfTerra Series C Units and 2,876,620 GulfTerra common units owned by El Paso Corporation for $500 million; and

	—	The exchange of each remaining GulfTerra common unit for 1.81 Enterprise common units, resulting in the expected issuance of 105,061,240 Enterprise common units to GulfTerra unitholders.


	•	Step Three. Immediately after Step Two is completed, Enterprise expects to acquire the South Texas midstream assets, which are comprised of nine cryogenic natural gas processing plants, one natural gas gathering system, one natural gas treating plant, and a small natural gas liquids connecting pipeline, from El Paso Corporation for $150 million, plus the value of then outstanding inventory.

The total estimated consideration for the proposed merger with GulfTerra and the purchase of the South Texas midstream assets is summarized below (dollars in millions):

The pro forma adjustments Enterprise made to the historical financial statements of Enterprise, GulfTerra and the South Texas midstream assets are described as follows:

(a) Reflects the pro forma adjustment to minority interest expense related to Enterprise’s restructuring of the ownership interest of its general partner from a 1% direct interest in Enterprise and a 1.0101% minority interest in Enterprise’s consolidated operating subsidiary to a 2% direct interest in Enterprise. The pro forma adjustment removes $0.9 million in minority interest expense attributable to the general partner’s ownership interest in the earnings of the operating subsidiary during 2003. As a result of this adjustment, Enterprise’s allocation of earnings to its general partner increases by a similar amount. This transaction occurred in December 2003 immediately prior to the completion of Step One.

(b) Until Step Two of the proposed merger is completed, Enterprise will account for its investment in GulfTerra’s general partner using the equity method.

The following table shows the pro forma adjustment to Enterprise’s equity earnings from unconsolidated affiliates for the year ended December 31, 2003 (dollars in millions):

Enterprise’s historical statement of consolidated operations for the three months ended March 31, 2004 already reflects $10.6 million of equity earnings from GulfTerra’s general partner.

(c) Reflects the pro forma adjustment to interest expense associated with the $425 million cash purchase consideration which was borrowed by Enterprise to finance its purchase of a 50% interest in GulfTerra’s general partner. This transaction was financed by $225 million borrowed under an acquisition term loan and $200 million borrowed under Enterprise’s existing revolving credit facilities. The pro forma adjustment to interest expense is $8.7 million for the year ended December 31, 2003 and is based on the weighted-average 2.1% variable interest rate Enterprise is currently paying on its existing revolving credit facilities. For an analysis of sensitivity of pro forma interest expense to Enterprise’s variable interest rates, please read the discussion titled “Pro Forma Sensitivity Analysis — Sensitivity to variable interest rates” on page F-20. For an analysis of sensitivity of pro forma interest expense to Enterprise’s long-term financing options, please read the discussion titled “Pro Forma Sensitivity Analysis — Sensitivity to long-term financing scenarios” on page F-21.

Enterprise’s historical March 31, 2004 balance sheet already reflects its investment in GulfTerra’s general partner; therefore, no pro forma adjustment is required.

(d) Reflects the pro forma adjustments attributable to the assumed exercise of 974,400 GulfTerra common unit options outstanding that are already vested or will vest immediately prior to the completion of Step Two of the proposed merger. For pro forma purposes, we have assumed that GulfTerra will receive the exercise price associated with these options and issue new common units. The pro forma balance sheet adjustments reflect the receipt of $31.1 million in proceeds received in connection with the assumed exercise of these options and a corresponding increase in partners’ equity, including GulfTerra’s general partner’s proportionate contribution of $0.3 million.

(e) Under Step Two of the proposed merger, Enterprise will purchase 2,876,620 GulfTerra common units and 10,937,500 GulfTerra Series C units from El Paso Corporation for $500 million in cash. For purposes of this pro forma presentation, we have assumed that this purchase will be financed by entering into a short-term $500 million, variable interest rate acquisition term loan, which Enterprise plans to refinance using long-term debt and proceeds from equity offerings after the proposed merger is completed. In addition, these pro forma adjustments reflect the $2.5 billion estimated value of Enterprise’s common units issued in an exchange for the estimated remaining 58,044,884 GulfTerra common units, the fair value of which is assigned to Enterprise’s partners in accordance with their pro forma ownership interest percentages after the exchange is completed. Collectively, these pro forma adjustments reflect the following:


	(1) Enterprise’s receipt of $500 million in cash from borrowings and subsequent use of these funds to purchase GulfTerra common units and Series C units owned by El Paso Corporation. Enterprise’s purchase of the GulfTerra common units will be recorded as a component of goodwill (see Note (i)).


	(2) The assignment among Enterprise’s partners’ equity accounts of the estimated $2.5 billion in estimated consideration issued to GulfTerra unitholders in connection with the exchange of common units. The offset to this consideration will be recorded as a component of goodwill (see Note (i)).

	(3) The elimination of GulfTerra’s common and Series C partner’s capital accounts in consolidation with Enterprise.

Enterprise will exchange 1.81 of its common units for each GulfTerra common unit remaining after Enterprise’s purchase of 2,876,620 common units owned by El Paso Corporation. Enterprise currently estimates that the number of its common units to be issued in the exchange is 105,061,240 calculated as follows:

In accordance with purchase accounting rules, the pro forma $2.5 billion value of Enterprise’s common units issued in the exchange is based on the average closing price of Enterprise’s common units immediately prior to and after the proposed merger was announced on December 15, 2003.

The following table shows the closing prices of Enterprise’s common units within two trading days prior to and after the proposed merger being announced.

In May 2003, GulfTerra issued 80 Series F convertible units in a registered offering to a large institutional investor. Each Series F convertible unit is comprised of two separate detachable units — a Series F1 convertible unit and a Series F2 convertible unit — that have identical terms except for vesting and termination dates and the number of underlying GulfTerra common units into which they may be converted. The Series F1 units are convertible into up to $80 million of GulfTerra common units anytime after August 12, 2003, and until the date GulfTerra merges with Enterprise (subject to other defined extension rights). The Series F2 units are convertible into up to $40 million of GulfTerra common units. The Series F2 units terminate on March 30, 2005 (subject to extension rights).

During the first quarter of 2004, 45 Series F1 convertible units were converted into 1,146,418 GulfTerra common units, for which GulfTerra received net proceeds of $44.1 million, which includes GulfTerra’s general partner’s proportionate contribution of $0.4 million.

In July 2004, 10 Series F1 convertible units were converted into 261,437 GulfTerra common units, for which GulfTerra received net proceeds of approximately $9.8 million, which includes GulfTerra’s general partner’s proportionate contribution of $0.1 million. Our pro forma adjustment reflects GulfTerra’s issuance of common units and the related proceeds.

After allowing for the transactions described in the previous two paragraphs, the holder of the Series F1 and F2 convertible units could still purchase up to an additional $65 million of GulfTerra common units. Assuming that GulfTerra had received a conversion notice from the holder on July 27, 2004 for the remaining amount of securities and using a conversion price of $38.25 per common unit at that date as calculated under the terms of the Series F security, an additional 1,699,346 GulfTerra common units would be issuable. For purposes of calculating diluted earnings per unit, we have assumed that the proceeds from this assumed conversion (including the proportionate contribution of GulfTerra’s general partner) would be reinvested by GulfTerra using the treasury stock method, which results in the repurchase of 1,615,598 GulfTerra common units at a market price of $39.42 per common unit; therefore, a net dilution of 83,748 GulfTerra common units would occur. If these common units are assumed outstanding when the Enterprise exchange takes place, this would result in an additional 61,145 Enterprise common units being issued, which would not have a material impact on our pro forma financial position, goodwill or diluted earnings per unit.

Any unexpired Series F convertible units outstanding at the merger date of Enterprise and GulfTerra will be converted into rights to receive Enterprise common units, subject to the restrictions governing the Series F units. The number of Enterprise common units and the price per unit at conversion will be adjusted based on the 1.81 exchange ratio.

(f) Reflects the pro forma adjustment to the number of Enterprise common units outstanding (as used in the calculation of basic and diluted earnings per unit) resulting from the issuance of Enterprise common units in the exchange with GulfTerra’s common unitholders described in Note (e). For both the year ended December 31, 2003 and the three months ended March 31, 2004, the pro forma effect of these new common units on the number of Enterprise units outstanding was an increase of 105,061,240 common units.

(g) In connection with Step Two of the proposed merger, El Paso Corporation will exchange its remaining 50% membership interest in GulfTerra’s general partner (its membership interest remaining after Step One was completed on December 15, 2003) for a 9.9% membership interest Enterprise’s general partner and $370 million in cash from Enterprise’s general partner. Subsequently, Enterprise’s general partner will make a capital contribution of its 50% membership interest in GulfTerra’s general partner to Enterprise without the receipt of additional general partner interest, common units or other consideration. A preliminary fair value estimate of the El Paso Corporation 50% membership interest in GulfTerra’s general partner ultimately contributed to Enterprise is $461.3 million. The pro forma balance sheet entries reflect the contribution of this 50% membership interest to Enterprise, the preliminary fair value of which is allocated for

financial reporting purposes to Enterprise’s limited and general partners based on the respective ownership percentages (98% and 2%) and the related allocation of profits and losses (98% and 2%), both of which are generally consistent with the Partnership Agreement. As such, the equity accounts reflected in these financial statements are not comparable to the partner “capital accounts,” as defined in the Partnership Agreement, established for income tax purposes and in the event of dissolution of Enterprise. The offset to this contribution amount is recorded as a component of goodwill (see Note (i)).

(h) Reflects the pro forma balance sheet adjustments necessary for the consolidation of GulfTerra’s general partner with Enterprise’s financial information as a result of the contribution described in Note (g). The pro forma entries reflect the reclassification of Enterprise’s $425.0 million investment in GulfTerra’s general partner at March 31, 2004 to goodwill and the elimination of GulfTerra’s general partner’s account in consolidation. Enterprise’s pro forma statement of consolidated operations reflects the replacement of equity earnings recorded under Step One with consolidated earnings for GulfTerra as if Step Two had occurred on January 1 of each period presented. This adjustment required the removal of $34.7 million of pro forma equity income we would have recorded from GulfTerra’s general partner in connection with Step One for the year ended December 31, 2003 (see Note (b)) and $10.6 million of equity earnings Enterprise recorded during the three months ended March 31, 2004.

(i) Reflects the pro forma balance sheet adjustment to record goodwill attributable to the proposed merger. The estimated value of consideration to be paid or granted by Enterprise to consummate Step One and Step Two of the proposed merger is approximately $3.8 billion. Step Two of the proposed merger will be accounted for under the purchase method, and GulfTerra will become a wholly owned consolidated subsidiary of Enterprise. As a result of using purchase accounting in Step Two, we are required to assign fair values to the assets and liabilities of GulfTerra in consolidation.

With the primary exception of long-term debt, a preliminary analysis indicates that the carrying value of GulfTerra’s assets and other liabilities at March 31, 2004 approximates fair value. Using recent market pricing information, the fair value of GulfTerra’s debt was approximately $84.9 million higher than its carrying value at March 31, 2004. GulfTerra has completed a number of business acquisitions and invested significant capital expenditures in the last five years resulting in asset growth of approximately $3.0 billion since 1999 to a total asset value of $3.4 billion at March 31, 2004. In accordance with generally accepted accounting principles, many of these transactions (including $1.9 billion in business acquisitions completed during 2003, 2002 and 2001) were recorded at fair value or recent historical cost amounts. As a result, we have preliminarily assumed that the amount of excess cost attributable to tangible or identifiable intangible assets would be minimal (subject to adjustment pending completion of the third-party valuation noted below).

Accordingly, the $2.6 billion difference between the value of Enterprise’s estimated consideration given to consummate the proposed merger and the fair value of GulfTerra’s pro forma net assets has been assigned to goodwill. The estimated goodwill amount represents the value that management has attached to future cash flows from the GulfTerra operations and the strategic location of such assets and their connections. GulfTerra is one of the biggest natural gas gatherers, based on miles of pipelines, in the prolific natural gas supply regions offshore in the Gulf of Mexico and onshore in Texas and in the San Juan Basin, which covers a significant portion of the four contiguous corners of Arizona, Colorado, New Mexico and Utah. These regions, especially the deepwater regions of the Gulf of Mexico, one of the United States’ fastest growing oil and natural gas producing regions offer GulfTerra significant growth potential through the acquisition and construction of pipelines, platforms, processing and storage facilities and other energy infrastructure.

Upon completion of the proposed merger with GulfTerra or shortly thereafter, Enterprise will obtain a third-party valuation of GulfTerra’s assets and liabilities in order to develop a definitive allocation of the purchase price. As a result, the final purchase price allocation may result in some amounts being assigned to tangible or amortizable intangible assets apart from goodwill. To the extent that any amount is assigned to a tangible or amortizable intangible asset, this amount may ultimately be depreciated or amortized (as

appropriate) to earnings over the expected period of benefit of the asset. To the extent that any amount remains as goodwill, this amount would not be subject to depreciation or amortization, but would be subject to periodic impairment testing and, if necessary, written down to fair value should circumstances warrant.

The following table shows our preliminary calculation of the estimated pro forma goodwill amount (dollars in millions):

The estimated fair value of GulfTerra’s net assets at March 31, 2004 reflects historical amounts plus $31.1 million in net proceeds from the assumed exercise of unit options (see Note (d)), $9.8 million from the conversion of Series F units (see Note (e)) less $3.7 million of deferred charges attributable to the merger with Enterprise and recorded in other current assets that will not be recorded by the combined company. In addition, GulfTerra’s historical net asset amount has been adjusted for the $84.9 million increase in the fair value of debt discussed previously.

Enterprise’s pro forma statements of consolidated operations for the three months ended March 31, 2004 and year ended December 31, 2003 reflect $2.2 million and $9.0 million, respectively, of interest expense reductions attributable to amortization of the $84.9 million pro forma excess of fair value over carrying value of GulfTerra’s debt at March 31, 2004 (i.e., the “fair value premium”). For pro forma presentation purposes, we have amortized the fair value premium associated with each GulfTerra debt instrument assumed over the remaining term of the instrument using the effective interest method. For the three months ended March 31, 2004, if market rates underlying the fair value of each debt instrument were to have increased 1/8%, the pro forma increase in interest expense would be $0.1 million. Likewise, for the year ended December 31, 2003, if market rates underlying the fair value of each debt instrument were to have increased 1/8%, the pro forma increase in interest expense would be $0.4 million.

For an analysis of the sensitivity of pro forma earnings to potential reclassifications of this preliminary goodwill amount to tangible or intangible assets, please read our discussion titled “Pro Forma Sensitivity Analysis — Sensitivity to fair value estimates” on page F-21.

(j) Reflects the pro forma adjustment to interest expense attributable to Enterprise’s $500 million in borrowings to consummate the purchase of GulfTerra units from El Paso Corporation as described in Note (e). The pro forma increase in interest expense is $2.7 million for the three months ended March 31, 2004 and $10.7 million for the year ended December 31, 2003 and is based on the weighted-average 2.1% variable interest rate Enterprise is currently paying on its existing revolving credit facilities. For an analysis of sensitivity of pro forma interest expense to Enterprise’s variable interest rates, please read the discussion titled

“Pro Forma Sensitivity Analysis — Sensitivity to variable interest rates” on page F-20. For an analysis of sensitivity of pro forma interest expense to Enterprise’s long-term financing scenarios, please read the discussion titled “Pro Forma Sensitivity Analysis — Sensitivity to long-term financing scenarios” on page F-21.

(k) As a result of completing Step Two, Enterprise will incur an estimated $31.9 million of various transaction fees and costs. In accordance with purchase accounting rules, those costs considered direct costs of the acquisition are a component of the total purchase price. These costs include fees for legal, accounting, printing, financial advisory and other services rendered by third-parties to Enterprise over the course of the transaction and anticipated involuntary severance costs. Our pro forma balance sheet assumes that this expenditure is made from cash on hand. The offset to this amount is recorded as a component of goodwill (see Note (i)).

(l) Reflects the present value of a note receivable from El Paso Corporation received as part of the negotiated net consideration reached in Step Two. The agreements between Enterprise and El Paso Corporation provide that for a period of three years following the closing of the proposed merger, El Paso Corporation will make transition support payments to Enterprise in annual amounts of $18 million, $15 million and $12 million for the first, second and third years of such period, respectively, payable in twelve equal monthly installments for each such year. The $45 million note receivable related to the El Paso Corporation transition support payments has been discounted to fair value and recorded as a reduction in the purchase price for GulfTerra. Of the $40.3 million estimated present value, $17.2 million of this amount has been classified on the pro forma March 31, 2004 balance sheet as a current asset with the remainder recorded as a component of other assets. The offset to this amount is recorded as a reduction of goodwill (see Note (i)).

Our pro forma statements of consolidated operations reflect $0.2 million and $0.8 million of imputed interest income that would have been recognized from this note during the three months ended March 31, 2004 and the year ended December 31, 2003, respectively, using the effective interest method.

(m) Reflects the pro forma elimination of material revenues and expenses and receivables and payables between Enterprise and GulfTerra as appropriate in consolidation.

(n) Reflects pro forma classification adjustments necessary to conform GulfTerra’s historical condensed financial statements with Enterprise’s method of presentation. The reclassifications were as follows:


	•	GulfTerra’s general and administrative costs were reclassified to a separate line item within operating expenses to conform to Enterprise’s method of presentation. Historically, GulfTerra’s general and administrative costs were $15.2 million for the three months ended March 31, 2004 and $48.8 million for the year ended December 31, 2003. For purposes of this pro forma presentation, our adjustment to GulfTerra’s general and administrative costs for the three months ended March 31, 2004 excludes $4.1 million of merger-related costs that were expensed by GulfTerra during the period. Such transaction costs for GulfTerra are pre-merger in nature and would not affect income from continuing operations of the combined partnership once the proposed merger is completed.

	•	GulfTerra’s operating income increased as a result of reclassifying its equity earnings from unconsolidated affiliates to a separate component of operating income to conform with Enterprise’s presentation of such earnings. As a result of this reclassification, GulfTerra’s operating income increased by $2.2 million for the three months ended March 31, 2004 and $11.4 million for the year ended December 31, 2003. Enterprise’s equity investments with industry partners are a vital component of its business strategy. They are a means by which Enterprise conducts its operations to align its interests with those of its customers, which may be a supplier of raw materials or a consumer of finished products. This method of operation also enables Enterprise to achieve favorable economies of scale relative to the level of investment and business risk assumed versus what Enterprise could accomplish


		on a stand-alone basis. Many of these equity investments perform supporting or complementary roles to Enterprise’s other business operations. Based on information provided to Enterprise by GulfTerra, GulfTerra’s relationship with its equity investees is the same.

	•	Enterprise grouped the income allocations to GulfTerra’s Series B unitholders, common unitholders and Series C unitholders under one category termed “Limited Partners” to conform to the Enterprise format.

GulfTerra’s balance sheet line item descriptions are similar to Enterprise’s balance sheet presentation. In general, the only change to GulfTerra’s historical balance sheet was to conform the terminology and order of items between the two similar formats.

(o) Immediately after Step Two is completed, Enterprise will purchase the South Texas midstream assets from El Paso Corporation for $150 million plus the value of then outstanding inventory. For purposes of pro forma presentation, we have assumed that this purchase will be initially financed using a short-term, variable-rate acquisition term loan, which Enterprise plans to refinance using long-term debt and proceeds from equity offerings after the proposed merger is completed. This pro forma balance sheet adjustment reflects Enterprise’s receipt of $169.9 million in cash from borrowings and subsequent use of these funds to purchase the South Texas midstream assets from El Paso Corporation.

(p) Reflects the pro forma adjustment to interest expense attributable to Enterprise’s $169.9 million in borrowings to consummate the purchase of the South Texas midstream assets from El Paso Corporation as described in Note (o). The pro forma increase in interest expense is $0.9 million for the three months ended March 31, 2004 and $3.6 million for the year ended December 31, 2003 and is based on the weighted-average 2.1% variable interest rate Enterprise is currently paying on borrowings under its existing revolving credit facilities. For an analysis of sensitivity of pro forma interest expense to Enterprise’s variable interest rates, please read the discussion titled “Pro Forma Sensitivity Analysis — Sensitivity to variable interest rates” on page F-20. For an analysis of sensitivity of pro forma interest expense to Enterprise’s long-term financing scenarios, please read the discussion titled “Pro Forma Sensitivity Analysis — Sensitivity to long-term financing scenarios” on page F-21.

(q) Enterprise’s purchase of the South Texas midstream assets will be recorded using purchase accounting. As a result, Enterprise will record the assets it acquires and any liabilities it may assume at fair value, which is preliminarily estimated at approximately $150 million of property, plant and equipment, $19.9 million assumed value of inventory plus $2.1 million of other long-term liabilities. Our allocation of the purchase price is preliminary pending completion of third-party valuation analysis. Under the purchase and sale agreement with El Paso Corporation for the South Texas midstream assets, certain assets and liabilities of this business will be retained by El Paso Corporation. The pro forma balance sheet adjustments record the estimated fair value of assets acquired and liabilities assumed by Enterprise and remove those retained by El Paso Corporation. In addition, these pro forma adjustments reflect the elimination of stockholder’s equity in the South Texas midstream assets in consolidation with Enterprise’s accounts. The South Texas midstream assets will be wholly-owned by Enterprise after Step Three is completed.

(r) Reflects the pro forma elimination of material revenues and expenses and receivables and payables between Enterprise, GulfTerra and the South Texas midstream assets as appropriate in consolidation.

(s) Reflects the pro forma adjustment to depreciation expense for the South Texas midstream assets acquisition. For purposes of calculating pro forma depreciation expense, we applied the straight-line method using an estimated remaining useful life of these assets of 25 years to our preliminary new basis of property, plant and equipment of approximately $150 million. After adjusting for historical depreciation recorded on

these assets, pro forma depreciation expense decreased $1.6 million for the three months ended March 31, 2004 and $6 million for the year ended December 31, 2003.

(t) In accordance with the purchase and sale agreement between Enterprise and El Paso Corporation for the South Texas midstream assets, El Paso Corporation will retain all working capital items of the South Texas midstream assets except for inventory. As a result, our pro forma adjustments remove $159.3 million of current assets and $193.1 million of current liabilities, with a $33.8 million offset to owner’s net investment. In addition, the purchase and sale agreement states that El Paso Corporation will retain a number of NGL marketing-related contracts. Enterprise’s pro forma statement of operations for the three months ended March 31, 2004 includes adjustments to remove $153.9 million of revenues and $152.7 million of operating costs and expenses associated with these retained contracts. Likewise, for the year ended December 31, 2003, Enterprise’s pro forma statement of operations includes adjustments to remove $431.9 million of revenues and $427.2 million of operating costs and expenses.

(u) Reflects pro forma classification adjustments necessary to conform the South Texas midstream assets’ historical combined financial statements with Enterprise’s method of presentation. First, the South Texas midstream assets’ general and administrative costs were reclassified to a separate line item within operating expenses to conform to Enterprise’s method of presentation. Second, the South Texas midstream assets’ balance sheet line item descriptions are similar to Enterprise’s balance sheet presentation. In general, the only change to the South Texas midstream assets’ historical combined balance sheet was to conform the terminology and order of items between the two similar formats.

(v) Reflects Enterprise’s other recent events, including (i) the May 2004 offering of 17,250,000 Enterprise common units (including the over-allotment amount of 2,250,000 common units) at an offering price of $21.00 per unit; (ii) the issuance of 1,757,347 Enterprise common units pursuant to its DRIP in May 2004; and (iii) the conversion of the 4,413,549 Class B special units into an equal number of Enterprise’s common units on July 29, 2004. Total net proceeds from these offerings were $388.4 million after deducting applicable underwriting discounts, commissions and offering expenses of approximately $16 million. Included in the total net proceeds from these offerings of $388.4 million are net capital contributions made by the general partner of Enterprise of $7.8 million to maintain its 2% general partner interest in Enterprise, after deducting the general partner’s share of underwriting discounts, commissions and offering expenses. Enterprise used $353.1 million of the net proceeds from these offerings (including Enterprise’s general partner’s net capital contributions) to repay its $225 million Interim Term Loan and to temporarily reduce borrowings outstanding under its revolving credit facilities by approximately $130 million. Enterprise used the $35.3 million in proceeds received in connection with its distribution reinvestment plan for general partnership purposes. For purposes of this pro forma presentation, proceeds received in connection with the DRIP are included in cash and cash equivalents.

As a result of this use of proceeds, pro forma interest expense decreased by $1.7 million for the three months ended March 31, 2004 and $6.8 million for the year ended December 31, 2003. However, Enterprise’s pro forma adjustment also removes $1.0 million of prepaid debt issuance attributable to the Interim Term Loan, which is recorded as an increase in interest expense and a decrease in other current assets. Taking into account these two offsets, pro forma interest expense decreased a net $0.7 million for the three months ended March 31, 2004 and $5.8 million for the year ended December 31, 2003. The removal of debt issuance costs is due to repayment of the Interim Term Loan.

For an analysis of sensitivity of pro forma interest expense to Enterprise’s variable interest rates, please read the discussion titled “Pro Forma Sensitivity Analysis — Sensitivity to variable interest rates” beginning on page F-20.

(w) Reflects the sale in this offering of 15,000,000 Enterprise common units (including 1,751,500 common units sold to Enterprise management) at an offering price of $20.20 per unit in August 2004. Total net proceeds from this sale will be approximately $296.9 million after deducting applicable underwriting discounts, commissions and offering expenses of $12.3 million. Included in the total net proceeds of $296.9 million is a net capital contribution made by the general partner of Enterprise of $5.9 million to maintain its 2% general partner interest in Enterprise, after deducting the general partner’s share of the underwriting discounts, commissions and offering expenses. The net proceeds from this equity offering, including Enterprise’s general partner’s net capital contribution, will be used to reduce the amount of borrowings necessary to complete Step Two and Step Three of the proposed merger.

As a result of our pro forma application of proceeds from this offering to reduce debt arising from Step Two and Step Three of the proposed merger, pro forma interest expense will decrease by $6.4 million and $1.6 million for the year ended December 31, 2003 and three months ended March 31, 2004, respectively. For an analysis of sensitivity of pro forma interest expense to Enterprise’s variable interest rates, please read the discussion below titled “Pro Forma Sensitivity Analysis — Sensitivity to variable interest rates.”

(x) Reflects the conversion of Enterprise’s 4,413,549 Class B special units into an equal number of its common units. Enterprise received approval from its unitholders for this conversion at its special meeting held on the same date. The pro forma balance sheet adjustment reflects the reclassification of $134.9 million in partnership capital. There was no effect on Enterprise’s earnings as a result of this conversion.

Sensitivity to variable interest rates. Certain of the pro forma adjustments to interest expense are based on Enterprise’s current weighted-average variable interest rates. The table below shows the sensitivity of these pro forma adjustments to interest expense to a 1/8% increase in the variable interest rates used to derive the pro forma adjustments for the periods indicated (dollars in millions):

Sensitivity to fair value estimates. Certain of the pro forma adjustments incorporate our preliminary estimates of the fair value of investments or businesses that we are acquiring. Early indications are that the excess of our purchase price over the preliminary fair values (“excess cost”) may be assigned to non-amortizable other intangible assets or goodwill as opposed to depreciable fixed assets or amortizable intangible assets. Upon completion of the proposed merger or shortly thereafter, Enterprise will obtain a third-party valuation of GulfTerra’s assets and liabilities in order to develop a definitive allocation of the purchase price. As a result, the final purchase price allocation may result in some amounts being assigned to tangible or amortizable intangible assets apart from goodwill. To the extent that any amount is assigned to a tangible or amortizable intangible asset, this amount may ultimately be depreciated or amortized (as appropriate) to earnings over the expected benefit period of the asset. To the extent that any amount remains as goodwill, this amount would not be subject to depreciation or amortization, but would be subject to periodic impairment testing and if necessary, written down to a lower fair value should circumstances warrant.

The table below shows the potential increase in pro forma depreciation or amortization expense if certain amounts of the $2.6 billion of goodwill identified in Note (i) were ultimately assigned to fixed assets or amortizable intangible assets. For purposes of calculating this sensitivity, we have applied the straight-line method of cost allocation (i.e., depreciation or amortization) over an estimated useful life of 20 years to various fair values. The decrease in annual basic earnings per unit is predicated on the $0.70 basic earnings per unit determined using the $274.7 million final adjusted pro forma income from continuing operations amount after this offering is completed. The resulting pro forma adjustments for the year ended December 31, 2003 are as follows (dollars in millions, unless indicated otherwise):

Sensitivity to long-term financing scenarios. Enterprise plans to refinance its acquisition term loans incurred in connection with Step Two and Step Three of the proposed merger using a mix of debt and equity offerings in the future. In addition, Enterprise management plans to refinance GulfTerra’s debt through a tender offer for that debt that is financed with private placement debt. The size and terms of any future equity

or debt offerings are subject to market conditions beyond our control. The financing scenarios described below are presented solely for the purpose of sensitivity analysis and may not represent management’s final courses of action.


	Scenario A —	10% of baseline borrowing amount repaid using proceeds of equity offering with remainder refinanced using 5.00% fixed-rate long-term debt


	Scenario B —	10% of baseline borrowing amount repaid using proceeds of equity offering with remainder refinanced using 7.00% fixed-rate long-term debt


	Scenario C —	20% of baseline borrowing amount repaid using proceeds of equity offering with remainder refinanced using 5.00% fixed-rate long-term debt


	Scenario D —	20% of baseline borrowing amount repaid using proceeds of equity offering with remainder refinanced using 7.00% fixed-rate long-term debt


	Scenario E —	All of baseline borrowing amount refinanced using 5.00% fixed-rate long-term debt


	Scenario F —	All of baseline borrowing amount refinanced using 7.00% fixed-rate long-term debt

The “baseline” sensitivity amounts referenced in the preceding scenarios are quantified in the following table, which reflects the sensitivity of annual interest expense to the noted scenarios (dollars in millions).


(1)	Baseline borrowing amount is after application of proceeds from May 2004 offering, May 2004 issuance of units pursuant to our DRIP and this offering.

(2)	Reflects GulfTerra’s outstanding debt obligations at March 31, 2004.

(3)	Baseline interest rate is a weighted-average rate as of March 31, 2004.

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


	•	common units representing limited partner interests in Enterprise Products Partners L.P.; and

	•	debt securities of Enterprise Products Operating L.P., which will be guaranteed by its parent company, Enterprise Products Partners L.P.

This prospectus provides you with a general description of the securities we may offer. Each time we sell securities we will provide a prospectus supplement that will contain specific information about the terms of that offering. The prospectus supplement may also add, update or change information contained in this prospectus. You should read carefully this prospectus and any prospectus supplement before you invest. You should also read the documents we have referred you to in the “Where You Can Find More Information” section of this prospectus for information on us and for our financial statements.

In addition, common units may be offered from time to time by other holders thereof. Any selling unitholders will be identified, and the number of common units to be offered by them will be specified, in a prospectus supplement to this prospectus. We will not receive proceeds of any sale of shares by any such selling unitholders.

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

Unless otherwise specified in a prospectus supplement, the senior debt securities, when issued, will be unsecured and will rank equally with our other unsecured and unsubordinated indebtedness. The subordinated debt securities, when issued, will be subordinated in right of payment to our senior debt.

Limited partnerships are inherently different from corporations. You should review carefully “Risk Factors” beginning on page 2 for a discussion of important risks you should consider before investing on our securities.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

This prospectus may not be used to consummate sales of securities unless accompanied by a prospectus supplement.

You should rely only on the information contained or incorporated by reference in this prospectus or any prospectus supplement. We have not authorized any other person to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. You should not assume that the information incorporated by reference or provided in this prospectus or any prospectus supplement is accurate as of any date other than the date on the front of each document.

In this prospectus, the terms “we,” “us” and “our” refer to Enterprise Products Partners L.P. and Enterprise Products Operating L.P. and their subsidiaries, unless otherwise indicated or the context requires otherwise.

This prospectus is part of a registration statement that we file with the Securities and Exchange Commission (the “Commission”) using a “shelf” registration process. Under this shelf process, we may offer from time to time up to $1,500,000,000 of our securities. Each time we offer securities, we will provide you with a prospectus supplement that will describe, among other things, the specific amounts and prices of the securities being offered and the terms of the offering. The prospectus supplement may also add, update or change information contained in this prospectus. Any statement that we make in this prospectus will be modified or superseded by any inconsistent statement made by us in a prospectus supplement. Therefore, you should read this prospectus and any attached prospectus supplement before you invest in our securities.

We are a publicly traded limited partnership that was formed in April 1998 to acquire, own, and operate all of the NGL processing and distribution assets of Enterprise Products Company, or EPCO. We conduct all of our business through our 99% owned subsidiary, Enterprise Products Operating L.P., our “Operating Partnership” and its subsidiaries and joint ventures. Our general partner, Enterprise Products GP, LLC, owns a 1.0% interest in us and a 1.0101% interest in our Operating Partnership.

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 and industrial fuels. Our asset platform 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 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 and transportation of natural gas for delivery 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, isobutane, 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 NGL and petrochemical products we produce and/or purchase for resale on a merchant basis.

Certain of our facilities are owned jointly by us and other industry partners, either through co-ownership arrangements or joint ventures. Some of our jointly owned facilities are operated by other owners.

We do not have any employees. All of our management, administrative and operating functions are performed by employees of EPCO, our ultimate parent company, pursuant to the EPCO Agreement. For a discussion of the EPCO Agreement, please read Item 13 of our Annual Report on Form 10-K.

Our principal executive offices are located at 2727 North Loop West, Houston, Texas 77008-1038, and our telephone number is (713) 880-6500.

An investment in our securities involves risks. You should consider carefully the following risk factors, together with all of the other information included in, or incorporated by reference into, this prospectus and any prospectus supplement in evaluating an investment in our securities. This prospectus also contains forward-looking statements that involve risks and uncertainties. Please read “Forward-Looking Statements.” Our actual results could differ materially from those anticipated in the forward-looking statements as a result of certain factors, including the risks described below and elsewhere in this prospectus. If any of these risks occur, our business, financial condition or results of operation could be adversely affected.


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

Our leverage is significant in relation to our partners’ capital. At February 28, 2003, our total outstanding debt, which represented approximately 58.0% of our total capitalization, was approximately $2.1 billion. As of January 31, 2003, we had $2.1 billion of senior indebtedness ranking equal in right of payment to all of our other senior indebtedness. As to the assets of our subsidiary, Seminole Pipeline Company, this $2.1 billion in senior indebtedness is structurally subordinated and ranks junior in right of payment to $45 million of indebtedness of Seminole Pipeline Company.

Debt service obligations, restrictive covenants and maturities resulting from this leverage may adversely affect our ability to finance future operations, pursue acquisitions and fund other capital needs, and may make our results of operations more susceptible to adverse economic or operating conditions. Our ability to repay, extend or refinance our existing debt obligations and to obtain future credit will depend primarily on our operating performance, which will be affected by general economic, financial, competitive, legislative, regulatory, business and other factors, many of which are beyond our control.

Our ability to access the capital markets for future offerings may be limited by adverse market conditions resulting from, among other things, general economic conditions, contingencies and uncertainties that are difficult to predict and beyond our control. If we are unable to access the capital markets for future offerings, we might be forced to seek extensions for some of our short-term maturities or to refinance some of our debt obligations through bank credit, as opposed to long-term public debt securities or equity securities. The price and terms upon which we might receive such extensions or additional bank credit could be more onerous than those contained in our existing debt agreements. Any such arrangements could, in turn, increase the risk that our leverage may adversely affect our future financial and operating flexibility.

The profitability of our operations depends upon the spread between NGL product prices and natural gas prices. NGL product prices and natural gas prices are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control. These factors include:


	•	the level of domestic production;

	•	the availability of imported oil and gas

	•	actions taken by foreign oil and gas producing nations;

	•	the availability of transportation systems with adequate capacity;

	•	the availability of competitive fuels;

	•	fluctuating and seasonal demand for oil, gas and NGLs; and

	•	conservation and the extent of governmental regulation of production and the overall economic environment.

Our Processing segment is directly exposed to commodity price risks, as we take title to NGLs and are obligated under certain of our gas processing contracts to pay market value for the energy extracted from the natural gas stream. We are exposed to various risks, primarily that of commodity price fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control. These pricing risks cannot be completely hedged or eliminated, and any attempt to hedge pricing risks may expose us to financial losses.

A reduction in demand for our 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 adversely affect our results of operations. For example:


	Ethane. If natural gas prices increase significantly in relation to ethane prices, it may be more profitable for natural gas processors 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 will cause the demand for propane to decline significantly and could cause a significant decline in the volumes of propane that we extract and transport.

	Isobutane. Any reduction in demand for motor gasoline in general or MTBE in particular may similarly 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, our operating margin from selling isobutane will be reduced.

	MTBE. A number of states have either banned or currently are considering legislation to ban MTBE. In addition, Congress is contemplating a federal ban on MTBE, and several oil companies have taken an early initiative to phase out the production of MTBE. If MTBE is banned or if its use is significantly limited, the revenues and equity earnings we record may be materially reduced or eliminated. For additional information regarding MTBE, please read “Business and Properties — Regulation and Environmental Matters — Impact of the Clean Air Act’s oxygenated fuels programs on our BEF investment” in our Annual Report on Form 10-K for the year ended December 31, 2002.

	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 we produce and expose our 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.

Please read Items 1 and 2. “Business and Properties — The Company’s Operations” beginning on page 3 of our Annual Report on Form 10-K for a more detailed discussion of our operations.

Our profitability is materially impacted by the volume of NGLs processed at our facilities. A material decrease in natural gas production of crude oil refining, as a result of depressed commodity prices or otherwise, or a decrease in imports of mixed butanes, could result in a decline in the volume of NGLs delivered to our facilities for processing, thereby reducing revenue and operating income.

As a result of business failures, revelations of material misrepresentations and related financial restatements by several large, well-known companies in various industries over the last year, there have been significant disruptions and extreme volatility in the financial markets and credit markets. Because of the credit intensive nature of the energy industry and troubling disclosures by some large, diversified energy companies, the energy industry has been especially impacted by these developments, with the rating agencies downgrading a number of large energy-related companies. Accordingly, in this environment we are exposed to an increased level of credit and performance risk with respect to our customers. If we fail to adequately assess the creditworthiness of existing or future customers, unanticipated deterioration in their creditworthiness could have an adverse impact on us.

From time to time, we evaluate and acquire assets and businesses that we believe complement our existing operations. We may encounter difficulties integrating these acquisitions with our existing businesses without a loss of employees or customers, a loss of revenues, an increase in operating or other costs or other difficulties. In addition, we may not be able to realize the operating efficiencies, competitive advantages, cost savings or other benefits expected from these acquisitions. Future acquisitions may require substantial capital or the incurrence of substantial indebtedness. As a result, our capitalization and results of operations may change significantly following an acquisition, and you will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.

Since the September 11, 2001 terrorist attacks on the United States, the United States government has issued warnings that energy assets, including our nation’s pipeline infrastructure, may be the future target of terrorist organizations. Any terrorist attack on our facilities, those of our customers and, in some cases, those of other pipelines, could have a material adverse effect on our business. An escalation of political tensions in the Middle East and elsewhere, such as the recent commencement of United States military action in Iraq, could result in increased volatility in the world’s energy markets and result in a material adverse effect on our business.

We may not have sufficient cash from operations to pay distributions at the current level following establishment of cash reserves and payments of fees and expenses, including payments to our general partner.

Because distributions on our common units are dependent on the amount of cash we generate, distributions may fluctuate based on our performance. We cannot guarantee that we will continue to pay distributions at the current level each quarter. The actual amount of cash that is available to be distributed each quarter will depend upon numerous factors, some of which are beyond our control and the control of our general partner. These factors include but are not limited to the following:


	•	the level of our operating costs;

	•	the level of competition in our business segments;

	•	prevailing economic conditions;

	•	the level of capital expenditures we make;

	•	the restrictions contained in our debt agreements and our debt service requirements;


	•	fluctuations in our working capital needs;

	•	the cost of acquisitions, if any; and

	•	the amount, if any, of cash reserves established by our general partner, in its discretion.

In addition, you should be aware that our ability to pay the minimum quarterly distribution each quarter depends primarily on our cash flow, including cash flow from financial reserves and working capital borrowings, and not solely on profitability, which is affected by non-cash items. As a result, we may make cash distributions during periods when we record losses and we may not make distributions during periods when we record net income.

Cost reimbursements due our general partner may be substantial and will reduce our cash available for distribution to holders of common units.

Prior to making any distribution on our common units, we will reimburse our general partner and its affiliates, including officers and directors of our general partner, for expenses they incur on our behalf. The reimbursement of expenses could adversely affect our ability to pay cash distributions to holders of common units. Our general partner has sole discretion to determine the amount of these expenses, subject to an annual limit. In addition, our general partner and its affiliates may provide us other services for which we will be charged fees as determined by our general partner.

Our general partner and its affiliates have limited fiduciary responsibilities and conflicts of interest with respect to our partnership.

The directors and officers of our general partner and its affiliates have duties to manage the general partner in a manner that is beneficial to its members. At the same time, our general partner has duties to manage our partnership in a manner that is beneficial to us. Therefore, our general partner’s duties to us may conflict with the duties of its officers and directors to its members.


	•	decisions of our general partner regarding the amount and timing of asset purchases and sales, cash expenditures, borrowings, issuances of additional units and reserves in any quarter may affect the level of cash available to pay quarterly distributions to unitholders and the general partner;

	•	under our partnership agreement, our general partner determines which costs incurred by it and its affiliates are reimbursable by us;

	•	our general partner is allowed to take into account the interests of parties other than us, such as Enterprise Products Company, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to unitholders;

	•	affiliates of our general partner may compete with us in certain circumstances;

	•	our general partner may limit its liability and reduce its fiduciary duties, while also restricting the remedies available to unitholders for actions that might, without the limitations, constitute breaches of fiduciary duty. As a result of purchasing units, you are deemed to consent to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable law;

	•	we do not have any employees and we rely solely on employees of the general partner and its affiliates; and

	•	in some instances, our general partner may cause us to borrow funds in order to permit the payment of distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to hasten the expiration of the subordination period.

Even if unitholders are dissatisfied, they cannot easily remove our general partner.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders did not elect our general partner or the directors of the general partner and will have no right to elect our general partner or the directors of our general partner on an annual or other continuing basis.

Furthermore, if unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. Our general partner may not be removed except upon the vote of the holders of at least 66 2/3% of the outstanding units voting together as a single class. Because affiliates of our general partner own more than one-third of our outstanding units, the general partner currently cannot be removed without the consent of the general partner and its affiliates.

Unitholders’ voting rights are further restricted by the partnership agreement provision stating that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner and its affiliates, cannot be voted on any matter. In addition, the partnership agreement contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

As a result of these provisions, the price at which the common units will trade may be lower because of the absence or reduction of a takeover premium in the trading price.

If our general partner is removed without cause during the subordination period, your distribution and liquidation preference over the subordinated units will be prematurely eliminated.

If our general partner is removed without cause during the subordination period, all remaining subordinated units will automatically convert into common units and will share distributions with the existing common units pro rata, existing arrearages on the common units will be extinguished and the common units will no longer be entitled to arrearages if we fail to pay the minimum quarterly distribution in any quarter. A removal of the general partner under these circumstances would adversely affect the common units by prematurely eliminating their distribution and liquidation preference over the subordinated units, which otherwise would have continued until we had met certain distribution and performance tests.

Under our partnership agreement, cause is narrowly defined to mean that a court of competent jurisdiction has entered a final non-appealable judgment finding our general partner liable for actual fraud, gross negligence or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of the general partner because of the unitholders’ dissatisfaction with the general partner’s performance in managing our partnership will most likely result in the termination of the subordination period.

We may issue additional common units without the approval of common unitholders, which would dilute their existing ownership interests.

During the subordination period, our general partner may cause us to issue up to 54,550,000 additional common units without any approval by the common unitholders. Our general partner may also cause us to issue an unlimited number of additional common units or other equity securities of equal rank with the common units, without such approval, in a number of circumstances, such as:


	•	the issuance of common units in connection with acquisitions that increase cash flow from operations per unit on a pro forma basis;

	•	the conversion of subordinated units into common units;

	•	the conversion of special units into common units;


	•	the conversion of the general partner interest and the incentive distribution rights into common units as a result of the withdrawal of our general partner; or

	•	issuances of common units under our long-term incentive plan.

After the end of the subordination period, we may issue an unlimited number of limited partner interests of any type without the approval of the unitholders. Our partnership agreement does not give the common unitholders the right to approve our issuance of equity securities ranking junior to the common units.

The issuance of additional common units or other equity securities of equal or senior rank will have the following effects:


	•	the proportionate ownership interest of common unitholders in us will decrease;

	•	the amount of cash available for distribution on each unit may decrease;

	•	since a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by the common unitholders will increase;

	•	the relative voting strength of each previously outstanding unit may be diminished; and

	•	the market price of the common units may decline.

Our general partner has a limited call right that may require common unitholders to sell their units at an undesirable time or price.

If at any time our general partner and its affiliates own 85% more of the common units then outstanding, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the remaining common units held by unaffiliated persons at a price not less than their then current market price. As a result, common unitholders may be required to sell their common units at an undesirable time or price and may therefore not receive any return on their investment. They may also incur a tax liability upon a sale of their units. Under our partnership agreement, Shell is not deemed to be an affiliate of our general partner for purposes of this limited call right.

Common unitholders may not have limited liability if a court finds that limited partner actions constitute control of our business.

Under Delaware law, common unitholders could be held liable for our obligations to the same extent as a general partner if a court determined that the right of limited partners to remove our general partner or to take other action under the partnership agreement constituted participation in the “control” of our business.

Under Delaware law, the general partner generally has unlimited liability for the obligations of the partnership, such as its debts and environmental liabilities, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner.

In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that, under some circumstances, a limited partner may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.

You are urged to read “Tax Consequences” beginning on page 39 for a more complete discussion of the following federal income tax risks related to owning and disposing of common units.

The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us.

A change in current law or a change in our business could cause us to be taxed as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, then the minimum quarterly distribution and the target distribution levels will be decreased to reflect that impact on us.

We have not requested a ruling from the IRS with respect to any matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel expressed in the accompanying prospectus or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not concur with our counsel’s conclusions or the positions we take. Any contest with the IRS may materially and adversely impact the market for common units and the price at which they trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will be borne indirectly by our unitholders and our general partner.

Common unitholders will be required to pay federal income taxes and, in some cases, state, local and foreign income taxes on their share of our taxable income even if they do not receive any cash distributions from us. They may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from their share of our taxable income.

If you sell your common units, you will recognize gain or loss equal to the difference between the amount realized and your tax basis in those common units. Prior distributions to you in excess of the total net taxable income you were allocated for a common unit, which decreased your tax basis in that common unit, will, in effect, become taxable income to you if the common unit is sold at a price greater than your tax basis in that common unit, even if the price you receive is less than your original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to you. Should the IRS successfully contest some positions we take, you could recognize more gain on the sale of units than would be the case under those positions, without the benefit of decreased income in prior years. Also, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale.

Investment in common units by tax-exempt entities, such as individual retirement accounts (known as IRAs), regulated investment companies (known as mutual funds) and foreign persons raises issues unique to them. For example, virtually all of our income allocated to unitholders who are organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to them. Very little of our income will be qualifying income to a regulated investment company or mutual fund. Distributions to foreign persons will be reduced by withholding taxes at the highest effective U.S. federal income tax rate for individuals, and foreign persons will be required to file federal income tax returns and pay tax on their share of our taxable income.

We are registered with the IRS as a “tax shelter.” Our tax shelter registration number is 9906100007. The tax laws require that some types of entities, including some partnerships, register as “tax shelters” in response to the perception that they claim tax benefits that may be unwarranted. As a result, we may be audited by the IRS and tax adjustments could be made. Any unitholder owning less than a 1% profits interest in us has very limited rights to participate in the income tax audit process. Further, any adjustments in our tax returns will lead to adjustments in our unitholders’ tax returns and may lead to audits of unitholders’ tax returns and adjustments of items unrelated to us. You will bear the cost of any expense incurred in connection with an examination of your personal tax return and indirectly bear a portion of the cost of an audit of us.

Because we cannot match transferors and transferees of common units, we adopt depreciation and amortization positions that may not conform with all aspects of applicable Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to a common unitholder. It also could affect the timing of these tax benefits or the amount of gain from a sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to the common unitholder’s tax returns.

In addition to federal income taxes, common unitholders will likely be subject to other taxes, including state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property and in which they do not reside. Common unitholders may be required to file state and local income tax returns and pay state and local income taxes in many or all of the jurisdictions in which we do business or own property. Further, they may be subject to penalties for failure to comply with those requirements. It is the responsibility of the common unitholder to file all United States federal, state and local tax returns. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in the common units.

We will use the net proceeds from any sale of securities described in this prospectus for future business acquisitions and other general corporate purposes, such as working capital, investments in subsidiaries, the retirement of existing debt and/or the repurchase of common units or other securities. The prospectus supplement will describe the actual use of the net proceeds from the sale of securities. The exact amounts to be used and when the net proceeds will be applied to corporate purposes will depend on a number of factors, including our funding requirements and the availability of alternative funding sources.

We will not receive any proceeds from any sale of common units by any selling unitholders.

The ratios of earnings to fixed charges for each of the periods indicated are as follows:

These computations include us and our subsidiaries, and 50% or less equity companies. For these ratios, “earnings” is the amount resulting from adding and subtracting the following items.


	•	pre-tax income from continuing operations before adjustment for minority interests in consolidated subsidiaries or income or loss from equity investees;

	•	fixed charges;

	•	amortization of capitalized interest;

	•	distributed income of equity investees; and

	•	our share of pre-tax losses of equity investees for which charges arising from guarantees are included in fixed charges.


	•	interest capitalized;

	•	preference security dividend requirements of consolidated subsidiaries; and

	•	minority interest in pre-tax income of subsidiaries that have not incurred fixed charges.


	•	interest expensed and capitalized;

	•	amortized premiums, discounts and capitalized expenses related to indebtedness;

	•	an estimate of the interest within rental expenses (equal to one-third of rental expense); and

	•	preference security dividend requirements of consolidated subsidiaries.

In this Description of Debt Securities references to the “Issuer” mean only Enterprise Products Operating L.P. and not its subsidiaries. References to the “Guarantor” mean only Enterprise Products Partners L.P. and not its subsidiaries. References to “we” and “us” mean the Issuer and the Guarantor collectively.

The debt securities will be issued under an Indenture dated as of March 15, 2000 (the “Indenture”), among the Issuer, the Guarantor, and Wachovia Bank, National Association (successor to First Union National Bank), as trustee (the “Trustee”). The terms of the debt securities will include those expressly set forth in the Indenture and those made part of the Indenture by reference to the Trust Indenture Act of 1939, as amended (the “Trust Indenture Act”). Capitalized terms used in this Description of Debt Securities have the meanings specified in the Indenture.

This Description of Debt Securities is intended to be a useful overview of the material provisions of the debt securities and the Indenture. Since this Description of Debt Securities is only a summary, you should refer to the Indenture for a complete description of our obligations and your rights.

The Indenture does not limit the amount of debt securities that may be issued thereunder. Debt securities may be issued under the Indenture from time to time in separate series, each up to the aggregate amount authorized for such series. The debt securities will be general obligations of the Issuer and the Guarantor and may be subordinated to Senior Indebtedness of the Issuer and the Guarantor. See “— Subordination.”

A prospectus supplement and a supplemental indenture (or a resolution of our Board of Directors and accompanying officers’ certificate) relating to any series of debt securities being offered will include specific terms relating to the offering. These terms will include some or all of the following:


	•	the form and title of the debt securities;

	•	the total principal amount of the debt securities;

	•	the portion of the principal amount which will be payable if the maturity of the debt securities is accelerated;

	•	the currency or currency unit in which the debt securities will be paid, if not U.S. dollars;

	•	any right we may have to defer payments of interest by extending the dates payments are due whether interest on those deferred amounts will be payable as well;

	•	the dates on which the principal of the debt securities will be payable;

	•	the interest rate which the debt securities will bear and the interest payment dates for the debt securities;

	•	any optional redemption provisions;

	•	any sinking fund or other provisions that would obligate us to repurchase or otherwise redeem the debt securities;

	•	any changes to or additional Events of Default or covenants;

	•	whether the debt securities are to be issued as Registered Securities or Bearer Securities or both; and any special provisions for Bearer Securities;


	•	the subordination, if any, of the debt securities and any changes to the subordination provisions of the Indenture; and

	•	any other terms of the debt securities.

The prospectus supplement will also describe any material United States federal income tax consequences or other special considerations applicable to the applicable series of debt securities, including those applicable to:


	•	Bearer Securities;

	•	debt securities with respect to which payments of principal, premium or interest are determined with reference to an index or formula, including changes in prices of particular securities, currencies or commodities;

	•	debt securities with respect to which principal, premium or interest is payable in a foreign or composite currency;

	•	debt securities that are issued at a discount below their stated principal amount, bearing no interest or interest at a rate that at the time of issuance is below market rates; and

	•	variable rate debt securities that are exchangeable for fixed rate debt securities.

At our option, we may make interest payments, by check mailed to the registered holders thereof or, if so stated in the applicable prospectus supplement, at the option of a holder by wire transfer to an account designated by the holder. Except as otherwise provided in the applicable prospectus supplement, no payment on a Bearer Security will be made by mail to an address in the United States or by wire transfer to an account in the United States.

Unless otherwise provided in the applicable prospectus supplement, Registered Securities may be transferred or exchanged at the office of the Trustee at which its corporate trust business is principally administered in the United States or at the office of the Trustee or the Trustee’s agent in New York City, subject to the limitations provided in the Indenture, without the payment of any service charge, other than any applicable tax or governmental charge. Bearer Securities will be transferable only by delivery. Provisions with respect to the exchange of Bearer Securities will be described in the applicable prospectus supplement.

Any funds we pay to a paying agent for the payment of amounts due on any debt securities that remain unclaimed for two years will be returned to us, and the holders of the debt securities must thereafter look only to us for payment thereof.

The Guarantor will unconditionally guarantee to each holder and the Trustee the full and prompt payment of principal of, premium, if any, and interest on the debt securities, when and as the same become due and payable, whether at maturity, upon redemption or repurchase, by declaration of acceleration or otherwise.

Except as set forth below or as may be provided in a prospectus supplement and supplemental indenture, neither the Issuer nor the Guarantor is restricted by the Indenture from incurring any type of indebtedness or other obligation, from paying dividends or making distributions on its partnership interests or capital stock or purchasing or redeeming its partnership interests or capital stock. The Indenture does not require the maintenance of any financial ratios or specified levels of net worth or liquidity. In addition, the Indenture does not contain any provisions that would require the Issuer to repurchase or redeem or otherwise modify the terms of any of the debt securities upon a change in control or other events involving the Issuer which may adversely affect the creditworthiness of the debt securities.

Limitations on Liens. The Indenture provides that the Guarantor will not, nor will it permit any Subsidiary to, create, assume, incur or suffer to exist any mortgage, lien, security interest, pledge, charge or other encumbrance (“liens”) other than Permitted Liens (as defined below) upon any Principal Property (as defined below) or upon any shares of capital stock of any Subsidiary owning or leasing any Principal Property, whether owned or leased on the date of the Indenture or thereafter acquired, to secure any indebtedness for borrowed money (“debt”) of the Guarantor or the Issuer or any other person (other than the debt securities), without in any such case making effective provision whereby all of the debt securities outstanding shall be secured equally and ratably with, or prior to, such debt so long as such debt shall be so secured.


	(1) the Issuer; or

	(2) any corporation, association or other business entity of which more than 50% of the total voting power of the equity interests entitled (without regard to the occurrence of any contingency) to vote in the election of directors, managers or trustees thereof or any partnership of which more than 50% of the partners’ equity interests (considering all partners’ equity interests as a single class) is, in each case, at the time owned or controlled, directly or indirectly, by the Guarantor, the Issuer or one or more of the other Subsidiaries of the Guarantor or the Issuer or combination thereof.


	(1) liens upon rights-of-way for pipeline purposes;

	(2) any statutory or governmental lien or lien arising by operation of law, or any mechanics’, repairmen’s, materialmen’s, suppliers’, carriers’, landlords’, warehousemen’s or similar lien incurred in the ordinary course of business which is not yet due or which is being contested in good faith by appropriate proceedings and any undetermined lien which is incidental to construction, development, improvement or repair; or any right reserved to, or vested in, any municipality or public authority by the terms of any right, power, franchise, grant, license, permit or by any provision of law, to purchase or recapture or to designate a purchaser of, any property;

	(3) liens for taxes and assessments which are (a) for the then current year, (b) not at the time delinquent, or (c) delinquent but the validity or amount of which is being contested at the time by the Guarantor or any Subsidiary in good faith by appropriate proceedings;

	(4) liens of, or to secure performance of, leases, other than capital leases; or any lien securing industrial development, pollution control or similar revenue bonds;

	(5) any lien upon property or assets acquired or sold by the Guarantor or any Subsidiary resulting from the exercise of any rights arising out of defaults on receivables;

	(6) any lien in favor of the Guarantor or any Subsidiary; or any lien upon any property or assets of the Guarantor or any Subsidiary in existence on the date of the execution and delivery of the Indenture;

	(7) any lien in favor of the United States of America or any state thereof, or any department, agency or instrumentality or political subdivision of the United States of America or any state thereof, to secure partial, progress, advance, or other payments pursuant to any contract or statute, or any debt incurred by the Issuer or any Subsidiary for the purpose of financing all or any part of the purchase price of, or the cost of constructing, developing, repairing or improving, the property or assets subject to such lien;

	(8) any lien incurred in the ordinary course of business in connection with workmen’s compensation, unemployment insurance, temporary disability, social security, retiree health or similar laws or regulations or to secure obligations imposed by statute or governmental regulations;

	(9) liens in favor of any person to secure obligations under provisions of any letters of credit, bank guarantees, bonds or surety obligations required or requested by any governmental authority in


	connection with any contract or statute; or any lien upon or deposits of any assets to secure performance of bids, trade contracts, leases or statutory obligations;

	(10) any lien upon any property or assets created at the time of acquisition of such property or assets by the Guarantor or any Subsidiary or within one year after such time to secure all or a portion of the purchase price for such property or assets or debt incurred to finance such purchase price, whether such debt was incurred prior to, at the time of or within one year after the date of such acquisition; or any lien upon any property or assets to secure all or part of the cost of construction, development, repair or improvements thereon or to secure debt incurred prior to, at the time of, or within one year after completion of such construction, development, repair or improvements or the commencement of full operations thereof (whichever is later), to provide funds for any such purpose;

	(11) any lien upon any property or assets existing thereon at the time of the acquisition thereof by the Guarantor or any Subsidiary and any lien upon any property or assets of a person existing thereon at the time such person becomes a Subsidiary by acquisition, merger or otherwise; provided that, in each case, such lien only encumbers the property or assets so acquired or owned by such person at the time such person becomes a Subsidiary;

	(12) liens imposed by law or order as a result of any proceeding before any court or regulatory body that is being contested in good faith, and liens which secure a judgment or other court-ordered award or settlement as to which the Guarantor or the applicable Subsidiary has not exhausted its appellate rights;

	(13) any extension, renewal, refinancing, refunding or replacement (or successive extensions, renewals, refinancing, refunding or replacements) of liens, in whole or in part, referred to in clauses (1) through (12) above; provided, however, that any such extension, renewal, refinancing, refunding or replacement lien shall be limited to the property or assets covered by the lien extended, renewed, refinanced, refunded or replaced and that the obligations secured by any such extension, renewal, refinancing, refunding or replacement lien shall be in an amount not greater than the amount of the obligations secured by the lien extended, renewed, refinanced, refunded or replaced and any expenses of the Guarantor and its Subsidiaries (including any premium) incurred in connection with such extension, renewal, refinancing, refunding or replacement; or

	(14) any lien resulting from the deposit of moneys or evidence of indebtedness in trust for the purpose of defeasing debt of the Guarantor or any Subsidiary.

“Principal Property” means, whether owned or leased on the date of the Indenture or thereafter acquired:


	(1) any pipeline assets of the Guarantor or any Subsidiary, including any related facilities employed in the transportation, distribution, storage or marketing of refined petroleum products, natural gas liquids, and petrochemicals, that are located in the United States of America or any territory or political subdivision thereof; and

	(2) any processing or manufacturing plant or terminal owned or leased by the Guarantor or any Subsidiary that is located in the United States or any territory or political subdivision thereof,


	(a) any such assets consisting of inventories, furniture, office fixtures and equipment (including data processing equipment), vehicles and equipment used on, or useful with, vehicles; and

	(b) any such assets, plant or terminal which, in the opinion of the board of directors of the General Partner, is not material in relation to the activities of the Issuer or of the Guarantor and its Subsidiaries taken as a whole.

Notwithstanding the foregoing, under the Indenture, the Guarantor may, and may permit any Subsidiary to, create, assume, incur, or suffer to exist any lien upon any Principal Property to secure debt of the Guarantor or any other person (other than the debt securities) other than a Permitted Lien without securing the debt securities, provided that the aggregate principal amount of all debt then outstanding secured by such lien and all similar liens, together with all Attributable Indebtedness from Sale-Leaseback Transactions

“Consolidated Net Tangible Assets” means, at any date of determination, the total amount of assets after deducting therefrom:


	(1) all current liabilities (excluding (A) any current liabilities that by their terms are extendable or renewable at the option of the obligor thereon to a time more than 12 months after the time as of which the amount thereof is being computed, and (B) current maturities of long-term debt); and

	(2) the value (net of any applicable reserves) of all goodwill, trade names, trademarks, patents and other like intangible assets, all as set forth, or on a pro forma basis would be set forth, on the consolidated balance sheet of the Guarantor and its consolidated subsidiaries for the Guarantor’s most recently completed fiscal quarter, prepared in accordance with generally accepted accounting principles.

Restriction on Sale-Leasebacks. The Indenture provides that the Guarantor will not, and will not permit any Subsidiary to, engage in the sale or transfer by the Guarantor or any Subsidiary of any Principal Property to a person (other than the Issuer or a Subsidiary) and the taking back by the Guarantor or any Subsidiary, as the case may be, of a lease of such Principal Property (a “Sale-Leaseback Transaction”), unless:


	(1) such Sale-Leaseback Transaction occurs within one year from the date of completion of the acquisition of the Principal Property subject thereto or the date of the completion of construction, development or substantial repair or improvement, or commencement of full operations on such Principal Property, whichever is later;

	(2) the Sale-Leaseback Transaction involves a lease for a period, including renewals, of not more than three years;

	(3) the Guarantor or such Subsidiary would be entitled to incur debt secured by a lien on the Principal Property subject thereto in a principal amount equal to or exceeding the Attributable Indebtedness from such Sale-Leaseback Transaction without equally and ratably securing the debt securities; or

	(4) the Guarantor or such Subsidiary, within a one-year period after such Sale-Leaseback Transaction, applies or causes to be applied an amount not less than the Attributable Indebtedness from such Sale-Leaseback Transaction to (a) the prepayment, repayment, redemption, reduction or retirement of any debt of the Guarantor or any Subsidiary that is not subordinated to the debt securities, or (b) the expenditure or expenditures for Principal Property used or to be used in the ordinary course of business of the Guarantor or its Subsidiaries. “Attributable Indebtedness,” when used with respect to any Sale-Leaseback Transaction, means, as at the time of determination, the present value (discounted at the rate set forth or implicit in the terms of the lease included in such transaction) of the total obligations of the lessee for rental payments (other than amounts required to be paid on account of property taxes, maintenance, repairs, insurance, assessments, utilities, operating and labor costs and other items that do not constitute payments for property rights) during the remaining term of the lease included in such Sale-Leaseback Transaction (including any period for which such lease has been extended). In the case of any lease that is terminable by the lessee upon the payment of a penalty or other termination payment, such amount shall be the lesser of the amount determined assuming termination upon the first date such lease may be terminated (in which case the amount shall also include the amount of the penalty or termination payment, but no rent shall be considered as required to be paid under such lease subsequent to the first date upon which it may be so terminated) or the amount determined assuming no such termination.

Notwithstanding the foregoing, under the Indenture the Guarantor may, and may permit any Subsidiary to, effect any Sale-Leaseback Transaction that is not excepted by clauses (1) through (4), inclusive, of the first paragraph under “— Restrictions On Sale-Leasebacks,” provided that the Attributable Indebtedness from such Sale-Leaseback Transaction, together with the aggregate principal amount of outstanding debt

Merger, Consolidation or Sale of Assets. The Indenture provides that each of the Guarantor and the Issuer may, without the consent of the holders of any of the debt securities, consolidate with or sell, lease, convey all or substantially all of its assets to, or merge with or into, any partnership, limited liability company or corporation if:


	(1) the partnership, limited liability company or corporation formed by or resulting from any such consolidation or merger or to which such assets shall have been transferred (the “successor”) is either the Guarantor or the Issuer, as applicable, or assumes all the Guarantor’s or the Issuer’s, as the case may be, obligations and liabilities under the Indenture and the debt securities (in the case of the Issuer) and the Guarantee (in the case of the Guarantor);

	(2) the successor is organized under the laws of the United States, any state or the District of Columbia; and

	(3) immediately after giving effect to the transaction no Default or Event of Default shall have occurred and be continuing.

The successor will be substituted for the Guarantor or the Issuer, as the case may be, in the Indenture with the same effect as if it had been an original party to the Indenture. Thereafter, the successor may exercise the rights and powers of the Guarantor or the Issuer, as the case may be, under the Indenture, in its name or in its own name. If the Guarantor or the Issuer sells or transfers all or substantially all of its assets, it will be released from all liabilities and obligations under the Indenture and under the debt securities (in the case of the Issuer) and the Guarantee (in the case of the Guarantor) except that no such release will occur in the case of a lease of all or substantially all of its assets.

Each of the following will be an Event of Default under the Indenture with respect to a series of debt securities:


	(1) default in any payment of interest on any debt securities of that series when due, continued for 30 days;

	(2) default in the payment of principal of or premium, if any, on any debt securities of that series when due at its stated maturity, upon optional redemption, upon declaration or otherwise;

	(3) failure by the Guarantor or the Issuer to comply for 60 days after notice with its other agreements contained in the Indenture;

	(4) certain events of bankruptcy, insolvency or reorganization of the Issuer or the Guarantor (the “bankruptcy provisions”); or

	(5) the Guarantee ceases to be in full force and effect or is declared null and void in a judicial proceeding or the Guarantor denies or disaffirms its obligations under the Indenture or the Guarantee.

However, a default under clause (3) of this paragraph will not constitute an Event of Default until the Trustee or the holders of 25% in principal amount of the outstanding debt securities of that series notify the Issuer and the Guarantor of the default such default is not cured within the time specified in clause (3) of this paragraph after receipt of such notice.

If an Event of Default (other than an Event of Default described in clause (4) above) occurs and is continuing, the Trustee by notice to the Issuer, or the holders of at least 25% in principal amount of the outstanding debt securities of that series by notice to the Issuer and the Trustee, may, and the Trustee at the request of such holders shall, declare the principal of, premium, if any, and accrued and unpaid interest, if any, on all the debt securities of that series to be due and payable. Upon such a declaration, such principal, premium and accrued and unpaid interest will be due and payable immediately. If an Event of Default

Subject to the provisions of the Indenture relating to the duties of the Trustee, if an Event of Default occurs and is continuing, the Trustee will be under no obligation to exercise any of the rights or powers under the Indenture at the request or direction of any of the holders unless such holders have offered to the Trustee reasonable indemnity or security against any loss, liability or expense. Except to enforce the right to receive payment of principal, premium, if any, or interest when due, no holder may pursue any remedy with respect to the Indenture or the debt securities unless:


	(1) such holder has previously given the Trustee notice that an Event of Default is continuing;

	(2) holders of at least 25% in principal amount of the outstanding debt securities of that series have requested the Trustee to pursue the remedy;

	(3) such holders have offered the Trustee reasonable security or indemnity against any loss, liability or expense;

	(4) the Trustee has not complied with such request within 60 days after the receipt of the request and the offer of security or indemnity; and

	(5) the holders of a majority in principal amount of the outstanding debt securities of that series have not given the Trustee a direction that, in the opinion of the Trustee, is inconsistent with such request within such 60-day period.

Subject to certain restrictions, the holders of a majority in principal amount of the outstanding debt securities of a series are given the right to direct the time, method and place of conducting any proceeding for any remedy available to the Trustee or of exercising any trust or power conferred on the Trustee with respect to that series of debt securities. The Trustee, however, may refuse to follow any direction that conflicts with law or the Indenture or that the Trustee determines is unduly prejudicial to the rights of any other holder or that would involve the Trustee in personal liability. Prior to taking any action under the Indenture, the Trustee will be entitled to indemnification satisfactory to it in its sole discretion against all losses and expenses caused by taking or not taking such action.

The Indenture provides that if a Default occurs and is continuing and is known to the Trustee, the Trustee must mail to each holder notice of the Default within 90 days after it occurs. Except in the case of a Default in the payment of principal of, premium, if any, or interest on any debt securities, the Trustee may withhold notice if and so long as a committee of trust officers of the Trustee in good faith determines that withholding notice is in the interests of the holders. In addition, the Issuer is required to deliver to the Trustee, within 120 days after the end of each fiscal year, a certificate indicating whether the signers thereof know of any Default that occurred during the previous year. The Issuer also is required to deliver to the Trustee, within 30 days after the occurrence thereof, written notice of any events which would constitute certain Defaults, their status and what action the Issuer is taking or proposes to take in respect thereof.

Modifications and amendments of the Indenture may be made by the Issuer, the Guarantor and the Trustee with the consent of the holders of a majority in principal amount of all debt securities then outstanding under the Indenture (including consents obtained in connection with a tender offer or exchange offer for the


	(1) reduce the amount of debt securities whose holders must consent to an amendment;

	(2) reduce the stated rate of or extend the stated time for payment of interest on any debt securities;

	(3) reduce the principal of or extend the stated maturity of any debt securities;

	(4) reduce the premium payable upon the redemption of any debt securities or change the time at which any debt securities may be redeemed as described above under “— Optional Redemption” or any similar provision;

	(5) make any debt securities payable in money other than that stated in the debt securities;

	(6) impair the right of any holder to receive payment of, premium, if any, principal of and interest on such holder’s debt securities on or after the due dates therefor or to institute suit for the enforcement of any payment on or with respect to such holder’s debt securities;

	(7) make any change in the amendment provisions which require each holder’s consent or in the waiver provisions; or

	(8) release the Guarantor or modify the Guarantee in any manner adverse to the holders.

The holders of a majority in aggregate principal amount of the outstanding debt securities of each series affected thereby, on behalf of all such holders, may waive compliance by the Issuer and the Guarantor with certain restrictive provisions of the Indenture. Subject to certain rights of the Trustee as provided in the Indenture, the holders of a majority in aggregate principal amount of the debt securities of each series affected thereby, on behalf of all such holders, may waive any past default under the Indenture (including any such waiver obtained in connection with a tender offer or exchange offer for the debt securities), except a default in the payment of principal, premium or interest or a default in respect of a provision that under the Indenture that cannot be modified or amended without the consent of all holders of the series of debt securities that is affected.

Without the consent of any holder, the Issuer, the Guarantor and the Trustee may amend the Indenture to:


	(1) cure any ambiguity, omission, defect or inconsistency;

	(2) provide for the assumption by a successor corporation, partnership, trust or limited liability company of the obligations of the Guarantor or the Issuer under the Indenture;

	(3) provide for uncertificated debt securities in addition to or in place of certificated debt securities (provided that the uncertificated debt securities are issued in registered form for purposes of Section 163(f) of the Code, or in a manner such that the uncertificated debt securities are described in Section 163(f)(2)(B) of the Code);

	(4) add guarantees with respect to the debt securities;

	(5) secure the debt securities;

	(6) add to the covenants of the Guarantor or the Issuer for the benefit of the holders or surrender any right or power conferred upon the Guarantor or the Issuer;

	(7) make any change that does not adversely affect the rights of any holder; or

	(8) comply with any requirement of the Commission in connection with the qualification of the Indenture under the Trust Indenture Act.

The consent of the holders is not necessary under the Indenture to approve the particular form of any proposed amendment. It is sufficient if such consent approves the substance of the proposed amendment. After an amendment under the Indenture becomes effective, the Issuer is required to mail to the holders a

The Issuer at any time may terminate all its obligations under a series of debt securities and the Indenture (“legal defeasance”), except for certain obligations, including those respecting the defeasance trust and obligations to register the transfer or exchange of the debt securities, to replace mutilated, destroyed, lost or stolen debt securities and to maintain a registrar and paying agent in respect of the debt securities. If the Issuer exercises its legal defeasance option, the Guarantee will terminate with respect to that series.

The Issuer at any time may terminate its obligations under covenants described under “— Certain Covenants” (other than “Merger, Consolidation or Sale of Assets”), the bankruptcy provisions with respect to the Guarantor and the Guarantee provision described under “Events of Default” above with respect to a series of debt securities (“covenant defeasance”).

The Issuer may exercise its legal defeasance option notwithstanding its prior exercise of its covenant defeasance option. If the Issuer exercises its legal defeasance option, payment of the affected series of debt securities may not be accelerated because of an Event of Default with respect thereto. If the Issuer exercises its covenant defeasance option, payment of the affected series of debt securities may not be accelerated because of an Event of Default specified in clause (3), (4), (with respect only to the Guarantor) or (5) under “— Events of Default” above.

In order to exercise either defeasance option, the Issuer must irrevocably deposit in trust (the “defeasance trust”) with the Trustee money or U.S. Government Obligations for the payment of principal, premium, if any, and interest on the series of debt securities to redemption or maturity, as the case may be, and must comply with certain other conditions, including delivery to the Trustee of an opinion of counsel (subject to customary exceptions and exclusions) to the effect that holders of the series of debt securities will not recognize income, gain or loss for Federal income tax purposes as a result of such deposit and defeasance and will be subject to Federal income tax on the same amount and in the same manner and at the same times as would have been the case if such deposit and defeasance had not occurred. In the case of legal defeasance only, such opinion of counsel must be based on a ruling of the Internal Revenue Service or other change in applicable Federal income tax law.

Debt securities of a series may be subordinated to our “Senior Indebtedness,” which we define generally to include all notes or other evidences of indebtedness for money borrowed by the Issuer, including guarantees, that are not expressly subordinate or junior in right of payment to any other indebtedness of the Issuer. Subordinated debt securities will be subordinate in right of payment, to the extent and in the manner set forth in the Indenture and the prospectus supplement relating to such series, to the prior payment of all indebtedness of the Issuer and Guarantor that is designated as “Senior Indebtedness” with respect to the series.

The holders of Senior Indebtedness of the Issuer will receive payment in full of the Senior Indebtedness before holders of subordinated debt securities will receive any payment of principal, premium or interest with respect to the subordinated debt securities:


	•	upon any payment of distribution of our assets of the Issuer to its creditors;

	•	upon a total or partial liquidation or dissolution of the Issuer; or

	•	in a bankruptcy, receivership or similar proceeding relating to the Issuer or its property.

Until the Senior Indebtedness is paid in full, any distribution to which holders of subordinated debt securities would otherwise be entitled will be made to the holders of Senior Indebtedness, except that such

If the Issuer does not pay any principal, premium or interest with respect to Senior Indebtedness within any applicable grace period (including at maturity), or any other default on Senior Indebtedness occurs and the maturity of the Senior Indebtedness is accelerated in accordance with its terms, the Issuer may not:


	•	make any payments of principal, premium, if any, or interest with respect to subordinated debt securities;

	•	make any deposit for the purpose of defeasance of the subordinated debt securities; or

	•	repurchase, redeem or otherwise retire any subordinated debt securities, except that in the case of subordinated debt securities that provide for a mandatory sinking fund, we may deliver subordinated debt securities to the Trustee in satisfaction of our sinking fund obligation,


	•	the default has been cured or waived and the declaration of acceleration has been rescinded;

	•	the Senior Indebtedness has been paid in full in cash; or

	•	the Issuer and the Trustee receive written notice approving the payment from the representatives of each issue of “Designated Senior Indebtedness.”


	•	indebtedness for borrowed money under a bank credit agreement, called “Bank Indebtedness”; and

	•	any specified issue of Senior Indebtedness of at least $100 million.

During the continuance of any default, other than a default described in the immediately preceding paragraph, that may cause the maturity of any Senior Indebtedness to be accelerated immediately without further notice, other than any notice required to effect such acceleration, or the expiration of any applicable grace periods, the Issuer may not pay the subordinated debt securities for a period called the “Payment Blockage Period.” A Payment Blockage Period will commence on the receipt by us and the Trustee of written notice of the default, called a “Blockage Notice,” from the representative of any Designated Senior Indebtedness specifying an election to effect a Payment Blockage Period.


	•	by written notice from the person or persons who gave the Blockage Notice;

	•	by repayment in full in cash of the Senior Indebtedness with respect to which the Blockage Notice was given; or

	•	if the default giving rise to the Payment Blockage Period is no longer continuing.

Unless the holders of Senior Indebtedness shall have accelerated the maturity of the Senior Indebtedness, we may resume payments on the subordinated debt securities after the expiration of the Payment Blockage Period.

Generally, not more than one Blockage Notice may be given in any period of 360 consecutive days unless the first Blockage Notice within the 360-day period is given by holders of Designated Senior Indebtedness, other than Bank Indebtedness, in which case the representative of the Bank Indebtedness may give another Blockage Notice within the period. The total number of days during which any one or more Payment Blockage Periods are in effect, however, may not exceed an aggregate of 179 days during any period of 360 consecutive days.

After all Senior Indebtedness is paid in full and until the subordinated debt securities are paid in full, holders of the subordinated debt securities shall be subrogated to the rights of holders of Senior Indebtedness to receive distributions applicable to Senior Indebtedness.

By reason of the subordination, in the event of insolvency, our creditors who are holders of Senior Indebtedness, as well as certain of our general creditors, may recover more, ratably, than the holders of the subordinated debt securities.

We will issue the debt securities in the form of one or more global securities in fully registered form initially in the name of Cede & Co., as nominee of DTC, or such other name as may be requested by an authorized representative of DTC. The global securities will be deposited with the Trustee as custodian for DTC and may not be transferred except as a whole by DTC to a nominee of DTC or by a nominee of DTC to DTC or another nominee of DTC or by DTC or any nominee to a successor of DTC or a nominee of such successor.


	•	DTC is a limited-purpose trust company organized under the New York Banking Law, a “banking organization” within the meaning of the New York Banking Law, a member of the Federal Reserve System, a “clearing corporation” within the meaning of the New York Uniform Commercial Code, and a “clearing agency” registered pursuant to the provisions of Section 17A of the Exchange Act.

	•	DTC holds securities that its participants deposit with DTC and facilitates the settlement among direct participants of securities transactions, such as transfers and pledges, in deposited securities, through electronic computerized book-entry changes in direct participants’ accounts, thereby eliminating the need for physical movement of securities certificates.

	•	Direct participants include securities brokers and dealers, banks, trust companies, clearing corporations and certain other organizations.

	•	DTC is owned by a number of its direct participants and by the New York Stock Exchange, Inc., the American Stock Exchange LLC and the National Association of Securities Dealers, Inc.

	•	Access to the DTC system is also available to others such as securities brokers and dealers, banks and trust companies that clear through or maintain a custodial relationship with a direct participant, either directly or indirectly.

	•	The rules applicable to DTC and its direct and indirect participants are on file with the Commission.

Purchases of debt securities under the DTC system must be made by or through direct participants, which will receive a credit for the debt securities on DTC’s records. The ownership interest of each actual purchaser of debt securities is in turn to be recorded on the direct and indirect participants’ records. Beneficial owners of the debt securities will not receive written confirmation from DTC of their purchase, but beneficial owners are expected to receive written confirmations providing details of the transaction, as well as periodic statements of their holdings, from the direct or indirect participants through which the beneficial owner entered into the transaction. Transfers of ownership interests in the debt securities are to be accomplished by entries made on the books of direct and indirect participants acting on behalf of beneficial owners. Beneficial owners will not receive certificates representing their ownership interests in the debt securities, except in the event that use of the book-entry system for the debt securities is discontinued.

To facilitate subsequent transfers, all debt securities deposited by direct participants with DTC are registered in the name of DTC’s partnership nominee, Cede & Co., or such other name as may be requested by an authorized representative of DTC. The deposit of debt securities with DTC and their registration in the name of Cede & Co. or such other nominee do not effect any change in beneficial ownership. DTC has no knowledge of the actual beneficial owners of the debt securities; DTC’s records reflect only the identity of the direct participants to whose accounts such debt securities are credited, which may or may not be the

Conveyance of notices and other communications by DTC to direct participants, by, direct participants to indirect participants, and by direct participants and indirect participants to beneficial owners will be governed by arrangements among them, subject to any statutory or regulatory requirements as may be in effect from time to time.

Neither DTC nor Cede & Co. (nor any other DTC nominee) will consent or vote with respect to the global securities. Under its usual procedures, DTC mails an omnibus proxy to the issuer as soon as possible after the record date. The omnibus proxy assigns Cede & Co.’s consenting or voting rights to those direct participants to whose accounts the debt securities are credited on the record date (identified in the listing attached to the omnibus proxy).

All payments on the global securities will be made to Cede & Co., as holder of record, or such other nominee as may be requested by an authorized representative of DTC. DTC’s practice is to credit direct participants’ accounts upon DTC’s receipt of funds and corresponding detail information from us or the Trustee on payment dates in accordance with their respective holdings shown on DTC’s records. Payments by participants to beneficial owners will be governed by standing instructions and customary practices, as is the case with securities held for the accounts of customers in bearer form or registered in “street name,” and will be the responsibility of such participant and not of DTC, us or the Trustee, subject to any statutory or regulatory requirements as may be in effect from time to time. Payment of principal, premium, if any, and interest to Cede & Co. (or such other nominee as may be requested by an authorized representative of DTC) shall be the responsibility of us or the Trustee. Disbursement of such payments to direct participants shall be the responsibility of DTC, and disbursement of such payments to the beneficial owners shall be the responsibility of direct and indirect participants.

DTC may discontinue providing its service as securities depositary with respect to the debt securities at any time by giving reasonable notice to us or the Trustee. In addition, we may decide to discontinue use of the system of book-entry transfers through DTC (or a successor securities depositary). Under such circumstances, in the event that a successor securities depositary is not obtained, note certificates in fully registered form are required to be printed and delivered to beneficial owners of the global securities representing such debt securities.

Neither we, the Trustee nor the initial purchasers will have any responsibility or obligation to direct or indirect participants, or the persons for whom they act as nominees, with respect to the accuracy of the records of DTC, its nominee or any participant with respect to any ownership interest in the debt securities, or payments to, or the providing of notice to participants or beneficial owners.

So long as the debt securities are in DTC’s book-entry system, secondary market trading activity in the debt securities will settle in immediately available funds. All payments on the debt securities issued as global securities will be made by us in immediately available funds.

The debt securities of a series may be issued as Registered Securities (which will be registered as to principal and interest in the register maintained by the registrar for the debt securities) or Bearer Securities (which will be transferable only by delivery). If the debt securities are issuable as Bearer Securities, certain special limitations and conditions will apply.

In compliance with United States federal income tax laws and regulations, we and any underwriter, agent or dealer participating in an offering of Bearer Securities will agree that, in connection with the original issuance of the Bearer Securities and during the period ending 40 days after the issue date, they will not offer, sell or deliver any such Bearer Securities, directly or indirectly, to a United States Person (as defined below) or to any person within the United States, except to the extent permitted under United States Treasury regulations.

Bearer Securities will bear a legend to the following effect: “Any United States person who holds this obligation will be subject to limitations under the United States federal income tax laws, including the limitations provided in Sections 165(j) and 1287(a) of the Internal Revenue Code.” The sections referred to in the legend provide that, with certain exceptions, a United States taxpayer who holds Bearer Securities will not be allowed to deduct any loss with respect to, and will not be eligible for capital gain treatment with respect to any gain realized on the sale, exchange, redemption or other disposition of, the Bearer Securities.

For this purpose, “United States” includes the United States of America and its possessions, and “United States person” means a citizen or resident of the United States, a corporation, partnership or other entity created or organized in or under the laws of the United States, or an estate or trust the income of which is subject to United States federal income taxation regardless of its source.

Pending the availability of a definitive global security or individual Bearer Securities, as the case may be, debt securities that are issuable as Bearer Securities may initially be represented by a single temporary global security, without interest coupons, to be deposited with a common depositary in London for Morgan Guaranty Trust Company of New York, Brussels Office, as operator of the Euroclear System (“Euroclear”), or Centrale de Livraison de Valeurs Mobilieres S.A. (“CEDEL”) for credit to the accounts designated by or on behalf of the purchasers thereof. Following the availability of a definitive global security in bearer form, without coupons attached, or individual Bearer Securities and subject to any further limitations described in the applicable prospectus supplement, the temporary global security will be exchangeable for interests in the definitive global security or for the individual Bearer Securities, respectively, only upon receipt of a “Certificate of Non-U.S. Beneficial Ownership,” which is a certificate to the effect that a beneficial interest in a temporary global security is owned by a person that is not a United States Person or is owned by or through a financial institution in compliance with applicable United States Treasury regulations. No Bearer Security will be delivered in or to the United States. If so specified in the applicable prospectus supplement, interest on a temporary global security will be paid to each of Euroclear and CEDEL with respect to that portion of the temporary global security held for its account, but only upon receipt as of the relevant interest payment date of a Certificate of Non-U.S. Beneficial Ownership.

Our general partner and its directors, officers, employees and members, as such, shall have no liability for any obligations of the Guarantor or the Issuer under the debt securities, the Indenture or the guarantee or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each holder by accepting a note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the debt securities. Such waiver may not be effective to waive liabilities under the federal securities laws, and it is the view of the Commission that such a waiver is against public policy.

The Indenture contains certain limitations on the right of the Trustee, should it become our creditor, to obtain payment of claims in certain cases, or to realize for its own account on certain property received in respect of any such claim as security or otherwise. The Trustee is permitted to engage in certain other transactions. However, if it acquires any conflicting interest within the meaning of the Trust Indenture Act, it must eliminate the conflict or resign as Trustee.

The holders of a majority in principal amount of all outstanding debt securities (or if more than one series of debt securities under the Indenture is affected thereby, all series so affected, voting as a single class) will have the right to direct the time, method and place of conducting any proceeding for exercising any remedy or power available to the Trustee for the debt securities or all such series so affected.

If an Event of Default occurs and is not cured under the Indenture and is known to the Trustee, the Trustee shall exercise such of the rights and powers vested in it by the Indenture and use the same degree of care and skill in its exercise as a prudent person would exercise or use under the circumstances in the conduct of his own affairs. Subject to such provisions, the Trustee will not be under any obligation to exercise any of

Wachovia Bank, National Association is the Trustee under the Indenture and has been appointed by the Issuer as Registrar and Paying Agent with regard to the debt securities. Wachovia Bank, National Association is the Administrative Agent and a lender under the Issuer’s credit facilities.

The Indenture, the debt securities and the guarantee are governed by, and will be construed in accordance with, the laws of the State of New York.

Generally, our common units represent limited partner interests that entitle the holders to participate in our cash distributions and to exercise the rights and privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units, holders of subordinated units and our general partner in and to cash distributions, together with a description of the circumstances under which subordinated units convert into common units, see “Cash Distribution Policy” in this prospectus.

Our outstanding common units are listed on the NYSE under the symbol “EPD.” Any additional common units we issue will also be listed on the NYSE.

The transfer agent and registrar for our common units is Mellon Investor Services LLC.

Each holder of common units is entitled to one vote for each common unit on all matters submitted to a vote of the unitholders.

Except as described below under “— Limited Liability,” the common units will be fully paid, and unitholders will not be required to make additional capital contributions to us.

For a purchaser of common units offered by this prospectus to be registered as a record holder of common units on the books of our transfer agent or issued a common unit certificate, the purchaser must execute a transfer application whereby the purchaser requests admission as a substituted limited partner and makes representations and agrees to provisions stated in the transfer application. If this action is not taken, a purchaser’s common units will be held in nominee accounts.

An assignee, pending its admission as a substituted limited partner, is entitled to an interest in us equivalent to that of a limited partner with respect to the right to share in allocations and distributions, including liquidating distributions. Our general partner will vote and exercise other powers attributable to common units owned by an assignee who has not become a substituted limited partner at the written direction of the assignee. Transferees who do not execute and deliver transfer applications will be treated neither as assignees nor as record holders of common units and will not receive distributions, federal income tax allocations or reports furnished to record holders of common units. The only right the transferees will have is the right to admission as a substituted limited partner in respect of the transferred common units upon execution of a transfer application in respect of the common units. A nominee or broker who has executed a transfer application with respect to common units held in street name or nominee accounts will receive distributions and reports pertaining to its common units.

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”) and that he otherwise acts in conformity with the provisions of our partnership agreement, his liability under the Delaware Act will be limited, subject to some possible exceptions, generally to the amount of capital he is obligated to contribute to us in respect of his units plus his share of any undistributed profits and assets.

Under the Delaware Act, a limited partnership may not make a distribution to a partner to the extent that at the time of the distribution, after giving effect to the distribution, all liabilities of the partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, exceed the fair value of the assets of the limited partnership.

For the purposes of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of the property subject to liability of which recourse of creditors is limited shall be

As soon as practicable. but in no event later than 120 days after the close of each fiscal year, our general partner will furnish or make available to each unitholder of record (as of a record date selected by our general partner) an annual report containing our audited financial statements for the past fiscal year. These financial statements will be prepared in accordance with generally accepted accounting principles. In addition, no later than 45 days after the close of each quarter (except the fourth quarter), our general partner will furnish or make available to each unitholder of record (as of a record date selected by our general partner) a report containing our unaudited financial statements and any other information required by law.

Our general partner will use all reasonable efforts to furnish each unitholder of record information reasonably required for tax reporting purposes within 90 days after the close of each fiscal year. Our general partner’s ability to furnish this summary tax information will depend on the cooperation of unitholders in supplying information to our general partner. Each unitholder will receive information to assist him in determining his U.S. federal and state and Canadian federal and provincial tax liability and filing his U.S. federal and state and Canadian federal and provincial income tax returns.

A limited partner can, for a purpose reasonably related to the limited partner’s interest as a limited partner, upon reasonable demand and at his own expense, have furnished to him:


	•	a current list of the name and last known address of each partner; a copy of our tax returns;

	•	information as to the amount of cash and a description and statement of the agreed value of any other property or services, contributed or to be contributed by each partner and the date on which each became a partner;

	•	copies of our partnership agreement. our certificate of limited partnership, amendments to either of them and powers of attorney which have been executed under our partnership agreement; information regarding the status of our business and financial condition; and

	•	any other information regarding our affairs as is just and reasonable.

Our general partner may, and intends to, keep confidential from the limited partners trade secrets and other information the disclosure of which our general partner believes in good faith is not in our best interest or which we are required by law or by agreements with third parties to keep confidential.

A total of 29,000,000 Class A special units were issued as part of the purchase price of Tejas Natural Gas Liquids LLC. These units do not accrue distributions and are not entitled to cash distributions until their conversion into an equal number of common units. On August 1, 2000, August 1, 2001 and August 1, 2002, 2,000,000, 10,000,000 and 17,000,000 of the Class A special units, respectively, were converted into an equal number of common units. As an additional part of the purchase price of Tejas Natural Gas Liquids LLC, we agreed to issue up to 12,000,000 more Class A special units to the seller if the volumes of natural gas that we process for Shell Oil Company and its affiliates reach certain agreed upon levels in 2000 and 2001. On August 1, 2000, we issued 6,000,000 of these Class A special units to the seller, and on August 1, 2001, we issued the remaining 6,000,000 Class A special units to the seller under our foregoing agreement. On August 1, 2002, 2,000,000 of these additional Class A special units converted into an equal number of common units. The remaining 10,000,000 additional Class A special units will convert into an equal number of common units in August 2003.

General. Within approximately 45 days after the end of each quarter, we will distribute all of our available cash to unitholders of record on the applicable record date.

Definition of Available Cash. Available cash is defined in our partnership agreement and generally means, with respect to any calendar quarter, all cash on hand at the end of such quarter:


	•	less the amount of cash reserves that is necessary or appropriate in the reasonable discretion of the general partner to:


	-	provide for the proper conduct of our business;

	-	comply with applicable law or any debt instrument or other agreement (including reserves for future capital expenditures and for our future credit needs); or


	–	provide funds for distributions to unitholders and our general partner in respect of any one or more of the next four quarters;


	•	plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter. Working capital borrowings are generally borrowings that are made under our credit facilities and in all cases are used solely for working capital purposes or to pay distributions to partners.

General. Cash distributions are characterized as distributions from either operating surplus or capital surplus. We distribute available cash from operating surplus differently than available cash from capital surplus.

Definition of Operating Surplus. Operating surplus is defined in the partnership agreement and generally means:


	•	our cash balance on July 31, 1998, the closing date of our initial public offering of common units (excluding $46.5 million to fund certain capital commitments existing at such closing date); plus

	•	all of our cash receipts since the closing of our initial public offering, excluding cash from interim capital transactions such as borrowings that are not working capital borrowings, sales of equity and debt securities and sales or other disposition of assets for cash, other than inventory, accounts receivable and other assets sold in the ordinary course of business or as part of normal retirements or replacements of assets; plus

	•	up to $60.0 million of cash from interim capital transactions; plus

	•	working capital borrowings made after the end of a quarter but before the date of determination of operating surplus for the quarter; less

	•	all of our operating expenditures since the closing of our initial public offering, including the repayment of working capital borrowings, but not the repayment of other borrowings, and including maintenance capital expenditures; less

	•	the amount of cash reserved that we deem necessary or advisable to provide funds for future operating expenditures.

Definition of Capital Surplus. Capital surplus is generally generated only by borrowings (other than borrowings for working capital purposes), sales of debt and equity securities and sales or other dispositions of assets for cash (other than inventory, accounts receivable and other assets disposed of in the ordinary course of business).

Characterization of Cash Distributions. To avoid the difficulty of trying to determine whether available cash we distribute is from operating surplus or from capital surplus, all available cash we distribute from any source will be treated as distributed from operating surplus until the sum of all available cash distributed since July 31, 1998 equals the operating surplus as of the end of the quarter prior to such distribution. Any available cash in excess of such amount (irrespective of its source) will be deemed to be from capital surplus and distributed accordingly.

If available cash from capital surplus is distributed in respect of each common unit in an aggregate amount per common unit equal to the $11.00 initial public offering price of the common units, plus any common unit arrearages, the distinction between operating surplus and capital surplus will cease, and all distributions of available cash will be treated as if they were from operating surplus. We do not anticipate that there will be significant distributions from capital surplus.

General. With respect to each quarter during the subordination period, to the extent there is sufficient available cash, the holders of common units will have the right to receive the minimum quarterly distribution of $0.225 per unit, plus any common unit arrearages, prior to any distribution of available cash to the holders of subordinated units. The purpose of the subordinated units is to increase the likelihood that during the subordination period there will be sufficient available cash from operating surplus for us to distribute the minimum quarterly distribution on each common unit. Common units will not accrue arrearages with respect to distributions for any quarter after the subordination period, and subordinated units will not accrue any arrearages with respect to distributions for any quarter.

Definition of Subordination Period. The subordination period will generally extend until the first day of any quarter beginning after June 30, 2003 that the following tests are met:


	•	distributions of available cash from operating surplus on each of the outstanding common units and the subordinated units with respect to each of the three consecutive, non-overlapping, four-quarter periods immediately preceding such date equaled or exceeded the minimum quarterly distribution on all of the outstanding common units and subordinated units during such periods;

	•	the adjusted operating surplus generated during each of the three consecutive, non-overlapping, four-quarter periods immediately preceding such date equaled or exceeded the sum of:


	—	the minimum quarterly distribution on all of the outstanding common units and subordinated units during those periods on a fully diluted basis; and

	—	the related distribution on the general partner interests in us and our operating partnership; and

Early Conversion of Subordinated Units. On May 1, 2002, 10,704,936 of the original subordinated units, or approximately 25%, converted into an equal number of common units. As of December 31, 2002, 32,114,804 subordinated units remained outstanding. An additional 10,704,936 subordinated units will convert into an equal number of common units on the first day after the record date established for the distribution in respect of any quarter ending on or after March 31, 2003 if the following tests are met:


	•	distributions of available cash from operating surplus on the common units and the subordinated units with respect to each of the three consecutive, non-overlapping, four-quarter periods immediately preceding such date equaled or exceeded the sum of the minimum quarterly distribution on all of the outstanding common units and subordinated units during such periods;

	•	the adjusted operating surplus generated during each of the three consecutive, non-overlapping, four-quarter periods immediately preceding such date equaled or exceeded the sum of $0.225 per unit on all of the common units and subordinated units that were outstanding during such period on a fully


		diluted basis and the related distribution on the general partner interests in us and our operating partnership; and

	•	there are no outstanding common unit arrearages.

Because the tests for early conversion and the end of the subordination period are the same, if the test for early conversion is not met for the quarter ending March 31, 2003, there will not be any additional early conversion of the subordinated units. If the test is met at the end of any subsequent quarter, then the subordination period will end and all of the subordinated units will convert into common units. On August 1, 2003, 10,000,000 special units owned by Shell that are currently not entitled to distributions will convert into common units and, if the subordination period has not terminated at such time, will be included as common units for purposes of the above test.

Definition of Adjusted Operating Surplus. Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes net increases in working capital borrowings and net drawdowns of reserves of cash generated in prior periods. Adjusted operating surplus for any period generally means:


	•	operating surplus generated during that period; less

	•	any net increase in working capital borrowings during that period; less

	•	any net reduction in cash reserves for operating expenditures during that period not relating to an operating expenditure made during that period; plus

	•	any net decrease in working capital borrowings during that period; plus

	•	any net increase in cash reserves for operating expenditures during that period required by any debt instrument for the repayment of principal, interest or premium.

Effect of Expiration of the Subordination Period. Upon expiration of the subordination period, each outstanding subordinated unit will convert into one common unit and will then participate pro rata with the other common units in distributions of available cash. In addition, if our general partner is removed as our general partner under circumstances where cause does not exist and units held by our general partner and its affiliates are not voted in favor of such removal:


	•	the subordination period will end and all outstanding subordinated units will immediately convert into common units on a one-for-one basis;

	•	any existing common unit arrearages will be extinguished; and

	•	our general partner will have the right to convert its general partner interest into common units or to receive cash in exchange for such interests.

Distributions of Available Cash from Operating Surplus During the Subordination Period

We will make distributions of available cash from operating surplus with respect to any quarter during the subordination period in the following manner:


	•	first, 98% to the common unitholders, pro rata, and 2% to the general partner, until there has been distributed in respect of each outstanding common unit an amount equal to $0.225 per unit for such quarter.

	•	second, 98% to the common unitholders, pro rata, and 2% to the general partner, until there has been distributed in respect of each outstanding common unit an amount equal to any common unit arrearages accrued and unpaid with respect to any prior quarters during the subordination period;

	•	third, 98% to the subordinated unitholders, pro rata, and 2% to the general partner, until there has been distributed in respect of each outstanding subordinated unit an amount equal to $0.225 per unit; and

	•	thereafter, in the manner described in “Incentive Distributions” below.

The above references to the 2% of available cash from operating surplus distributed to the general partner are references to the amount of the percentage interest of our general partner (exclusive of its or any of its affiliates’ interests as holders of common units or subordinated units) in distributions from us and our operating partnership. Our general partner owns a 1% general partner interests in us and a 1.0101% general partner interest in our operating partnership.

With respect to any common unit, the term “common unit arrearages” refers to the amount by which the minimum quarterly distribution of $0.225 per unit in any quarter during the subordination period exceeds the distribution of available cash from operating surplus actually made for such quarter on a common unit issued in our initial public offering, cumulative for such quarter and all prior quarters during the subordination period. Common unit arrearages will not accrue interest.

Distributions of Available Cash from Operating Surplus after Subordination Period

We will make distributions of available cash from operating surplus with respect to any quarter after the subordination period in the following manner:


	•	first, 98% to all common unitholders, pro rata and 2% to the general partner, until there has been distributed in respect of each unit an amount equal to $0.225; and

	•	thereafter, in the manner described in “Incentive Distributions” below.

Incentive distributions represent the right to receive an increasing percentage of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. For any quarter for which available cash from operating surplus is distributed to the common and subordinated unitholders in an amount equal to $0.225 per unit on all units and to the common unitholders in an amount equal to any unpaid common unit arrearages, then any additional available cash from operating surplus in respect of such quarter will be distributed among the unitholders and the general partner in the following manner:


	•	first, 98% to all common and subordinated unitholders, pro rata, and 2% to the general partner, until the unitholders have received a total of $0.253 for such quarter in respect of each outstanding unit (the “First Target Distribution”);

	•	second, 85% to all common and subordinated unitholders, pro rata, and 15% to the general partner, until the unitholders have received a total of $0.3085 for such quarter in respect of each outstanding unit (the “Second Target Distribution”); and

	•	thereafter, 75% to all common and subordinated unitholders, pro rata, and 25% to the general partner.

In each case, the amount of the target distribution set forth above is exclusive of any distributions to our common unitholders to eliminate any cumulative arrearages in payment of the minimum quarterly distribution.

How Distributions from Capital Surplus Will Be Made. We will make distributions of available cash from capital surplus in the following manner:


	•	first, 98% to all common and subordinated unitholders, pro rata, and 2% to the general partner, until we have distributed, in respect of each outstanding common unit issued in our initial public offering, available cash from capital surplus in an aggregate amount per common unit equal to the initial unit price of $11.00;

	•	second, 98% to the holders of common units, pro rata, and 2% to the general partner, until the Company has distributed, in respect of each outstanding common unit, available cash from capital


		surplus in an aggregate amount equal to any unpaid common unit arrearages with respect to such common unit; and

	•	thereafter, all distributions of available cash from capital surplus will be distributed as if they were from operating surplus.

Effect of a Distribution from Capital Surplus. Our partnership agreement treats a distribution of capital surplus on a common unit as the repayment of the common unit price from its initial public offering, which is a return of capital. The initial public offering price less any distributions of capital surplus per common unit is referred to as the unrecovered initial common unit price. Each time a distribution of capital surplus is made on a common unit, the minimum quarterly distribution and the target distribution levels for all units will be reduced in the same proportion as the corresponding reduction in the unrecovered initial common unit price. Because distributions of capital surplus will reduce the minimum quarterly distribution, after any of these distributions are made, it may be easier for our general partner to receive incentive distributions and for the subordinated units to convert into common units. However, any distribution by us of capital surplus before the unrecovered initial common unit price is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.

Once we distribute capital surplus on a common unit in any amount equal to the unrecovered initial common unit price plus any arrearages, it will reduce the minimum quarterly distribution and the target distribution levels to zero and it will make all future distributions of available cash from operating surplus, with 25% being paid to the holders of units, as applicable, and 75% to our general partner.

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

In addition to reductions of the minimum quarterly distribution and target distribution levels made upon a distribution of available cash from capital surplus, if we combine our units into fewer units or subdivide our units into a greater number of units, we will proportionately adjust:


	•	the minimum quarterly distribution;

	•	the target distribution levels;

	•	the unrecovered initial common unit price;

	•	the number of common units issuable during the subordination period without a unitholder vote; and

	•	the number of common units issuable upon conversion of the subordinated units.

For example, in the event of a two-for-one split of the common units (assuming no prior adjustments), the minimum quarterly distribution, each of the target distribution levels and the unrecovered capital of the common units would each be reduced to 50% of its initial level.

In addition, if legislation is enacted or if existing law is modified or interpreted in a manner that causes us to become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, then we will reduce the minimum quarterly distribution and the target distribution levels by multiplying the same by one minus the sum of the highest effective federal corporate income tax rate that could apply and any increase in the effective overall state and local income tax rates. For example, if we became subject to a maximum effective federal, state and local income tax rate of 38%, then the minimum quarterly distribution and the target distribution levels would each be reduced to 62% of their previous levels.

If we dissolve in accordance with the partnership agreement, we will sell or otherwise dispose of our assets in a process called a liquidation. We will first apply the proceeds of liquidation to the payment of our creditors in the order of priority provided in the partnership agreement and by law and, thereafter, we will distribute any remaining proceeds to the unitholders and our general partner in accordance with their respective capital account balances as so adjusted.

Partners are entitled to liquidating distributions in accordance with capital account balances. The allocations of gains and losses upon liquidation are intended, to the extent possible, to entitle the holders of outstanding common units to a preference over the holders of outstanding subordinated units upon our liquidation, to the extent required to permit common unitholders to receive their unrecovered capital plus any unpaid common unit arrearages. Thus, net losses recognized upon our liquidation will be allocated to the holders of the subordinated units to the extent of their capital account balances before any loss is allocated to the holders of the common units, and net gains recognized upon liquidation will be allocated first to restore negative balances in the capital account of the general partner and any unitholders and then to the common unitholders until their capital account balances equal their unrecovered capital plus unpaid common unit arrearages. However, no assurance can be given that there will be sufficient gain upon our liquidation to enable the holders of common units to fully recover all of such amounts, even though there may be cash available after such allocation for distribution to the holders of subordinated units.

Manner of Adjustments for Gain. The manner of the adjustment is set forth in the partnership agreement. If our liquidation occurs before the end of the subordination period, we will allocate any net gain (or unrealized gain attributable to assets distributed in kind to the partners as follows:


	•	first, to the general partner and the holders of units having negative balances in their capital accounts to the extent of and in proportion to such negative balances:

	•	second, 98% to the holders of common units, pro rata, and 2% to the general partner, until the capital account for each common unit is equal to the sum of


	-	the unrecovered capital in respect of such common unit; plus

	-	the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; plus

	-	any unpaid common unit arrearages in respect of such common unit;


	•	third, if the capital account with respect to a Class A special unit is not equal to the capital account with respect to each common unit, 98% to the holders of common units and the holders of Class A special units in the manner and amount necessary to equalize, to the maximum extent possible, the capital account for each common unit and Class A special unit, and 2% to the general partner;

	•	fourth, 98% to the holders of subordinated units, pro rata, and 2% to the general partner, until the capital account for each subordinated unit is equal to the sum of


	-	the unrecovered capital in respect of such subordinated unit; plus

	-	the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;


	•	fifth, 98% to all unitholders, pro rata, and 2% to the general partner, until there has been allocated under this paragraph fifth an amount per unit equal to:


	-	the sum of the excess of the First Target Distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less

	-	the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that were distributed 98% to the unitholders, pro rata, and 2% to the general partner for each quarter of our existence;


	•	sixth, 85% to all unitholders, pro rata, and 15% to the general partner, until there has been allocated under this paragraph sixth an amount per unit equal to:


	-	the sum of the excess of the Second Target Distribution per unit over the First Target Distribution per unit for each quarter of our existence; less


	-	the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the First Target Distribution per unit that were distributed 85% to the unitholders, pro rata, and 15% to the general partner for each quarter of our existence; and


	•	thereafter, 75% to all unitholders, pro rata, and 25% to the general partner.

If the liquidation occurs after the conversion of all the Class A special units into common units, the distinction between Class A special units and common units will disappear, so that all of paragraph third above will no longer be applicable. If the liquidation occurs after the subordination period, the distinction between common units and subordinated units will disappear, so that the third bullet of paragraph second above and all of paragraph fourth above will no longer be applicable.

Manner of Adjustments for Losses. Upon our liquidation, any loss will generally be allocated to the general partner and the unitholders as follows:


	•	first, 98% to holders of subordinated units in proportion to the positive balances in their respective capital accounts and 2% to the general partner, until the capital accounts of the holders of the subordinated units have been reduced to zero;

	•	second, if the capital account with respect to a Class A special unit is not equal to the capital account with respect to each common unit, 98% to the holders of common units and the holders of Class A special units in the manner and amount necessary to equalize, to the maximum extent possible, the capital account for each common unit and Class A special unit, and 2% to the general partner;

	•	third, 98% to the holders of common units in proportion to the positive balances in their respective capital accounts and 2% to the general partner, until the capital accounts of the common unitholders have been reduced to zero; and

	•	thereafter, 100% to the general partner.

If the liquidation occurs after the subordination period, the distinction between common units and subordinated units will disappear, so that all of paragraph first above will no longer be applicable. If the liquidation occurs after the conversion of all the Class A special units into common units, the distinction between Class A special units and common units will disappear, so that all of paragraph second above will no longer be applicable.

Adjustments to Capital Accounts. In addition, interim adjustments to capital accounts will be made at the time we issue additional partnership interests or make distributions of property. Such adjustments will be based on the fair market value of the partnership interests or the property distributed and any gain or loss resulting therefrom will be allocated to the unitholders and the general partner in the same manner as gain or loss is allocated upon liquidation. In the event that positive interim adjustments are made to the capital accounts, any subsequent negative adjustments to the capital accounts resulting from the issuance of additional partnership interests in us, distributions of property by us, or upon our liquidation, will be allocated in a manner which results, to the extent possible, in the capital account balances of the general partner equaling the amount that would have been the general partner’s capital account balances if no prior positive adjustments to the capital accounts had been made.

The following is a summary of the material provisions of our partnership agreement. Our amended and restated partnership agreement has been filed with the Commission, and is incorporated by reference in this prospectus. The following provisions of our partnership agreement are summarized elsewhere in this prospectus:


	•	distributions of our available cash are described under “Cash Distribution Policy”;

	•	allocations of taxable income and other tax matters are described under “Tax Consequences”; and

	•	rights of holders of common units are described under “Description of Our Common Units.”

Our purpose under our partnership agreement is to serve as a partner of our operating partnership and to engage in any business activities that may be engaged in by our operating partnership or that are approved by our general partner. The partnership agreement of our operating partnership provides that it may engage in any activity that was engaged in by our predecessors at the time of our initial public offering or reasonably related thereto and any other activity approved by our general partner.

Each limited partner, and each person who acquires a unit from a unitholder and executes and delivers a transfer application, grants to our general partner and, if appointed, a liquidator, a power of attorney to, among other things, execute and file documents required for our qualification, continuance or dissolution. The power of attorney also grants the authority for the amendment of, and to make consents and waivers under, our partnership agreement.

Our general partner does not receive any compensation for its services as our general partner. It is, however, entitled to be reimbursed for all of its costs incurred in managing and operating our business. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion.

Our partnership agreement authorizes us to issue an unlimited number of additional limited partner interests and other equity securities that are equal in rank with or junior to our common units on terms and conditions established by our general partner in its sole discretion without the approval of any limited partners. During the subordination period, however, except as set forth in the following paragraph, we may not issue an aggregate of more than approximately 54,550,000 additional common units or an equivalent number of units that are equal in rank with our common units, in each case, without the approval of at least a majority of our outstanding common units (excluding common units owned by the general partner and its affiliates).

During the subordination period, we may issue an unlimited number of common units to finance an acquisition or a capital improvement that would have resulted, on a pro forma basis, in an increase in per unit adjusted operating surplus as provided in our partnership agreement.

In no event may we issue partnership interests during the subordination period that are senior to our common units without the approval of the holders of a majority of our outstanding common units (excluding common units owned by the general partner and its affiliates).

It is possible that we will fund acquisitions through the issuance of additional common units or other equity securities. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our cash distributions. In addition, the issuance of additional

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership interests that, in the sole discretion of our general partner, may have special voting rights to which common units are not entitled.

Our general partner has the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units, subordinated units or other equity securities whenever, and on the same terms that, we issue those securities to persons other than our general partner and its affiliates, to the extent necessary to maintain their percentage interests in us that existed immediately prior to the issuance. The holders of common units will not have preemptive rights to acquire additional common units or other partnership interests in us.

Amendments to our partnership agreement may be proposed only by our general partner. Any amendment that materially and adversely affects the rights or preferences of any type or class of limited partner interests in relation to other types or classes of limited partner interests or our general partner interest will require the approval of at least a majority of the type or class of limited partner interests or general partner interests so affected. However, our general partner may make amendments to our partnership agreement without the approval of our limited partners or assignees to reflect:


	•	a change in our name, the location of our principal place of business, our registered agent or our registered office;

	•	the admission, substitution, withdrawal or removal of partners;

	•	a change to qualify or continue our qualification as a limited partnership or a partnership in which our limited partners have limited liability under the laws of any state or to ensure that neither we, our operating partnership, nor any of our subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;

	•	a change that does not adversely affect our limited partners in any material respect;

	•	a change to (i) satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute or (ii) facilitate the trading of our limited partner interests or comply with any rule, regulation, guideline or requirement of any national securities exchange on which our limited partner interests are or will be listed for trading;

	•	a change in our fiscal year or taxable year and any changes that are necessary or advisable as a result of a change in our fiscal year or taxable year;

	•	an amendment that is necessary to prevent us, or our general partner or its directors, officers, trustees or agents from being subjected to the provisions of the Investment Company Act of 1940, as amended, the Investment Advisers Act of 1940, as amended, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, as amended;

	•	an amendment that is necessary or advisable in connection with the authorization or issuance of any class or series of our securities;

	•	any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;

	•	an amendment effected, necessitated or contemplated by a merger agreement approved in accordance with our partnership agreement;

	•	an amendment that is necessary or advisable to reflect, account for and deal with appropriately our formation of, or investment in, any corporation, partnership, joint venture, limited liability company or


		other entity other than our operating partnership, in connection with our conduct of activities permitted by our partnership agreement;

	•	a merger or conveyance to effect a change in our legal form; or

	•	any other amendments substantially similar to the foregoing.

Our general partner has agreed not to withdraw voluntarily as our general partner prior to December 31, 2008 without obtaining the approval of the holders of a majority of our outstanding common units, excluding those held by our general partner and its affiliates, and furnishing an opinion of counsel stating that such withdrawal (following the selection of the successor general partner) would not result in the loss of the limited liability of any of our limited partners or of a member of our operating partnership or cause us or our operating partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not previously treated as such).

On or after December 31, 2008, our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days’ written notice, and that withdrawal will not constitute a violation of our partnership agreement. In addition, our general partner may withdraw without unitholder approval upon 90 days’ notice to our limited partners if at least 50% of our outstanding common units are held or controlled by one person and its affiliates other than our general partner and its affiliates.

Upon the voluntary withdrawal of our general partner, the holders of a majority of our outstanding common units, excluding the common units held by the withdrawing general partner and its affiliates, may elect a successor to the withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within 90 days after that withdrawal, the holders of a majority of our outstanding units, excluding the common units held by the withdrawing general partner and its affiliates, and the holders of a majority of the subordinated units, voting as separate classes, agree to continue our business and to appoint a successor general partner.

Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than two-thirds of our outstanding units, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of this kind is also subject to the approval of a successor general partner by the vote of the holders of a majority of our outstanding common units, including those held by our general partner and its affiliates, and the holders of a majority of the subordinated units, voting as separate classes.

While our partnership agreement limits the ability of our general partner to withdraw, it allows the general partner interest to be transferred to an affiliate or to a third party in conjunction with a merger or sale of all or substantially all of the assets of our general partner. In addition, our partnership agreement expressly permits the sale, in whole or in part, of the ownership of our general partner. Our general partner may also transfer, in whole or in part, the common units and subordinated units it owns.

Upon our dissolution, unless we are reconstituted and continued as a new limited partnership, the person authorized to wind up our affairs (the liquidator) will, acting with all the powers of our general partner that


	•	first, towards the payment of all of our creditors and the creation of a reserve for contingent liabilities; and

	•	then, to all partners in accordance with the positive balance in the respective capital accounts.

Under some circumstances and subject to some limitations, the liquidator may defer liquidation or distribution of our assets for a reasonable period of time. If the liquidator determines that a sale would be impractical or would cause a loss to our partners, our general partner may distribute assets in kind to our partners.

Our partnership agreement contains the following specific provisions that are intended to discourage a person or group from attempting to remove our general partner or otherwise change management:


	•	if the holders, including the general partner and its affiliates, of at least 66 2/3% of the units vote to remove the general partner without cause, all remaining subordinated units will automatically convert into common units and will share distributions with the existing common units pro rata, existing arrearages on the common units will be extinguished and the common units will no longer be entitled to arrearages if we fail to pay the minimum quarterly distribution in any quarter. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding the general partner liable for actual fraud, gross negligence or willful or wanton misconduct in its capacity as our general partner;

	•	any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner and its affiliates, cannot be voted on any matter; and

	•	the partnership agreement contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

If at any time our general partner and its affiliates own 85% or more of the issued and outstanding limited partner interests of any class, our general partner will have the right to purchase all, but not less than all, of the outstanding limited partner interests of that class that are held by non-affiliated persons. The record date for determining ownership of the limited partner interests would be selected by our general partner on at least 10 but not more than 60 days’ notice. The purchase price in the event of a purchase under these provisions would be the greater of (1) the current market price (as defined in our partnership agreement) of the limited partner interests of the class as of the date three days prior to the date that notice is mailed to the limited partners as provided in the partnership agreement and (2) the highest cash price paid by our general partner or any of its affiliates for any limited partner interest of the class purchased within the 90 days preceding the date our general partner mails notice of its election to purchase the units. Under our partnership agreement, Shell is not deemed to be an affiliate of our general partner for purposes of this limited call right.

As of March 1, 2003, our general partner and its affiliates own 81,875,602 common units and 32,114,804 subordinated units, representing an aggregate 56.8% limited partner interest in us.

Under our partnership agreement, in most circumstances, we will indemnify our general partner, its affiliates and their officers and directors to the fullest extent permitted by law, from and against all losses, claims or damages any of them may suffer by reason of their status as general partner, officer or director, as long as the person seeking indemnity acted in good faith and in a manner believed to be in or not opposed to our best interest. Any indemnification under these provisions will only be out of our assets. Our general

Under our partnership agreement, we have agreed to register for resale under the Securities Act of 1933, as amended (the “Securities Act”) and applicable state securities laws any common units, subordinated units or other partnership securities proposed to be sold by our general partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and commissions.

This section is a summary of the material tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States and, unless otherwise noted in the following discussion, represents the opinion of Vinson & Elkins L.L.P., special counsel to the general partner and us, insofar as it relates to matters of United States federal income tax law matters. This section is based upon current provisions of the Internal Revenue Code, existing and proposed regulations and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below.

The following discussion does not comment on all federal income tax matters affecting us or the unitholders. Moreover, the discussion focuses on unitholders who are individual citizens or residents of the United States and has only limited application to corporations, estates, trusts, nonresident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, foreign persons, individual retirement accounts (IRAs), real estate investment trusts (REITs)or mutual funds. Accordingly, we recommend that each prospective unitholder consult, and depend on, his own tax advisor in analyzing the federal, state, local and foreign tax consequences particular to him of the ownership or disposition of common units.

All statements as to matters of law and legal conclusions, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of counsel and are based on the accuracy of the representations made by us.

No ruling has been or will be requested from the IRS regarding any matter affecting us or prospective unitholders. Instead, we will rely on opinions and advice of Vinson & Elkins L.L.P. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made here may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the common units and the prices at which common units trade. In addition, the costs of any contest with the IRS will be borne directly or indirectly by the unitholders and the general partner. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

For the reasons described below, counsel has not rendered an opinion with respect to the following specific federal income tax issues:


	(1) the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units (please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales”);

	(2) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “— Disposition of Common Units — Allocations Between Transferors and Transferees”); and

	(3) whether our method for depreciating Section 743 adjustments is sustainable (please read “— Tax Consequences of Unit Ownership — Section 754 Election”).

A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not taxable unless the amount of cash distributed is in excess of the partner’s adjusted basis in his partnership interest.

Section 7704 of the Internal Revenue Code provides that publicly-traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the “Qualifying Income Exception,” exists with respect to publicly-traded partnerships of which 90% or more of the gross income for every taxable

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 are:


	(a) Neither we nor the Operating Partnership will elect to be treated as a corporation; and

	(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.

If we fail to meet the Qualifying Income Exception, other than a failure which is determined by the IRS to be inadvertent and which is cured within a reasonable time after discovery, we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us. This contribution and liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.

If we were taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to the unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as either taxable dividend income, to the extent of our current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder’s tax basis in his common units, or taxable capital gain, after the unitholder’s tax basis in his common units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.

The discussion below is based on the conclusion that we will be classified as a partnership for federal income tax purposes.

Unitholders who have become limited partners of the Company will be treated as partners of the Company for federal income tax purposes. Also:


	(a) assignees who have executed and delivered transfer applications, and are awaiting admission as limited partners, and

	(b) unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their common units,

will be treated as partners of the Company for federal income tax purposes. As there is no direct authority addressing assignees of common units who are entitled to execute and deliver transfer applications and become entitled to direct the exercise of attendant rights, but who fail to execute and deliver transfer applications, the opinion of Vinson & Elkins L.L.P. does not extend to these persons. Furthermore, a purchaser or other transferee of common units who does not execute and deliver a transfer application may not receive some federal income tax information or reports furnished to record holders of common units unless the common units are held in a nominee or street name account and the nominee or broker has executed and delivered a transfer application for those common units.

A beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales.”

Income, gain, deductions or losses would not appear to be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore be fully taxable as ordinary income. We strongly recommend that prospective unitholders consult their own tax advisors with respect to their status as partners in the Company for federal income tax purposes.

Flow-through of Taxable Income. We will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether corresponding cash distributions are received by him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for our taxable year ending with or within his taxable year. Our taxable year ends on December 31.

Treatment of Distributions. Distributions by us to a unitholder generally will not be taxable to the unitholder for federal income tax purposes to the extent of his tax basis in his common units immediately before the distribution. Our cash distributions in excess of a unitholder’s tax basis generally will be considered to be gain from the sale or exchange of the common units, taxable in accordance with the rules described under “— Disposition of Common Units” below. Any reduction in a unitholder’s share of our liabilities for which no partner, including the general partner, bears the economic risk of loss, known as “nonrecourse liabilities,” will be treated as a distribution of cash to that unitholder. To the extent our distributions cause a unitholder’s “at risk” amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read “— Limitations on Deductibility of Losses.”

A decrease in a unitholder’s percentage interest in us because of our issuance of additional common units will decrease his share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his common units, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation recapture, and/or substantially appreciated “inventory items,” both as defined in the Internal Revenue Code, and collectively, “Section 751 Assets.” To that extent, he will be treated as having been distributed his proportionate share of the Section 751 Assets and having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder’s realization of ordinary income. That income will equal the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder’s tax basis for the share of Section 751 Assets deemed relinquished in the exchange.

Basis of Common Units. A unitholder’s initial tax basis for his common units will be the amount he paid for the common units plus his share of our nonrecourse liabilities. That basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That basis will be decreased, but not below zero, by distributions from us, by the unitholder’s share of our losses, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will have no share of our debt which is

Limitations on Deductibility of Losses. The deduction by a unitholder of his share of our losses will be limited to the tax basis in his units and, in the case of an individual unitholder or a corporate unitholder, if more than 50% of the value of the corporate unitholder’s stock is owned directly or indirectly by five or fewer individuals or some tax-exempt organizations, to the amount for which the unitholder is considered to be “at risk” with respect to our activities, if that is less than his tax basis. A unitholder must recapture losses deducted in previous years to the extent that distributions cause his at risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable to the extent that his tax basis or at risk amount, whichever is the limiting factor, is subsequently increased. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at risk limitation but may not be offset by losses suspended by the basis limitation. Any excess loss above that gain previously suspended by the at risk or basis limitations is no longer utilizable.

In general, a unitholder will be at risk to the extent of the tax basis of his units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for repayment. A unitholder’s at risk amount will increase or decrease as the tax basis of the unitholder’s units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.

The passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from passive activities, which are generally corporate or partnership activities in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. The passive loss limitations are applied separately with respect to each publicly-traded partnership. Consequently, any passive losses we generate will be available to offset only our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or investments in other publicly-traded partnerships, or salary or active business income. Passive losses that are not deductible because they exceed a unitholder’s share of income we generate may be deducted in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive activity loss rules are applied after other applicable limitations on deductions, including the at risk rules and the basis limitation.

A unitholder’s share of our net income may be offset by any suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly-traded partnerships.

Limitations on Interest Deductions. The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:


	•	interest on indebtedness properly allocable to property held for investment;

	•	our interest expense attributed to portfolio income; and

	•	the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment. The IRS has indicated that net passive income earned by a publicly-traded partnership will be treated as

Entity-Level Collections. If we are required or elect under applicable law to pay any federal, state or local income tax on behalf of any unitholder or the general partner or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the partner on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend the partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under the partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual partner in which event the partner would be required to file a claim in order to obtain a credit or refund.

Allocation of Income, Gain, Loss and Deduction. In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among the general partner and the unitholders in accordance with their percentage interests in us. At any time that distributions are made to the common units in excess of distributions to the subordinated units, or incentive distributions are made to the general partner, gross income will be allocated to the recipients to the extent of these distributions. If we have a net loss for the entire year, that loss will be allocated first to the general partner and the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts and, second, to the general partner.

Specified items of our income, gain, loss and deduction will be allocated to account for the difference between the tax basis and fair market value of property contributed to us by the general partner and its affiliates, referred to in this discussion as “Contributed Property.” The effect of these allocations to a unitholder purchasing common units in this offering will be essentially the same as if the tax basis of our assets were equal to their fair market value at the time of an offering. In addition, items of recapture income will be allocated to the extent possible to the partner who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by some unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner to eliminate the negative balance as quickly as possible.

An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Internal Revenue Code to eliminate the difference between a partner’s “book” capital account, credited with the fair market value of Contributed Property, and “tax” capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the “Book-Tax Disparity”, will generally be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction only if the allocation has substantial economic effect. In any other case, a partner’s share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including his relative contributions to us, the interests of all the partners in profits and losses, the interest of all the partners in cash flow and other nonliquidating distributions and rights of all the partners to distributions of capital upon liquidation.

Vinson & Elkins L.L.P. is of the opinion that, with the exception of the issues described in “— Tax Consequences of Unit Ownership — Section 754 Election” and “— Disposition of Common Units — Allocations Between Transferors and Transferees,” allocations under our partnership agreement will be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction.

Treatment of Short Sales. A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be a partner for those


	•	any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;

	•	any cash distributions received by the unitholder as to those units would be fully taxable; and

	•	all of these distributions would appear to be ordinary income.

Counsel has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller should modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units. The IRS has announced that it is actively studying issues relating to the tax treatment of short sales of partnership interests. Please also read “— Disposition of Common Units — Recognition of Gain or Loss.”

Alternative Minimum Tax. Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for noncorporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. We strongly recommend that prospective unitholders consult with their tax advisors as to the impact of an investment in units on their liability for the alternative minimum tax.

Tax Rates. In general the highest effective United States federal income tax rate for individuals currently is 38.6% and the maximum United States federal income tax rate for net capital gains of an individual currently is 20% if the asset disposed of was held for more than 12 months at the time of disposition.

Section 754 Election. We have made the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS. The election generally permits us to adjust a common unit purchaser’s tax basis in our assets (“inside basis”) under Section 743(b) of the Internal Revenue Code to reflect his purchase price. This election does not apply to a person who purchases common units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other unitholders. For purposes of this discussion, a unitholder’s inside basis in our assets will be considered to have two components: (1) his share of our tax basis in our assets (“common basis”) and (2) his Section 743(b) adjustment to that basis.

Treasury regulations under Section 743 of the Internal Revenue Code require that, if the remedial allocation method is adopted (which we have adopted), a portion of the Section 743(b) adjustment attributable to recovery property be depreciated over the remaining cost recovery period for the Section 704(c) built-in gain. Under Treasury regulation Section 1.167(c)-l(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Internal Revenue Code rather than cost recovery deductions under Section 168 is generally required to be depreciated using either the straight-line method or the 150% declining balance method. Under our partnership agreement, our general partner is authorized to take a position to preserve the uniformity of units even if that position is not consistent with these Treasury Regulations. Please read “— Tax Treatment of Operations — Uniformity of Units.”

Although Vinson & Elkins L.L.P. is unable to opine as to the validity of this approach because there is no clear authority on this issue, we intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the common basis of the property, or treat that portion as non-amortizable to the extent attributable to property the common basis of which is not amortizable. This method is consistent with the regulations under Section 743 but is arguably inconsistent with Treasury regulation Section 1.167(c)-1(a)(6). To the extent this Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation

A Section 754 election is advantageous if the transferee’s tax basis in his units is higher than the units’ share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation and depletion deductions and his share of any gain or loss on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in his units is lower than those units’ share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment allocated by us to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.

Accounting Method and Taxable Year. We use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than one year of our income, gain, loss and deduction. Please read “— Disposition of Common Units — Allocations Between Transferors and Transferees.”

Initial Tax Basis, Depreciation and Amortization. The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to an offering will be borne by our general partner, its affiliates and our unitholders as of that time. Please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction.”

To the extent allowable, we may elect to use the depreciation and cost recovery methods that will result in the largest deductions being taken in the early years after assets are placed in service. We are not entitled to any amortization deductions with respect to any goodwill conveyed to us on formation. Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal Revenue Code.

If we dispose of depreciable property by sale, foreclosure, or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a partner who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all, of those deductions as ordinary income upon a sale of his interest in us.

The costs incurred in selling our units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us. The underwriting discounts and commissions we incur will be treated as a syndication cost.

Valuation and Tax Basis of Our Properties. The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the initial tax bases, of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Recognition of Gain or Loss. Gain or loss will be recognized on a sale of units equal to the difference between the amount realized and the unitholder’s tax basis for the units sold. A unitholder’s amount realized will be measured by the sum of the cash or the fair market value of other property received by him plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

Prior distributions from us in excess of cumulative net taxable income for a common unit that decreased a unitholder’s tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than the unitholder’s tax basis in that common unit, even if the price received is less than his original cost.

Except as noted below, gain or loss recognized by a unitholder, other than a “dealer” in units, on the sale or exchange of a unit held for more than one year will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held more than 12 months will generally be taxed at a maximum rate of 20%. A portion of this gain or loss, which will likely be substantial, however, will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to depreciation recapture or other “unrealized receivables” or to “inventory items” we own. The term “unrealized receivables” includes potential recapture items, including depreciation recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized upon the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Net capital loss may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gain in the case of corporations.

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method. Although the ruling is unclear as to how the holding period of these interests is determined once they are combined, recently finalized Treasury regulations under Section 1223 of the Internal Revenue Code allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred. Thus, according to the ruling, a common unitholder will be unable to select high or low basis common units to sell as would be the case with corporate stock, but, according to the Treasury regulations, may designate specific common units sold for purposes of determining the holding period of units transferred. A unitholder

Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:


	•	a short sale;

	•	an offsetting notional principal contract; or

	•	a futures or forward contract with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Allocations Between Transferors and Transferees. In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month (the “Allocation Date”). However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

The use of this method may not be permitted under existing Treasury Regulations. Accordingly, Vinson & Elkins L.L.P. is unable to opine on the validity of this method of allocating income and deductions between unitholders. If this method is not allowed under the Treasury regulations, or only applies to transfers of less than all of the unitholder’s interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between unitholders, as well as among unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury regulations.

A unitholder who owns units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deductions attributable to that quarter but will not be entitled to receive that cash distribution.

Notification Requirements. A unitholder who sells or exchanges units is required to notify us in writing of that sale or exchange within 30 days after the sale or exchange. We are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale or exchange through a broker. Failure to satisfy these reporting obligations may lead to the imposition of substantial penalties.

Constructive Termination. We will be considered to have been terminated for tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a 12-month period. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than 12 months of our taxable income or loss being includable in his taxable income for the year of termination. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Internal Revenue Code, and a termination would result in a deferral of

Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6). Any non-uniformity could have a negative impact on the value of the units. Please read “— Tax Consequences of Unit Ownership — Section 754 Election.”

We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the common basis of that property, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the regulations under Section 743, even though that position may be inconsistent with Treasury regulation Section 1.167(c)-1(a)(6). Please read “— Tax Consequences of Unit Ownership — Section 754 Election.” To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury regulations and legislative history. If we determine that this position cannot reasonably be taken, we may adopt a depreciation and amortization position under which all purchasers acquiring units in the same month would receive depreciation and amortization deductions, whether attributable to a common basis or Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our property. If this position is adopted, it may result in lower annual depreciation and amortization deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable. This position will not be adopted if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material adverse effect on the unitholders. The IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased without the benefit of additional deductions. Please read “— Disposition of Common Units — Recognition of Gain or Loss.”

Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations, other foreign persons and regulated investment companies raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them.

Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to them.

A regulated investment company or “mutual fund” is required to derive 90% or more of its gross income from interest, dividends and gains from the sale of stocks or securities or foreign currency or specified related sources. It is not anticipated that any significant amount of our gross income will include that type of income.

Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the United States because of the ownership of units. As a consequence they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Under rules applicable to publicly traded

In addition, because a foreign corporation that owns units will be treated as engaged in a United States trade or business, that corporation may be subject to the United States branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in the foreign corporation’s “U.S. net equity,” which are effectively connected with the conduct of a United States trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.

Under a ruling of the IRS, a foreign unitholder who sells or otherwise disposes of a unit will be subject to federal income tax on gain realized on the sale or disposition of that unit to the extent that this gain is effectively connected with a United States trade or business of the foreign unitholder. Apart from the ruling, a foreign unitholder will not be taxed or subject to withholding upon the sale or disposition of a unit if he has owned less than 5% in value of the units during the five-year period ending on the date of the disposition and if the units are regularly traded on an established securities market at the time of the sale or disposition.

Information Returns and Audit Procedures. We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine his share of income, gain, loss and deduction. We cannot assure you that those positions will yield a result that conforms to the requirements of the Internal Revenue Code, Treasury regulations or administrative interpretations of the IRS. Neither we nor counsel can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability, and possibly may result in an audit of his own return. Any audit of a unitholder’s return could result in adjustments not related to our returns as well as those related to our returns.

Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the “Tax Matters Partner” for these purposes. The partnership agreement names our general partner as our Tax Matters Partner.

The Tax Matters Partner will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.

A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Nominee Reporting. Persons who hold an interest in us as a nominee for another person are required to furnish to us:


	(a) the name, address and taxpayer identification number of the beneficial owner and the nominee;

	(b) whether the beneficial owner is


	(1) a person that is not a United States person,

	(2) a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing, or

	(3) a tax-exempt entity;


	(c) the amount and description of units held, acquired or transferred for the beneficial owner; and

	(d) specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

Brokers and financial institutions are required to furnish additional information, including whether they are United States persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $50 per failure, up to a maximum of $100,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

Registration as a Tax Shelter. The Internal Revenue Code requires that “tax shelters” be registered with the Secretary of the Treasury. It is arguable that we are not subject to the registration requirement on the basis that we will not constitute a tax shelter. However, our general partner, as our principal organizer, has registered us as a tax shelter with the Secretary of Treasury because of the absence of assurance that we will not be subject to tax shelter registration and in light of the substantial penalties which might be imposed if registration is required and not undertaken.

Issuance of this registration number does not indicate that investment in us or the claimed tax benefits have been reviewed, examined or approved by the IRS.

We must supply our tax shelter registration number to unitholders, and a unitholder who sells or otherwise transfers a unit in a later transaction must furnish the registration number to the transferee. The penalty for failure of the transferor of a unit to furnish the registration number to the transferee is $100 for each failure. The unitholders must disclose our tax shelter registration number on Form 8271 to be attached to the tax return on which any deduction, loss or other benefit we generate is claimed or on which any of our income is included. A unitholder who fails to disclose the tax shelter registration number on his return, without reasonable cause for that failure, will be subject to a $250 penalty for each failure. Any penalties discussed are not deductible for federal income tax purposes.

Accuracy-related Penalties. An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

A substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000


	(1) for which there is, or was, “substantial authority,” or

	(2) as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.

More stringent rules apply to “tax shelters,” a term that in this context does not appear to include us. If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an “understatement” of income for which no “substantial authority” exists, we must disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns to avoid liability for this penalty.

A substantial valuation misstatement exists if the value of any property, or the adjusted basis of any property, claimed on a tax return is 200% or more of the amount determined to be the correct amount of the valuation or adjusted basis. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). If the valuation claimed on a return is 400% or more than the correct valuation, the penalty imposed increases to 40%.

In addition to federal income taxes, you will be subject to other taxes, including state and local income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us. You will be required to file state income tax returns and to pay state income taxes in some or all of the states in which we do business or own property and may be subject to penalties for failure to comply with those requirements. In some states, tax losses may not produce a tax benefit in the year incurred and also may not be available to offset income in subsequent taxable years. Some of the states may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the state. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the state, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld may be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read “— Tax Consequences of Unit Ownership — Entity-Level Collections.” Based on current law and our estimate of our future operations, our general partner anticipates that any amounts required to be withheld will not be material. We may also own property or do business in other states in the future.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent states and localities, of his investment in us. Accordingly, we strongly recommend that each prospective unitholder consult, and depend upon, his own tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state and local, as well as United States federal tax returns, that may be required of him. Vinson & Elkins L.L.P. has not rendered an opinion on the state or local tax consequences of an investment in us.

A description of the material federal income tax consequences of the acquisition, ownership and disposition of debt securities will be set forth in the prospectus supplement relating to the offering of debt securities.

In addition to covering our offering of securities, this Prospectus covers the offering for resale of an unspecified number of common units by selling unitholders. The applicable prospectus supplement will set forth, with respect to each selling unitholder:


	•	the name of the selling unitholder,

	•	the nature of any position, office or other materials relationship which the selling unitholder will have had within the prior three years with us or any of our predecessors or affiliates,

	•	the number of common units owned by the selling unitholders prior to the offering,

	•	the amount of common units to be offered for the selling unitholder’s account, and

	•	the amount and (if one percent or more) the percentage of the common units to be owned by the selling unitholders after completion of the offering.

We may sell the common units or debt securities directly, through agents, or to or through underwriters or dealers. Please read the prospectus supplement to find the terms of the common unit or debt securities offering including:


	•	the names of any underwriters, dealers or agents;

	•	the offering price;

	•	underwriting discounts;

	•	sales agents’ commissions;

	•	other forms of underwriter or agent compensation;

	•	discounts, concessions or commissions that underwriters may pass on to other dealers; and

	•	any exchange on which the common units or debt securities are listed.

We may change the offering price, underwriter discounts or concessions, or the price to dealers when necessary. Discounts or commissions received by underwriters or agents and any profits on the resale of common units or debt securities by them may constitute underwriting discounts and commissions under the Securities Act.

Unless we state otherwise in the prospectus supplement, underwriters will need to meet certain requirements before purchasing common units or debt securities. Agents will act on a “best efforts” basis during their appointment. We will also state the net proceeds from the sale in the prospectus supplement.

Any brokers or dealers that participate in the distribution of the common units or debt securities may be “underwriters” within the meaning of the Securities Act for such sales. Profits, commissions, discounts or concessions received by such broker or dealer may be underwriting discounts and commissions under the securities act.

When necessary, we may fix common unit or debt securities distribution using changeable, fixed prices, market prices at the time of sale, prices related to market prices, or negotiated prices.

We may, through agreements, indemnify underwriters, dealers or agents who participate in the distribution of the common units or debt securities against certain liabilities including liabilities under the Securities Act. We may also provide funds for payments such underwriters, dealers or agents may be required to make. Underwriters, dealers and agents, and their affiliates may transact with us and our affiliates in the ordinary course of their business.

Distribution of any common units to be offered by one or more of the selling unitholders may be effected from time to time in one or more transactions (which may involve block transactions) (1) on the New York Stock Exchange, (2) in the over-the-counter market, (3) in underwritten transactions; (4) in transactions otherwise than on the New York Stock Exchange or in the over-the-counter market or (5) in a combination of any of these transactions. The transactions may be effected by the selling unitholders at market prices prevailing at the time of sale, at prices related to the prevailing market prices, at negotiated prices or at fixed prices. The selling unitholders may offer their shares through underwriters, brokers, dealers or agents, who may receive compensation in the form of underwriting discounts, commissions or concessions from the selling unitholders and/or the purchasers of the shares for whom they act as agent. The selling unitholders may engage in short sales, short sales against the box, puts and calls and other transactions in our securities, or derivatives thereof, and may sell and deliver their common units in connection therewith. In addition, the selling unitholders may from time to time sell their common units in transactions permitted by Rule 144 under the Securities Act.

As of the date of this prospectus, we have not engaged any underwriter, broker, dealer or agent in connection with the distribution of common units pursuant to this prospectus by the selling unitholders. To the extent required, the number of common units to be sold, the purchase price, the name of any applicable agent, broker, dealer or underwriter and any applicable commissions with respect to a particular offer will be set forth in the applicable prospectus supplement. The aggregate net proceeds to the selling unitholders from the sale of their common units offered hereby will be the sale price of those shares, less any commissions, if any, and other expenses of issuance and distribution not borne by us.

The selling unitholders and any brokers, dealers, agents or underwriters that participate with the selling unitholders in the distribution of shares may be deemed to be “underwriters” within the meaning of the Securities Act, in which event any discounts, concessions and commissions received by such brokers, dealers, agents or underwriters and any profit on the resale of the shares purchased by them may be deemed to be underwriting discounts and commissions under the Securities Act.

The applicable prospectus supplement will set forth the extent to which we will have agreed to bear fees and expenses of the selling unitholders in connection with the registration of the common units being offered hereby by them. We may, if so indicated in the applicable prospectus supplement, agree to indemnify selling unitholders against certain civil liabilities, including liabilities under the Securities Act.

Enterprise Products Partners L.P. and Enterprise Products Operating L.P. file combined annual, quarterly and current reports, and other information with the Commission under the Securities Exchange Act of 1934, as amended (the “Securities Exchange Act”). You may read and copy any document we file at the Commission’s public reference room at 450 Fifth Street, N.W., Washington, D.C. 20549. Please call the Commission at 1-800-732-0330 for further information on the public reference room. Our filings are also available to the public at the Commission’s web site at http://www.sec.gov. In addition, documents filed by us can be inspected at the offices of the New York Stock Exchange, Inc. 20 Broad Street, New York, New York 10002.

The Commission allows us to incorporate by reference into this 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 part of this prospectus and later information that we file with the Commission will automatically update and supersede this information. Therefore, before you decide to invest in a particular offering under this shelf registration, you should always check for reports we may have filed with the Commission after the date of this prospectus. We incorporate by reference the documents listed below filed by Enterprise Products Partners L.P. and Enterprise Products Operating L.P. and any future filings


	•	Annual Report on Form 10-K for the fiscal year ended December 31, 2002, Commission File Nos. 1-14323 and 333-93239-01;

	•	Current Report on Form 8-K filed with the Commission on January 10, 2003, Commission File Nos. 1-14323 and 333-93239-01; and

	•	the description of the common units contained in the Registration Statement on Form 8-A, initially filed with the Commission on July 21, 1998, and any subsequent amendment thereto filed for the purposes of updating such description.

We will provide without charge to each person, including any beneficial owner, to whom this prospectus is delivered, upon written or oral request, a copy of any document incorporated by reference in this prospectus, other than exhibits to any such document not specifically described above. Requests for such documents should be directed to Investor Relations, Enterprise Products Partners L.P., 2727 North Loop West, Suite 700, Houston, Texas 77008-1038; telephone number: (713) 880-6812.

We intend to furnish or make available to our unitholders within 90 days (or such shorter period as the Commission may prescribe) following the close of our fiscal year end annual reports containing audited financial statements prepared in accordance with generally accepted accounting principles and furnish or make available within 45 days (or such shorter period as the Commission may prescribe) following the close of each fiscal quarter quarterly reports containing unaudited interim financial information, including the information required by Form 10-Q, for the first three fiscal quarters of each of our fiscal years. Our annual report will include a description of any transactions with our general partner or its affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to our general partner or its affiliates for the fiscal year completed, including the amount paid or accrued to each recipient and the services performed.

This prospectus and the documents incorporated by reference contain various forward-looking statements and information that are based on our beliefs and those of our general partner, as well as assumptions made by us and information currently available to us. When used in this prospectus, words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “intend,” “could,” “believe,” “may” and similar expressions and statements regarding our plans and objectives for future operations, are intended to identify forward-looking statements. Although we and our general partner believe that such expectations reflected in such forward-looking statements are reasonable, neither we nor our general partner can give any assurances that such expectations will prove to be correct. Such statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected.

You should not put undue reliance on any forward-looking statements. When considering forward-looking statements, please review the risk factors described under “Risk Factors” in this prospectus and in any prospectus supplement.

Vinson & Elkins L.L.P., our counsel, will issue an opinion for us about the legality of the common units and debt securities and the material federal income tax considerations regarding the common units. Any underwriter will be advised about other issues relating to any offering by their own legal counsel.

The (i) consolidated financial statements and the related consolidated financial statement schedules of Enterprise Products Partners L.P. and of Enterprise Products Operating L.P. and subsidiaries as of


	Per Common Unit		Total

Public Offering Price	$	20.2000	$	303,000,000
Underwriting Discount(1)	$	0.8585	$	11,373,837
Proceeds to Enterprise Products Partners (before expenses)	$	19.3415	$	291,626,163



						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 August 4, 2004)		22.89		20.20		—			—		—


						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			494.9
		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			4,139.9
Minority interest				88.5			90.3			90.3			90.3
Partners’ equity:
	Common units			1,576.6			4,401.6			4,916.1			5,207.1
	Class B special units			99.6			134.9			—			—
	General partner			34.2			92.6			100.4			106.3
	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			5,323.9

		Total capitalization	$	4,020.3		$	9,519.8		$	9,554.1		$	9,554.1


	Capacity
Plant Name	(MMcf/d)

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


		Number of
Name of Underwriters		Common Units

Citigroup Global Markets Inc.			3,450,000
Morgan Stanley & Co. Incorporated			3,450,000
Lehman Brothers Inc.			1,425,000
Sanders Morris Harris Inc.			1,350,000
UBS Securities LLC			1,275,000
Wachovia Capital Markets, LLC			1,275,000
A.G. Edwards & Sons, Inc.			975,000
Merrill Lynch, Pierce, Fenner & Smith Incorporated			750,000
RBC Capital Markets Corporation			600,000
J.P. Morgan Securities Inc.			225,000
KeyBanc Capital Markets, a Division of McDonald Investments Inc.			225,000

	Total		15,000,000


	Page

Prospectus Supplement
Summary		S-1
Risk Factors		S-26
Use of Proceeds		S-42
Price Range of Common Units and Distributions		S-43
Capitalization		S-44
Business and Properties		S-46
Management		S-51
Tax Consequences		S-55
Underwriting		S-57
Incorporation of Documents by Reference		S-61
Legal Matters		S-61
Experts		S-61
Index to Unaudited Pro Forma Financial Statements		F-1
Prospectus
About This Prospectus		iii
Our Company		1
Risk Factors		2
Use of Proceeds		10
Ratio of Earnings to Fixed Charges		10
Description of Debt Securities		11
Description of Our Common Units		25
Cash Distribution Policy		27
Description of Our Partnership Agreement		34
Tax Consequences		39
Selling Unitholders		52
Plan of Distribution		52
Where You Can Find More Information		53
Forward-Looking Statements		54
Legal Matters		54
Experts		54


	•	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.


	•	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.


	•	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;


	•	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.


(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.


(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.


(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 974,400 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.


	•	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


	•	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.


Citigroup	Morgan Stanley


	UBS Investment Bank


	Wachovia Securities


	Sanders Morris Harris


	•	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.


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


	•	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.


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


	*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.*


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


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


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


	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 will face competition from third parties in its midstream businesses.*


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


	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 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 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 operating cash flows from its capital projects may not be immediate.*


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


	*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.*


	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.


	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.