Edgar Filing: ENTERPRISE PRODUCTS PARTNERS L P

e424b3

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

Filed Pursuant to Rule 424(b)(3)

Registration No. 333-102778

333-102778-01

SUBJECT TO COMPLETION, DATED FEBRUARY 7, 2005

PRELIMINARY PROSPECTUS SUPPLEMENT

(To Prospectus Dated April 21, 2003)

(ENTERPRISE PRODUCTS PARTNERS L.P. LOGO)

10,000,000 Common Units

Enterprise Products Partners L.P.

$ per common unit

We are selling 10,000,000 common units representing limited partner interests in Enterprise Products Partners L.P. 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 February 3, 2005 was $27.28 per common unit.

Investing in our common units involves risk. See “Risk Factors” beginning on page S-19 of this prospectus supplement and on page 2 of the accompanying prospectus.

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


	Per Common Unit	Total

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

We have granted the underwriters a 30-day option to purchase up to 1,500,000 additional common units to cover over-allotments.

The underwriters expect to deliver the common units on or about , 2005.

Joint Book-Running Managers


UBS Investment Bank	Citigroup

Goldman, Sachs & Co.


	Lehman Brothers


	Morgan Stanley


	Wachovia Securities


	A.G. Edwards


	Merrill Lynch & Co.


	Raymond James


	Sanders Morris Harris


	RBC Capital Markets


	KeyBanc Capital Markets

, 2005

[ENTERPRISE PRODUCTS PARTNERS SYSTEM MAP, GULFTERRA SYSTEM MAP

AND COMBINED COMPANY SYSTEM MAP APPEAR HERE]

This document is in two parts. The first part is this prospectus supplement, which describes the terms of this offering of common units. The second part is the accompanying prospectus, which gives more general information, some of which may not apply to this offering of our common units. If the information 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.

TABLE OF CONTENTS


	Page

Prospectus Supplement
Summary		S-1
Risk Factors		S-19
Use of Proceeds		S-28
Price Range of Common Units and Distributions		S-29
Capitalization		S-30
Business and Properties		S-32
Management		S-34
Tax Consequences		S-38
Underwriting		S-39
Legal Matters		S-42
Experts		S-42
Incorporation of Documents by Reference		S-43
Forward-Looking Statements		S-44
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

SUMMARY

This summary highlights information from this prospectus supplement and the accompanying prospectus to help you understand our business and 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-19 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, unless otherwise indicated. 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 to Enterprise Products Partners L.P. and its wholly owned subsidiaries. “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.

Unless otherwise indicated, pro forma financial results presented in this prospectus supplement give effect to the completion of the merger-related and other transactions described in the unaudited pro forma consolidated financial statements included elsewhere in this prospectus supplement, and pro forma as adjusted financial results presented in this prospectus supplement also give effect to 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 the unaudited pro forma consolidated 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, natural gas liquids, or NGLs, and crude oil, and we are an industry leader in the development of midstream infrastructure in the deepwater trend of the Gulf of Mexico. We have the only integrated North American midstream network, which includes natural gas transportation, gathering, processing and storage; NGL fractionation (or separation), transportation, storage and import and export terminaling; and crude oil transportation and offshore production platform services. Our midstream network links producers of natural gas, NGLs and crude oil from the largest supply basins in the United States, Canada and the Gulf of Mexico with the largest consumers and international markets. 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. We provide integrated services to our customers and generate fee-based cash flow from multiple sources along our midstream energy “value chain.”

We and our affiliates have completed several significant transactions related to our merger with GulfTerra, which closed on September 30, 2004, including:


	•	Our purchase of a 50% interest in GulfTerra’s general partner for $425 million on December 15, 2003;

	•	Prior to the merger, the contribution of El Paso Corporation’s remaining 50% interest in GulfTerra’s general partner to our general partner in exchange for a 9.9% interest in our general partner and $370 million in cash, and the subsequent contribution by our general partner of that 50% interest to us without consideration; and

	•	Our acquisition of certain midstream assets in South Texas related to GulfTerra’s business for approximately $156 million on September 30, 2004, but effective September 1, 2004.

Affiliates of our general partner acquired El Paso Corporation’s 9.9% interest in our general partner and approximately 13.5 million of our common units for approximately $425 million on January 14, 2005. El Paso

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Corporation and its affiliates no longer own any interest in us or our general partner as a result of this transaction.

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 $425.3 million and income from continuing operations of $112.5 million. For the nine months ended September 30, 2004, we had revenues of $5.5 billion, operating income of $247.7 million and net income of $152.9 million. On a pro forma basis for the nine months ended September 30, 2004, we had revenues of $6.8 billion, operating income of $424.3 million and income from continuing operations of $223.3 million. We recently announced unaudited results for the year ended December 31, 2004. For this period, we had revenues of $8.3 billion, operating income of $423.0 million and net income of $268.3 million. Please read “— Summary Historical and Pro Forma Financial and Operating Data” and our unaudited pro forma financial statements beginning on page F-1 of this prospectus supplement for a description of the transactions we have included in our pro forma presentation and “— Recent Developments — Fourth Quarter and Fiscal Year 2004 Unaudited Results” for additional summarized financial information.

Our Business Segments

As a result of the GulfTerra merger and related transactions, we have reorganized our business activities into four reportable business segments: (i) Offshore Pipelines & Services, (ii) Onshore Natural Gas Pipelines & Services, (iii) NGL Pipelines & Services, and (iv) Petrochemical Services, which are generally organized and managed along our midstream energy value chain according to the type of services rendered and products produced and sold.

Offshore Pipelines & Services. Our Offshore Pipelines & Services segment consists of (i) approximately 1,390 miles of natural gas pipelines strategically located to serve production activities in some of the most active drilling and development regions in the Gulf of Mexico, (ii) ownership interests in Gulf of Mexico offshore oil pipeline systems aggregating approximately 800 miles, which includes the recently constructed 390-mile Cameron Highway oil pipeline, and (iii) ownership interests in seven multi-purpose offshore hub platforms located in the Gulf of Mexico.

Onshore Natural Gas Pipelines & Services. Our Onshore Natural Gas Pipelines & Services segment includes natural gas pipeline systems aggregating approximately 17,180 miles that provide for the gathering and transmission of natural gas in Alabama, Colorado, Louisiana, Mississippi, New Mexico and Texas. Included in this segment are two salt dome natural gas storage facilities located in Mississippi, which are strategically located to serve the Northeast, Mid-Atlantic and Southeast natural gas markets. We also lease natural gas storage facilities located in Texas and Louisiana.

NGL Pipelines & Services. Our NGL Pipelines & Services segment is comprised of (i) our natural gas processing business and related NGL marketing activities, (ii) NGL pipelines aggregating approximately 12,600 miles and related storage facilities, which include our strategic Mid-America and Seminole NGL pipeline systems and (iii) NGL fractionation facilities located in Texas and Louisiana. This segment also includes our NGL import and export terminaling operations. We also lease two NGL storage facilities located in Texas.

Petrochemical Services. Our Petrochemical Services segment includes our four propylene fractionation facilities, isomerization complex, and octane additive production facility. This segment also includes approximately 460 miles of various propylene pipeline systems and a 70-mile hi-purity isobutane pipeline.

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Our Business Strategy

Our business strategy is to:


	•	capitalize on expected increases in natural gas, NGL and oil production resulting from development activities in the deepwater and continental shelf areas of the Gulf of Mexico and in the Rocky Mountain region;

	•	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

We believe we have the following competitive strengths:

Large-Scale, Integrated Network of Diversified Assets in Strategic Locations. We have the only integrated natural gas and NGL transportation, fractionation, processing, storage and import/export network in North America. Our operations are 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 our location in these markets provides better access to natural gas, NGL and petrochemical supply volumes, anticipated demand growth and business expansion opportunities. The GulfTerra merger has resulted in a more balanced, diversified company with access to new geographic areas, such as the San Juan and Permian Basins. We believe that the larger scope and scale of the combined company should result in greater operating strength and promote long-term unitholder value.

Cash-Flow Stability Through Fee-Based Businesses and Balanced Asset Mix. Our cash flow is derived primarily from fee-based businesses which are not directly affected by volatility in energy commodity prices. We expect that our more diversified asset portfolio resulting from the GulfTerra merger should provide operating income from a broader range of sources than our operations on a stand-alone basis prior to the merger. GulfTerra’s historical operations generally benefitted from strong or average hydrocarbon prices, while our historical operations prior to the merger generally benefitted from stable or lower hydrocarbon prices. This relationship results in a natural hedge to natural gas prices that should provide greater cash flow stability to the combined company.

Relationships with Major Oil, Natural Gas and Petrochemical Companies. We have long-term relationships with many of our suppliers and customers, and we believe that we will continue to benefit from these relationships. We jointly own facilities with many of our customers who either provide raw materials to or consume the end products from our 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.

Strategic Platform for Continued Expansion. We believe that the GulfTerra merger has strengthened our leading business positions across the midstream energy value chain in some of the largest producing basins in North America. We have a significant portfolio of organic growth opportunities to construct new facilities or expand existing assets. To date, we have identified approximately $2 billion of organic growth projects over the next three years, including our recently announced Independence Trail and Independence Hub projects and the Constitution oil and natural gas pipeline projects in the deepwater areas of the Gulf of Mexico; the expansion of some of our key western NGL assets to support new production in the Rocky Mountain and San Juan regions; and enhancements to some of our existing facilities on the Texas Gulf Coast to serve our refining and petrochemical customers.

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Lower Cost of Capital. We believe that our general partner’s maximum incentive distribution level of 25% (as compared to 50% for many publicly traded master limited partnerships) combined with our investment grade credit profile provides us with a lower cost of capital than many of our competitors, enabling us to compete more effectively in acquiring assets and expanding our asset base. We also believe that the larger scope and scale of the combined company should provide us with greater access to capital.

Experienced Operator and Management Team. We 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. Affiliates of Dan L. Duncan, our co-founder and the chairman of our general partner, own a 100% membership interest in our general partner. In addition, following this offering Mr. Duncan and his affiliates collectively will own an approximate 37.3% limited partner interest in us. The officers of our general partner average more than 25 years of industry experience.

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Ownership Structure and Management

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

(GRAPH)

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



						Ownership After
		Current Ownership				the Offering

				Percentage				Percentage
		Units		Interest		Units		Interest

Public common units			185,621,528		49.9%		195,621,528		51.1%
EPCO common units			142,592,215		38.3%		142,592,215		37.3%
Shell common units			36,572,122		9.8%		36,572,122		9.6%
General partner interest			—		2.0%		—		2.0%

	Total		364,785,865		100.0%		374,785,865		100.0%

Information regarding our management is set forth under “Management” beginning on page S-34 of this prospectus supplement. Our principal executive offices are located at 2727 North Loop West, Houston, Texas 77008, and our telephone number is (713) 880-6500.

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The Offering


Common units offered		10,000,000 common units; or

		11,500,000 common units if the underwriters exercise their over-allotment option in full.

Units outstanding after this offering		374,785,865 common units, or 376,285,865 common units if the underwriters exercise their over-allotment option in full.

Use of proceeds		We will use the net proceeds from this offering, including our general partner’s proportionate capital contribution, to permanently reduce borrowings and commitments outstanding under our 364-day acquisition revolving credit facility. Any remaining proceeds will be used for general partnership purposes, which may include acquisitions or the temporary reduction of amounts borrowed under our multi-year revolving credit facility. The net proceeds from any exercise of the underwriters’ over-allotment option will be used in a similar manner.

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 November 5, 2004, we paid a quarterly cash distribution for the third quarter of 2004 of $0.3950 per common unit, or $1.58 per unit on an annualized basis. On January 19, 2005, our general partner increased our quarterly cash distribution to $0.40 per common unit, or $1.60 per common unit on an annualized basis, beginning with cash distributions with respect to the fourth quarter of 2004. The distribution with respect to the fourth quarter of 2004 will be paid on February 14, 2005 to unitholders of record on January 31, 2005. The 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.

Estimated ratio of taxable income to distributions		We estimate that if you own the common units you purchase in this offering through December 31, 2007, you will be allocated, on a cumulative basis, an amount of federal taxable income for the taxable years 2005 through 2007 that will be less than 10% of the cash distributed with respect to that period. Please read “Tax Consequences” in this prospectus supplement and the accompanying prospectus for the basis of this estimate.

New York Stock Exchange symbol		EPD

Risk Factors		There are risks associated with this offering and our business. You should consider carefully the risk factors beginning on page S-19 of this prospectus supplement and beginning on page 2 of the accompanying prospectus before making a decision to purchase common units in this offering.

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Recent Developments

Fourth Quarter and Fiscal Year 2004 Unaudited Results

The following table sets forth our summarized results of operations and selected volumetric operating data for the periods indicated (dollars in millions, except per unit amounts):



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

		2003			2004			2003			2004


		(Unaudited)									(Unaudited)
Income Statement Data:
Revenues		$	1,419.4		$	2,859.6		$	5,346.4		$	8,318.1
Costs and expenses			1,356.0			2,694.9			5,084.3			7,947.9
Equity in income (loss) of unconsolidated affiliates			2.7			10.6			(14.0	)		52.8

	Operating income		66.1			175.3			248.1			423.0
Other income (expense)			(31.8	)		(57.6	)		(134.4	)		(153.6	)
Provision for taxes			(0.6	)		(1.0	)		(5.3	)		(3.8	)
Minority interest			0.5			(1.3	)		(3.9	)		(8.1	)
Cumulative effect of changes in accounting principle			—			—			—			10.8

	Net income	$	34.2		$	115.4		$	104.5		$	268.3

Fully diluted earnings per unit		$	0.13		$	0.28		$	0.41		$	0.87

EBITDA		$	99.9		$	275.6		$	366.4		$	623.1

Gross operating margin by segment:
	Offshore Pipelines & Services	$	0.1		$	33.9		$	5.6		$	36.5
	Onshore Natural Gas Pipelines & Services		4.1			72.0			18.3			91.0
	NGL Pipelines & Services		80.1			142.5			310.6			374.2
	Petrochemical Services		24.7			30.8			75.9			121.5
	Other, non-segment results(1)		—			—			—			32.0

Total gross operating margin		$	109.0		$	279.2		$	410.4		$	655.2

Selected Volumetric Operating Data:(2)
Offshore Pipelines & Services, net:
	Natural gas transportation volumes in billion British thermal units (BBtus) per day(3)		378			1,828			433			2,081
	Crude oil transportation volumes (MBbls/d)		—			138			—			138
	Platform gas treating (Mdth/d)		—			306			—			306
	Platform oil treating (MBbls/d)		—			14			—			14
Onshore Natural Gas Pipelines & Services, net:
	Natural gas transportation volumes (BBtu/d)		627			5,621			600			5,638
NGL Pipelines & Services, net:
	NGL transportation volumes (MBbls/d)		1,281			1,390			1,275			1,411
	NGL fractionation volumes (MBbls/d)		241			304			227			307
	Equity NGL production (MBbls/d)		44			128			43			129
	Fee-based natural gas processing (MMcf/d)		324			1,844			194			1,692
Petrochemical Services, net:
	Butane isomerization volumes (MBbls/d)		70			85			77			76
	Propylene fractionation volumes (MBbls/d)		56			54			57			57
	Octane additive production volumes (MBbls/d)		7			13			4			10
	Petrochemical transportation volumes (MBbls/d)		75			69			68			71
Total, net:
	NGL, crude oil and petrochemical transportation volumes (MBbls/d)		1,356			1,597			1,343			1,620
	Natural gas transportation volumes (BBtu/d)		1,005			7,449			1033			7,719
	Equivalent transportation volumes (MBbls/d)(4)		1,621			3,557			1,615			3,651


(1)	The Other, non-segment category is presented for financial reporting purposes to show the historical equity earnings we received from GulfTerra’s general partner. Our investment in GulfTerra’s general partner was accounted for using the equity method until the GulfTerra merger and related transactions were completed on September 30, 2004. Since the historical equity earnings of GulfTerra’s general partner were based on net income amounts allocated to it by GulfTerra, it is impractical for us to allocate the equity income we received during the periods presented to each of our new segments. Therefore, we have segregated earnings from GulfTerra’s general partner apart from our other segments to aid in comparability between the periods presented and future periods.

(2)	Throughput rates reflect the periods that we owned the underlying businesses.

(3)	Excludes fourth quarter of 2004 volumes for Starfish, which is being disposed of.

(4)	Reflects equivalent energy volumes where 3.8 MMBtus of natural gas are equivalent to one barrel of NGLs.

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Please read “— Non-GAAP Financial Measures” and “— Non-GAAP Reconciliations” on pages S-15 through S-18 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.

Overview of Fourth Quarter and Fiscal Year 2004 Unaudited Results

We reported quarterly net income of $115.4 million, or $0.28 per unit on a fully diluted basis, for the fourth quarter of 2004 compared to $34.2 million, or $0.13 per unit, for the fourth quarter of 2003. For the fiscal year of 2004, we earned net income of $268.3 million, or $0.87 per unit, compared to $104.5 million, or $0.41 per unit, in 2003.

Revenue for the fourth quarter of 2004 increased by 101%, to approximately $2.9 billion compared to $1.4 billion for the fourth quarter of 2003. Operating income for the fourth quarter of 2004 increased by 165% to $175.3 million compared to $66.1 million for the fourth quarter of 2003. Gross operating margin increased by 156% to $279.2 million for the fourth quarter of 2004 from $109.0 million for the same quarter in 2003. Earnings before interest, taxes, depreciation and amortization, or EBITDA, increased by 176% to $275.6 million for the fourth quarter of 2004 from $99.9 million for the fourth quarter of 2003.

Review of Segment Performance

NGL Pipelines & Services. The NGL Pipelines & Services segment includes our NGL pipelines, storage facilities and fractionators and our natural gas processing plants and related NGL marketing activities. Gross operating margin for this segment increased by 78%, or $62.4 million, in the fourth quarter of 2004 to $142.5 million from $80.1 million in the same quarter in 2003.

Our natural gas processing and related businesses accounted for $75.1 million of gross operating margin for this segment in the fourth quarter of 2004 compared to $7.6 million in the fourth quarter of 2003. This increase was due to the contributions from the GulfTerra assets and nine processing plants acquired from El Paso Corporation in the third quarter of 2004 as well as improved performance from our legacy processing plants and NGL marketing business. The processing business benefited from favorable processing economics due to the continued strong demand for NGLs by the petrochemical and motor gasoline industries as a result of improvements in the U.S. and global economies.

Gross operating margin from the NGL pipelines and storage business was $52.0 million during the fourth quarter of 2004 versus $61.0 million in the fourth quarter of 2003. The Mid-America and Seminole pipelines accounted for $44.7 million of the gross operating margin for our NGL pipelines and storage business during the fourth quarter of 2004. This is a 24%, or $8.5 million, increase from the $36.2 million these pipelines earned during the same quarter of 2003. This increase was more than offset by a decrease in gross operating margin from export terminal services, reduced demand for certain Louisiana NGL pipelines, in part due to lower volumes resulting from the effects of Hurricane Ivan, and pipeline integrity expenses.

Total transportation volumes for the NGL pipeline business averaged 1,390 thousand barrels, or MBbls, per day for the fourth quarter of 2004 compared to 1,281 MBbls per day in the fourth quarter of 2003. Transportation volumes for the Mid-America and Seminole pipelines increased by 15%, or 120 MBbls per day, to 908 MBbls per day in the fourth quarter of 2004 from 788 MBbls per day in the same period of 2003.

Our NGL fractionation business earned gross operating margin of $15.3 million for the fourth quarter of 2004 compared to $11.5 million in the fourth quarter of 2003. NGL fractionation volumes for the fourth quarter of 2004 averaged 304 MBbls per day versus 241 MBbls per day in the fourth quarter of 2003.

Onshore Natural Gas Pipelines & Services. The Onshore Natural Gas Pipelines & Services segment includes our onshore natural gas pipelines and natural gas storage businesses. Gross operating margin for this segment for the fourth quarter of 2004 was $72.0 million compared to $4.1 million in the fourth quarter of 2003.

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Onshore natural gas pipelines generated $64.8 million of gross operating margin in the fourth quarter of 2004 versus $4.1 million in the fourth quarter of 2003. Onshore transportation volumes were 5.6 trillion British thermal units, or Tbtus, per day compared to 0.6 Tbtus per day in the fourth quarter of 2003. Natural gas storage services accounted for $7.2 million of gross operating margin in the fourth quarter of 2004. This combined $67.9 million increase for the segment was due to the contribution of the GulfTerra assets and increased margin and volume on the Acadian system.

Offshore Pipelines & Services. The Offshore Pipelines & Services segment includes our offshore natural gas and crude oil pipelines and platforms. Gross operating margin for this segment for the fourth quarter of 2004 was $33.9 million compared to $0.1 million in the fourth quarter of 2003.

Offshore natural gas pipelines recorded gross operating margin of $14.4 million on average throughput of 1.8 Tbtus per day in the fourth quarter of 2004 versus $0.1 million and 0.4 Tbtus per day, respectively, for the same quarter in 2003. Gross operating margin for our offshore platform services and production business was $13.6 million for the fourth quarter of 2004. Our offshore oil pipelines business recorded gross operating margin of $5.8 million in the fourth quarter of 2004 on net volumes of 138 MBbls per day. The increase for this segment was primarily attributable to the contribution from the GulfTerra assets.

Petrochemical Services. The Petrochemical Services segment includes the partnership’s butane isomerization, propylene fractionation and octane enhancement businesses including related pipeline facilities. Gross operating margin for this segment during the fourth quarter of 2004 increased by 25%, or $6.1 million, to $30.8 million from $24.7 million in the same quarter of 2003. Each of the three businesses in this segment reported an increase in gross operating margin.

Other Recent Developments


	Receipt of First Deliveries From Holstein and Mad Dog Fields in Deepwater Gulf of Mexico

In January 2005, we began receiving first deliveries of crude oil and natural gas from the Holstein and Mad Dog fields located in the Southern Green Canyon area of the deepwater Gulf of Mexico.

Initial oil production of approximately 35,000 barrels, or Bbls, per day from three deepwater wells has commenced flowing into our recently completed and jointly owned Cameron Highway Oil Pipeline System, a 390-mile 24-inch to 30-inch pipeline, which has the capacity to deliver up to 500,000 Bbls per day of crude oil from developments in the Gulf of Mexico to the major refining markets along the Texas Gulf Coast.

Cameron Highway is supported by life of lease dedications with BP, BHP Billiton and Unocal for their production from the Holstein, Mad Dog and Atlantis fields and with Kerr McGee for its production from the Constitution and Ticonderoga fields. Additionally, Cameron Highway has contracted with Shell under a term agreement to move its 50% share of production from the Holstein field.

Initial natural gas production of approximately 100 million cubic feet, or MMcf, per day from the Holstein field has commenced flowing into our 25.7% owned Manta Ray Offshore Gathering System and Nautilus Gas Pipeline. The 101-mile, 30-inch Nautilus Gas Pipeline system terminates onshore in St. Mary’s Parish Louisiana, where the natural gas is processed at our Neptune natural gas processing plant. The gathering, transportation and processing agreements with BP, BHP Billiton and Unocal include life of lease dedications for the Holstein, Mad Dog and Atlantis developments while Shell’s natural gas production from Holstein is gathered and transported under a life of lease dedication and processed under an existing 20-year contract.

The Holstein field began producing oil and natural gas in December 2004. First production from the Mad Dog field commenced in January 2005. The total combined design capacity of the Holstein, Mad Dog and Atlantis platforms is 400,000 Bbls per day and 340 MMcf per day, and the design capacity of the Constitution platform is 70,000 Bbls per day.

S-9


	Acquisition of Natural Gas Gathering and Processing Companies from El Paso

In January 2005, we acquired two subsidiaries of El Paso Corporation which own and operate a natural gas gathering system and natural gas cryogenic processing plant located in East Texas for $74.5 million. We received required regulatory approvals prior to closing. The companies we acquired own an 80% equity interest in three gathering systems located in Polk County, Texas, which represent a combined 89 miles of 2-inch to 12-inch pipeline system and a 75% equity interest in the Indian Springs gas processing facility located in Polk County, Texas. The Indian Springs processing plant has capacity to process up to 120 MMcf per day of natural gas. In addition, there is an idle 20 MMcf per day train available for restart to support an increase in gas volumes. The gas processed at the Indian Springs plant is sourced from the Polk County gas gathering systems, as well as our nearby Big Thicket gathering system. Additionally, the Indian Springs plant produces over 6,000 Bbls per day of NGLs that are currently fractionated at a facility in Mont Belvieu.


	Divestiture of Ownership Interest Related to Stingray Natural Gas Pipeline

In connection with the GulfTerra merger, we are required under a consent decree to sell our 50% interest in an entity which owns the Stingray natural gas pipeline and related gathering pipelines and dehydration and other facilities located in south Louisiana and the Gulf of Mexico offshore Louisiana. In January 2005, we entered into a contract with a third party to sell this investment for approximately $41.2 million. We expect this sale to close during the first quarter of 2005. The sale requires Federal Trade Commission approval under the terms of the consent decree relating to the GulfTerra merger and is subject to other customary closing conditions.


	Receipt of New Production Into Poseidon Oil Pipeline System

In January 2005, the Poseidon Oil Pipeline began receiving crude oil from the Front Runner and Tarantula fields located in the central Gulf of Mexico. We own a 36% interest in Poseidon Oil Pipeline Company, L.L.C., which owns and operates the Poseidon Oil Pipeline System that extends from the central Gulf of Mexico onshore into Southern Louisiana.

Poseidon constructed, owns and operates the Front Runner oil pipeline, a new 36-mile, 14-inch pipeline that connects the Front Runner field with Poseidon’s main pipeline at Ship Shoal Block 332. The Front Runner oil pipeline has the capacity to transport 65,000 Bbls of crude oil per day and can be expanded to transport up to 125,000 Bbls of crude oil per day.

The Front Runner field is located in 3,100 feet of water in the Green Canyon Blocks 338 and 339 in the Central Gulf of Mexico. The field is currently producing in excess of 10,000 Bbls per day of crude oil from the first of eight wells, and is expected to produce up to 60,000 Bbls per day of crude oil. The producers in the field have dedicated a total of 13 contiguous blocks in this area to Poseidon.

The Tarantula field is located in 480 feet of water in South Timbalier Block 308 and is connected to the Poseidon system by a new four-mile gathering pipeline owned by us. The field development consists of a fixed platform designed to initially handle 30,000 Bbls of crude oil per day and production from four wells.


	Acquisition of Additional Interest in Louisiana NGL Facilities

In December 2004, we purchased an additional 16.7% ownership interest in K/ D/ S Promix, L.L.C., or Promix, for $27.5 million in cash from Koch Hydrocarbon Southeast Inc. As a result of this purchase, our ownership interest in Promix increased to 50%.

Promix owns a fractionator located in Napoleonville, Louisiana, which has the capacity to fractionate up to 145,000 Bbls per day of NGLs from natural gas processing plants on the Louisiana, Mississippi and Alabama Gulf Coast. It also owns an NGL pipeline system that gathers mixed NGLs from natural gas processing plants in Louisiana, five NGL salt dome storage wells and a barge loading facility on the Gulf Coast of Louisiana. We are the operator of the Promix facilities. Promix provides a link between natural gas

S-10

processing plants on the Gulf Coast that remove NGLs from natural gas produced from deepwater developments and NGL consumers in Louisiana and, through our pipelines, markets in Texas.


	Agreement with Atwater Valley Producers Group for Deepwater Platform and Gas Pipeline

In November 2004, we entered into an agreement with the Atwater Valley Producers Group for the dedication, processing and gathering of natural gas and condensate production from six natural gas fields in the Atwater Valley, DeSoto Canyon and Lloyd Ridge areas of the deepwater Gulf of Mexico. We will design, construct, install and own Independence Hub, a 105-foot deep-draft, semi-submersible platform with a two-level production deck, which will be capable of processing 850 MMcf of gas per day. The platform, which is estimated to cost approximately $385 million, will be operated by Anadarko Petroleum Corp., and is designed to process production from the six anchor fields and has excess payload capacity to tie-back up to 10 additional fields. In December 2004, we entered into an agreement with Cal Dive International Inc., or Cal Dive, to sell them a 20% interest in one of our affiliates that owns the Independence Hub platform. Under the terms of the agreement, we will have access to Cal Dive’s fleet of vessels, which will assist us in the construction of the Independence Hub and the related export pipeline.

Independence Hub will be located on Mississippi Canyon block 920, in a water depth of 8,000 feet. This location was selected for the permanently anchored host facility based on favorable seafloor conditions and proximity to the identified anchor fields. First production is expected in 2007. Under the terms of the agreement, the development will include dedicated anchor fields in addition to future discoveries on surrounding undeveloped blocks. Additionally, we will own, install and operate 140 miles of 24-inch pipeline, with a capacity of approximately 850 MMcf of gas per day, named Independence Trail. The pipeline, which is estimated to cost approximately $280 million, will redeliver the production from Independence Hub into the Tennessee Gas Pipeline.

S-11

Summary Historical and Pro Forma Financial and Operating Data

The following tables set forth, for the periods and at the dates indicated, summary historical and pro forma financial and operating data for Enterprise. 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 nine-month periods ended September 30, 2003 and 2004 and balance sheet data at September 30, 2004 are derived from and should be read in conjunction with the unaudited financial statements of Enterprise that are incorporated by reference into this prospectus supplement.

Our summary unaudited pro forma financial and operating data gives effect to the following transactions:


	•	The completion of our merger with GulfTerra and the related transactions on September 30, 2004 (including our purchase of certain midstream assets located in South Texas, effective as of September 1, 2004).

	•	The issuance by our operating partnership of $2 billion of senior unsecured notes on October 4, 2004, and the application of the net proceeds therefrom to reduce debt amounts outstanding under our 364-day acquisition revolving credit facility that was used to fund a portion of the purchase price at the closing of the GulfTerra merger and related transactions on September 30, 2004.

	•	The completion on October 5, 2004 of our operating partnership’s four cash tender offers for $915 million in principal amount of GulfTerra’s senior and senior subordinated notes using $1.1 billion in cash borrowed under our 364-day acquisition revolving credit facility, which was placed in escrow on September 30, 2004.

	•	Our public offerings of common units in both May 2004 and August 2004, each consisting of 17,250,000 common units, and our issuance of a total of 5,183,591 common units in connection with our distribution reinvestment plan, or DRIP, during the first eleven months of 2004 (2,199,350 common units were issued in connection with the DRIP in November 2004).

	•	The conversion of the remaining outstanding 80 Series F2 convertible units, which were originally issued by GulfTerra, into an aggregate of 1,950,317 of our common units in October and November 2004.

Our summary unaudited pro forma as adjusted financial and operating data also gives effect to the sale of 10,000,000 of our common units to the public in this offering at an assumed offering price of $27.28 per unit and the application of the net proceeds as described in “Use of Proceeds.” Estimated net proceeds from this offering, including our general partner’s proportionate net capital contribution of $5.4 million, are $266.5 million after deducting applicable underwriting discounts, commissions and offering expenses of $11.9 million.

The unaudited pro forma financial and operating data for the year ended December 31, 2003 and for the nine months ended September 30, 2004 assume the pro forma transactions described above and this offering all occurred on January 1, 2003. The unaudited pro forma condensed consolidated balance sheet data shows the financial effects of the pro forma transactions described above and this offering as if they had occurred on September 30, 2004 (to the extent these transactions are not already recorded in our historical balance sheet).

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 supplemental sections titled “— Non-GAAP Financial Measures” and “— Non-GAAP Reconciliations,” we have provided the necessary explanations and reconciliations for Enterprise’s non-GAAP financial measures.

S-12

Summary Historical and Pro Forma Financial and Operating Data



				Consolidated Historical
													For Year Ended
													December 31, 2003
				For Year Ended December 31,
																Pro Forma
				2001			2002			2003			Pro Forma			as Adjusted


													(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
	Costs and expenses:
		Operating costs and expenses			2,862.6			3,382.8			5,046.8			6,633.1			6,633.1
		Selling, general and administrative			30.3			42.9			37.5			92.0			92.0

			Total costs and expenses		2,892.9			3,425.7			5,084.3			6,725.1			6,725.1

	Equity in income (loss) of unconsolidated affiliates				25.3			35.2			(14.0	)		(2.6	)		(2.6	)

	Operating income				286.8			194.3			248.1			425.3			425.3

	Other income (expense):
		Interest expense			(52.4	)		(101.6	)		(140.8	)		(321.1	)		(312.0	)
		Other, net			10.3			7.3			6.4			8.4			8.4

			Total other income (expense)		(42.1	)		(94.3	)		(134.4	)		(312.7	)		(303.6	)

	Income before provision for income taxes and minority interest				244.7			100.0			113.7			112.6			121.7
	Provision for income taxes				—			(1.6	)		(5.3	)		(5.3	)		(5.3	)

	Income before minority interest				244.7			98.4			108.4			107.3			116.4
	Minority interest				(2.5	)		(2.9	)		(3.9	)		(3.9	)		(3.9	)

	Income from continuing operations			$	242.2		$	95.5		$	104.5		$	103.4		$	112.5

	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		$	0.19		$	0.21

Diluted earnings per unit (net of general partner interest):
	Income from continuing operations per unit			$	1.39		$	0.48		$	0.41		$	0.19		$	0.20

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			$	277.6		$	326.8		$	419.6
	Cash flows used in investing activities				491.2			1,708.3			657.0
	Cash provided by financing activities				285.3			1,263.3			254.0
	Distributions received from unconsolidated affiliates				45.1			57.7			31.9
	Gross operating margin				375.9			332.3			410.4		$	887.3		$	887.3
	EBITDA				345.8			284.8			366.4			809.5			809.5
	Commodity hedging income (losses)				101.3			(51.3	)		(0.6	)

S-13

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



				Consolidated
				Historical


				For Nine Months						For Nine Months Ended
				Ended						September 30, 2004
				September 30,
													Pro Forma
				2003			2004			Pro Forma			as Adjusted


				(Unaudited)

				(Dollars in millions, except per unit amounts)
Income Statement Data:
	Revenues			$	3,927.0		$	5,458.5		$	6,752.4		$	6,752.4
	Costs and expenses:
		Operating costs and expenses			3,699.5			5,226.4			6,272.8			6,272.8
		Selling, general and administrative			28.9			26.6			73.1			73.1

			Total costs and expenses		3,728.4			5,253.0			6,345.9			6,345.9

	Equity in income (loss) of unconsolidated affiliates				(16.6	)		42.2			17.8			17.8

	Operating income				182.0			247.7			424.3			424.3

	Other income (expense):
		Interest expense			(107.7	)		(96.9	)		(202.5	)		(195.7	)
		Other, net			5.1			0.9			2.5			2.5

			Total other income (expense)		(102.6	)		(96.0	)		(200.0	)		(193.2	)

	Income before provision for income taxes, minority interest and change in accounting principle				79.4			151.7			224.3			231.1
	Provision for income taxes				(4.6	)		(2.7	)		(2.7	)		(2.7	)

	Income before minority interest and changes in accounting principles				74.8			149.0			221.6			228.4
	Minority interest				(4.4	)		(6.9	)		(5.1	)		(5.1	)

	Income from continuing operations				70.4			142.1		$	216.5		$	223.3

	Cumulative effect of change in accounting principle				—			10.8

	Net income			$	70.4		$	152.9

Basic earnings per unit (net of general partner interest):
	Income from continuing operations per unit			$	0.29		$	0.52		$	0.50		$	0.50

Diluted earnings per unit (net of general partner interest):
	Income from continuing operations per unit			$	0.28		$	0.52		$	0.50		$	0.50

Distributions to limited partners:
	Per common unit			$	1.10		$	1.14
Balance sheet data:
	Total assets			$	4,281.7		$	12,183.4					$	11,223.9
	Total debt				1,889.6			5,579.4						4,265.5
	Total partners’ equity				1,605.3			5,279.6						5,635.0
Other financial data:
	Cash provided by operating activities			$	222.7		$	33.0
	Cash used in investing activities				153.5			734.7
	Cash provided by (used in) financing activities				(42.8	)		817.9
	Distributions received from unconsolidated affiliates				25.7			54.6
	Gross operating margin				301.4			376.0		$	791.9		$	791.9
	EBITDA				266.5			347.2			709.2			709.2



			Enterprise Consolidated Historical


									For Nine
			For Year Ended						Months Ended
			December 31,						September 30,

			2001		2002		2003		2003		2004

Selected Volumetric Operating Data:
	Offshore pipelines & services, net volumes in billion British thermal units (BBtus) per day
		Natural gas transportation volumes		566		500		433		451		423
	Onshore natural gas pipelines & services, net volumes in BBtus/d
		Natural gas transportation volumes		783		701		599		590		650
	NGL pipelines & services, net volumes as shown
		NGL transportation volumes (thousand barrels (MBbls) per day, net)		420		1,306		1,275		1,273		1,358
		NGL fractionation volumes (MBbls/d, net)		204		235		227		223		235
		Equity NGL production (MBbls/d, net)		63		73		43		42		47
		Fee-based natural gas processing (MMcf/d, net)		*		*		194		150		944
	Petrochemical services, net volumes in MBbls/d
		Butane isomerization volumes		80		84		77		80		73
		Propylene fractionation volumes		31		55		57		57		58
		Octane additive production volumes		5		5		4		4		9
		Petrochemical transportation volumes		33		46		68		63		73

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

S-14

Non-GAAP Financial Measures

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

Gross Operating Margin

We define gross operating margin as operating income before: (1) depreciation and amortization expense; (2) operating lease expenses for which we do not have the cash payment obligation; (3) gains and losses on the sale of assets; and (4) selling, general and administrative expenses. We view gross operating margin as an important performance measure of the core profitability of our operations. This measure forms the basis of our internal financial reporting and is used by our senior management in deciding how to allocate capital resources among business segments. We believe that investors benefit from having access to the same financial measures that our management uses. The GAAP measure most directly comparable to gross operating margin is operating income.

EBITDA

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


	•	the financial performance of our assets without regard to financing methods, capital structures or historical costs basis;

	•	the ability of our assets to generate cash sufficient to pay interest cost and support its indebtedness;

	•	our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing and capital structure; and

	•	the viability of projects and the overall rates of return on alternative investment opportunities.

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

S-15

Non-GAAP Reconciliations

The following table presents a reconciliation of our non-GAAP financial measures of 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:



			Consolidated Historical
												For Year Ended
												December 31, 2003
			For Year Ended December 31,
															Pro Forma
			2001			2002			2003			Pro Forma			as Adjusted


												(Unaudited)

			(Dollars in millions)
Reconciliation of Non-GAAP “Gross operating margin” to GAAP “Operating income”
Operating income			$	286.8		$	194.3		$	248.1		$	425.3		$	425.3
	Adjustments to reconcile Operating income to Gross operating margin:
		Depreciation and amortization in operating costs and expenses		48.8			86.0			115.7			379.6			379.6
		Retained lease expense, net in operating costs and expenses		10.4			9.1			9.1			9.1			9.1
		Gain on sale of assets in operating costs and expenses		(0.4	)								(18.7	)		(18.7	)
		Selling, general and administrative costs		30.3			42.9			37.5			92.0			92.0

Total Gross Operating Margin			$	375.9		$	332.3		$	410.4		$	887.3		$	887.3

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		$	103.4		$	112.5
	Adjustments to derive EBITDA:
		Interest expense		52.5			101.6			140.8			321.1			312.0
		Provision for income taxes					1.6			5.3			5.3			5.3
		Depreciation and amortization (excluding amortization component in interest expenses)		51.1			86.1			115.8			379.7			379.7

EBITDA				345.8			284.8			366.4		$	809.5		$	809.5

	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
	Equity in loss (income) of 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
	Increase in restricted cash			(5.7	)		(3.0	)		(5.1	)
	Net effect of changes in operating accounts			(37.2	)		92.7			120.9

Cash provided by operating activities			$	277.6		$	326.8		$	419.6

S-16

Non-GAAP Reconciliations (Continued)



			Consolidated Historical

									For Nine Months Ended
			For Nine Months						September 30, 2004
			Ended September 30,
											Pro Forma
			2003			2004			Pro Forma		as Adjusted


			(Unaudited)

			(Dollars in millions)
Reconciliation of Non-GAAP “Gross operating margin” to GAAP “Operating income”
Operating Income			$	182.0		$	247.7		$	424.3	$	424.3
	Adjustments to reconcile Operating income to Gross operating margin:
		Depreciation and amortization in operating costs and expenses		83.8			94.7			287.5		287.5
		Retained lease expense, net in operating costs and expenses		6.8			6.8			6.8		6.8
		Loss (gain) on sale of assets in operating costs and expenses		(0.1	)		0.2			0.2		0.2
		Selling, general and administrative costs		28.9			26.6			73.1		73.1

Gross operating margin			$	301.4		$	376.0		$	791.9	$	791.9

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)				70.4			152.9			216.5		223.3
	Adjustments to derive EBITDA:
		Interest expense		107.7			96.9			202.5		195.7
		Provision for income taxes		4.6			2.7			2.7		2.7
		Depreciation and amortization (excluding amortization component in interest expenses)		83.8			94.7			287.5		287.5

EBITDA				266.5			347.2		$	709.2	$	709.2

	Interest expense			(107.7	)		(96.9	)
	Amortization in interest expense			12.3			3.2
	Provision for income taxes			(4.6	)		(2.7	)
	Cumulative effect of change in accounting principle			—			(10.8	)
	Provision for impairment of long-lived asset			—			4.0
	Equity in loss (income) of unconsolidated affiliates			16.6			(42.2	)
	Distributions from unconsolidated affiliates			25.7			54.6
	Loss (gain) on sale of assets			(0.1	)		0.2
	Operating lease expense paid by EPCO (excluding minority interest portion)			6.8			6.8
	Other expenses paid by EPCO			0.6			—
	Minority interest			4.4			6.9
	Deferred income tax expense			4.2			6.3
	Increase in restricted cash			(5.9	)		(3.1	)
	Net effect of changes in operating accounts			3.9			(240.5	)

Cash provided by operating activities			$	222.7		$	33.0

S-17

Non-GAAP Reconciliations (Continued)

The following table presents a reconciliation of our non-GAAP financial measures of total gross operating margin and EBITDA as presented on page S-7 to their respective GAAP measures.



			For Three Months					For the Year Ended
			Ended December 31,					December 31, 2004

			2003		2004			2003		2004

										(Unaudited)
			(Unaudited)
			(Dollars in millions)
Reconciliation of Non-GAAP “Total gross operating margin” to GAAP “Operating income”
Operating income			$	66.1	$	175.3		$	248.1	$	423.0
	Adjustments to reconcile Operating income to Total gross operating margin:
		Depreciation and amortization in operating costs and expenses		31.9		99.1			115.7		193.7
		Retained lease expense, net in operating costs and expenses		2.3		0.9			9.1		7.7
		Loss (gain) on sale of assets in operating costs and expenses		—		(16.1	)		—		(15.9	)
		Selling, general and administrative costs		8.7		20.0			37.5		46.7

Total gross operating margin			$	109.0	$	279.2		$	410.4	$	655.2

Reconciliation of Non-GAAP “EBITDA” to GAAP “Net income” or “Income from continuing operations” and GAAP “Cash provided by operating activities”
Net income			$	34.2	$	115.4		$	104.5	$	268.3
	Adjustments to derive EBITDA:
		Interest expense		33.1		58.8			140.8		155.7
		Provision for income taxes		0.7		1.0			5.3		3.7
		Depreciation and amortization (excluding amortization component in interest expenses)		31.9		100.4			115.8		195.4

EBITDA			$	99.9	$	275.6		$	366.4	$	623.1

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RISK FACTORS

An investment in our common units involves risks. You should consider carefully the risk factors included below, under the caption “Risk Factors” beginning on page 2 of the accompanying prospectus, and under “Business and Properties — Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2003, together with all of the other information included in, or incorporated by reference into, this prospectus supplement, when evaluating an investment in our common units. If any of these risks were to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, the trading price of our common units could decline, and you could lose all or part of your investment.

Risks Related to Our Business


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

We operate predominantly in the midstream energy sector which includes gathering, transporting, processing, fractionating and storing natural gas, NGLs and crude oil. As such, our results of operations, cash flows and financial condition may be materially adversely affected by changes in the prices of these hydrocarbon products and by changes in the relative price levels among these hydrocarbon products. In general terms, the prices of natural gas, NGLs, crude oil and other hydrocarbon products are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are impossible to control. These factors include:


	•	the level of domestic production;

	•	the availability of imported oil and natural gas;

	•	actions taken by foreign oil and natural gas producing nations;

	•	the availability of transportation systems with adequate capacity;

	•	the availability of competitive fuels;

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

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

We are also exposed to natural gas and NGL commodity price risk under natural gas processing and gathering and NGL fractionation contracts that provide for our 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 our results of operations, cash flows and financial position.


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

Our profitability could be materially impacted by a decline in the volume of natural gas, NGLs and crude oil transported, gathered or processed at our 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 our facilities.

The crude oil, natural gas and NGLs available to our facilities will be derived from reserves produced from existing wells, which reserves naturally decline over time. To offset this natural decline, our facilities will need access to additional reserves. Additionally, some of our 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 our control and can adversely affect the

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decision by producers to explore for and develop new reserves. These factors could 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 our facilities are located. This could result in a decrease in volumes to our offshore platforms, natural gas processing plants, natural gas, crude oil and NGL pipelines, and NGL fractionators which would have a material adverse affect on our results of operations, cash flows and financial position. Additional reserves, if discovered, may not be developed in the near future or at all.


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

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


	*We face competition from third parties in our midstream businesses.*

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


	•	geographic proximity to the production;

	•	costs of connection;

	•	available capacity;

	•	rates; and

	•	access to markets.

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	*Our debt level may limit our future financial and operating flexibility.*

As of September 30, 2004, on a pro forma as adjusted basis, we had approximately $4.3 billion of consolidated debt outstanding. The amount of our debt could have significant effects on our future operations, including, among other things:


	•	a significant portion of our 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 our debt level negatively;

	•	covenants contained in our existing debt arrangements will require us to continue to meet financial tests that may adversely affect our flexibility in planning for and reacting to changes in our business;

	•	our ability to obtain additional financing for working capital, capital expenditures, acquisitions and general partnership purposes may be limited;

	•	we may be at a competitive disadvantage relative to similar companies that have less debt; and

	•	we may be more vulnerable to adverse economic and industry conditions as a result of our 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, however, restrict our ability to incur additional debt, though any debt we may incur in compliance with these restrictions may still be substantial.

Each of our revolving credit facilities and indentures for our public debt contains conventional financial covenants and other restrictions. A breach of any of these restrictions by us 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.

Our ability to access the capital markets to raise capital on favorable terms will be affected by our debt level, the amount of our 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. Moreover, if the rating agencies were to downgrade our corporate credit, then we could experience an increase in our borrowing costs, difficulty assessing capital markets or a reduction in the market price of our common units. Such a development could adversely affect our ability to obtain financing for working capital, capital expenditures or acquisitions or to refinance existing indebtedness. If we are unable to access the capital markets on favorable terms in the future, we might be forced to seek extensions for some of our short-term securities 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, if at all, could be more onerous than those contained in existing debt agreements. Any such arrangements could, in turn, increase the risk that our leverage may adversely affect our future financial and operating flexibility and our ability to pay cash distributions at expected rates.


	*We may not be able to fully execute our growth strategy if we encounter illiquid capital markets or increased competition for qualified assets.*

Our strategy 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 our ability to compete effectively and diversify our asset portfolio, thereby providing more stable cash flow. We regularly consider and enter into discussions regarding, and are currently contemplating, potential joint ventures, stand alone projects or other transactions that we believe will present opportunities to realize synergies, expand our role in the energy infrastructure business and increase our market position.

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

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


	Our growth strategy may adversely affect our results of operations if we do not successfully integrate the businesses that we acquire, including GulfTerra, or if we substantially increase our indebtedness and contingent liabilities to make acquisitions.

Our growth strategy includes making accretive acquisitions. As a result, from time to time, we will evaluate and acquire assets and businesses that we believe complement our existing operations. Similar to the risks associated with integrating our operations with GulfTerra’s operations, we may be unable to integrate successfully businesses we acquire in the future. We may incur substantial expenses or encounter delays or other problems in connection with our growth strategy that could negatively impact our 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;

	•	establishing the internal controls and procedures that we are required to maintain under the Sarbanes-Oxley Act of 2002;

	•	managing relationships with new joint venture partners with whom we have not previously partnered;

	•	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, our capitalization and results of operations may change significantly following an acquisition. A substantial increase in our indebtedness and contingent liabilities could have a material adverse effect on our business. In addition, any anticipated benefits of a material acquisition, such as expected cost savings, may not be fully realized, if at all.


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

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

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	*Our actual construction, development and acquisition costs could exceed forecasted amounts.*

We 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. We may not be able to complete our projects, whether in deepwater or otherwise, at the costs estimated at the time of initiation.


	*We may be unable to cause our joint ventures to take or not to take certain actions unless some or all of our joint venture participants agree.*

We participate in several joint ventures. 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, we may be unable to cause any of our joint ventures to take or not to take certain actions, even though those actions may be in the best interest of us or the particular joint venture.

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 our partnering with different or additional parties.


	*The interruption of distributions to us from our subsidiaries and joint ventures may affect our ability to satisfy our obligations and to make cash distributions to our unitholders.*

We are a holding company with no business operations. Our only significant assets are the equity interests we own in our subsidiaries and joint ventures. As a result, we depend upon the earnings and cash flow of our subsidiaries and joint ventures and the distribution of that cash to us in order to meet our obligations and to allow us to make distributions to our unitholders.

In addition, the management committees of the joint ventures in which we participate typically have sole discretion regarding the occurrence and amount of distributions. Some of the joint ventures in which we 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 us under certain circumstances. Accordingly, our joint ventures may be unable to make distributions to us at current levels or at all.


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

Some of our operations involve risks of personal injury, property damage and environmental damage, which could curtail our operations and otherwise materially adversely affect our cash flow. For example, natural gas facilities operate at high pressures, sometimes in excess of 1,100 pounds per square inch. We 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 our operations are exposed to potential natural disasters, including hurricanes, tornadoes, storms, floods and/or earthquakes.

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If one or more facilities that are owned by us or that deliver oil, natural gas or other products to us are damaged by severe weather or any other disaster, accident, catastrophe or event, our operations could be significantly interrupted. Similar interruptions could result from damage to production or other facilities that supply our facilities or other stoppages arising from factors beyond our 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 we are a party to obligate us to indemnify our customers for any damage or injury occurring during the period in which the customers’ natural gas is in our possession. Any event that interrupts the fees generated by our energy infrastructure assets, or which causes us to make significant expenditures not covered by insurance, could reduce our cash available for paying our interest obligations as well as unitholder distributions and, accordingly, adversely affect the market price of our securities.

We believe that we 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, we may not be able to renew our existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our 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.


	*An impairment of goodwill could reduce our earnings.*

We had recorded $445.9 million of goodwill and $961.9 million of intangible assets on our consolidated balance sheet as of September 30, 2004. 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 us 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 we determine that any of our goodwill or intangible assets were impaired, we would be required to take an immediate charge to earnings with a correlative effect on partners’ equity and balance sheet leverage as measured by debt to total capitalization.


	*Increases in interest rates could adversely affect our business and may cause the market price of our common units to decline.*

In addition to our exposure to commodity prices, we have significant exposure to increases in interest rates. As of December 31, 2004, we had approximately $4.3 billion of consolidated debt, of which approximately $2.9 billion was at fixed interest rates and approximately $1.4 billion was at variable interest rates, after giving effect to existing interest swap arrangements. We may from time to time enter into additional interest rate swap arrangements, which could increase our exposure to variable interest rates. As a result, our results of operations, cash flows and financial condition, could be materially adversely affected by significant increases in interest rates.

An increase in interest rates may also cause a corresponding decline in demand for equity investments in general, and in particular for yield-based equity investments such as our common units. Any such reduction in demand for our common units resulting from other more attractive investment opportunities may cause the trading price of our common units to decline.


	*The use of derivative financial instruments could result in material financial losses by us.*

We 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 we hedge our commodity price and interest rate exposures, we will forego the benefits we would otherwise experience if commodity prices or interest rates were

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to change in our 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.


	*Our pipeline integrity program may impose significant costs and liabilities on us.*

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 us. However, we will continue our pipeline integrity testing programs, which are intended to assess and maintain the integrity of our pipelines. While the costs associated with the pipeline integrity testing itself are not large, the results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines.


	*Environmental costs and liabilities and changing environmental regulation could materially affect our cash flow.*

Our operations are 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.

We 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 our operations, including the handling, manufacture, use, emission or disposal of substances and wastes. Moreover, as with other companies engaged in similar or related businesses, our operations have some risk of environmental costs and liabilities because we handle petroleum products.


	*Federal, state or local regulatory measures could materially adversely affect our business.*

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, contains a general overview of FERC and state regulation applicable to our energy infrastructure assets. This regulatory oversight can affect certain aspects of our 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

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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.

For example, in December 2002, High Island Offshore System, L.L.C., or HIOS, an interstate natural gas pipeline owned by us, filed a rate case pursuant to Section 4 of the Natural Gas Act before FERC to increase its transportation rates. 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. The ALJ issued an initial decision on the issues set for hearing on April 22, 2004, proposing rates lower than the rate initially proposed by HIOS. In response to the ALJ’s initial decision, HIOS filed, on August 5, 2004, a settlement agreement whereby HIOS proposed to implement its rates in effect prior to this proceeding for a prospective three-year period.

On January 24, 2005, FERC issued an order rejecting HIOS’s settlement offer and generally affirming the ALJ’s initial decision, resulting in rates significantly lower than the rate proposed in HIOS’ settlement offer. FERC’s January 24 order may be subject to requests for rehearing and appeal to federal court. We are not able to predict the outcome of the HIOS proceeding, but an adverse outcome in this proceeding or any other rate case proceedings to which we may be a party in the future could adversely affect our results of operations, cash flows and financial position.

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

Our intrastate NGL and gas pipelines are subject to regulation in Alabama, Colorado, Louisiana, Mississippi, New Mexico and Texas. 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.

Certain of our companies, assets and services 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, or NGPA.

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.

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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. The Commission, by letter dated January 11, 2005, is seeking additional information from GulfTerra Texas regarding its July 12, 2004 filing, thus, a final FERC order is still pending. Additionally, the FERC’s February 25, 2004 order directed GulfTerra Texas to file a new rate case or justification of existing rates every three years. GulfTerra Texas filed a timely request for rehearing of the triennial rate filing requirement, which the Commission rejected, on December 27, 2004.

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 stated that FERC had not provided reasonable decision-making in support of its 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 the appropriate income tax allowance for a pipeline owned by a master limited partnership and 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 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. On December 2, 2004, the FERC issued a Notice of Inquiry in Docket No. PL05-5 suggesting that BP West Coast may not be limited to the specific facts. Specifically, FERC requested comments regarding whether the court’s opinion should apply only to the specific facts of that case, or whether it should apply more broadly, and, if the latter, what effect that ruling might have on energy infrastructure investments. It is not clear what action the FERC will take in response to BP West Coast after considering comments filed, to what extent such action will be challenged and, if so, whether it will withstand further FERC or judicial review.

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


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

Sales of a substantial number of our common units in the public market following this offering could cause the market price of our common units to decline. Upon completion of this offering, a total of approximately 374,785,865 of our common units will be outstanding. Shell US Gas & Power LLC, which will own 36,572,122 of our common units following this offering, representing approximately 9.6% 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.

Sales of a substantial number of these units in the trading markets, whether in a single transaction or series of transactions, or the possibility that these sales may occur, could reduce the market price of our outstanding common units. In addition, these sales, or the possibility that these sales may occur, could make it more difficult for us to sell our common units in the future.

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USE OF PROCEEDS

We expect to receive net proceeds of approximately $266.5 million (assuming a public offering price of $27.28) from the sale of the 10,000,000 common units we are offering (including the net capital contribution of $5.4 million from our general partner to maintain its 2% general partner interest) after deducting underwriting discounts, commissions and estimated offering expenses payable by us. If the underwriters exercise their over-allotment option in full, we will receive net proceeds of approximately $306.5 million, including a proportionate net capital contribution of $6.1 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, to permanently reduce borrowings and commitments outstanding under our 364-day acquisition revolving credit facility, which indebtedness was incurred to fund a portion of the purchase price at the closing of the GulfTerra merger and related transactions on September 30, 2004. Any remaining proceeds will be used for general partnership purposes, which may include acquisitions or the temporary reduction of amounts borrowed under our revolving credit facilities. 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 January 31, 2005, we had $242.2 million of borrowings outstanding under our 364-day acquisition revolving credit facility that bear interest at a rate of approximately 3.4% per annum, and we had $493.0 million of borrowings outstanding under our multi-year revolving credit facility that bear interest at a rate of approximately 3.4% per annum. Amounts repaid on our multi-year revolving credit facility may be reborrowed from time to time.

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PRICE RANGE OF COMMON UNITS AND DISTRIBUTIONS

On December 31, 2004, we had 364,293,458 common units outstanding, beneficially held by approximately 100,000 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 February 3, 2005 was $27.28 per common unit.



						Cash Distribution History
		Price Ranges
						Per
		High		Low		Unit(1)			Record Date		Payment Date

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			July 30, 2004		August 6, 2004
	3rd Quarter		23.70		20.19		0.3950			October 29, 2004		November 5, 2004
	4th Quarter		25.99		22.73		0.4000	(2)		January 31, 2005		February 14, 2005
2005
	1st Quarter (through February 3, 2005)	$	28.35	$	24.85		—	(3)		—		—


(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 January 19, 2005, our general partner increased our quarterly cash distribution to $0.40 per common unit, or $1.60 per common unit on an annualized basis, beginning with cash distributions with respect to the fourth quarter of 2004. The distribution with respect to the fourth quarter will be paid on February 14, 2005 to unitholders of record on January 31, 2005. The units purchased in this offering will not be entitled to receive this distribution.

(3)	Distributions with respect to quarters subsequent to the fourth quarter of 2004 have neither been declared nor paid.

S-29

CAPITALIZATION

The following table sets forth our capitalization as of September 30, 2004:


	•	on a consolidated historical basis;

	•	on a pro forma basis giving effect to the following adjustments:


	•	the issuance by our operating partnership of $2 billion of senior unsecured notes on October 4, 2004, and the application of the net proceeds therefrom to reduce debt amounts outstanding under our 364-day acquisition revolving credit facility that was used to fund a portion of the purchase price at the closing of the GulfTerra merger and related transactions on September 30, 2004;

	•	the completion on October 5, 2004 of our operating partnership’s four cash tender offers for $915 million in principal amount of GulfTerra’s senior and senior subordinated notes using $1.1 billion in cash borrowed under our 364-day acquisition revolving credit facility, which was placed in escrow on September 30, 2004;

	•	our issuance of 2,199,350 common units in connection with the DRIP in November 2004; and

	•	the conversion of the remaining outstanding 80 Series F2 convertible units, which were originally issued by GulfTerra, into an aggregate of 1,950,317 of our common units in November and December 2004; and


	•	on a pro forma as adjusted basis to give effect to the issuance of 10,000,000 common units in this offering at an assumed offering price of $27.28, our general partner’s proportionate capital contribution and the application of the net proceeds from this offering to reduce borrowings under our revolving credit facilities.

The historical data in the table on the following page are derived from and should be read in conjunction with our historical financial statements, including the accompanying notes, incorporated by reference in this prospectus supplement. Please read our unaudited pro forma financial statements included elsewhere in this prospectus supplement for a complete description of the adjustments we have made to arrive at the pro forma financial measures that we present in the following table. You should also read our financial statements and notes that are incorporated by reference in this prospectus supplement for additional information regarding our capital structure.

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Enterprise Historical and Pro Forma Capitalization

As of September 30, 2004


										Pro Forma
				Historical			Pro Forma			As Adjusted


				(Dollars in millions)
Cash and cash equivalents				$	146.6		$	234.0		$	234.0

Long-term borrowings including current portion:
	Enterprise amounts:
		364-Day Acquisition Revolving Credit Facility, variable rate, due September 2005, $2.25 billion borrowing capacity		$	2,250.0		$	265.5			—
		Multi-Year Revolving Credit Facility “B”, variable rate, due September 2009, $750 million borrowing capacity			545.0			545.0		$	544.0
		Senior Notes A, 8.25% fixed-rate, due March 2005			350.0			350.0			350.0
		Seminole Notes, 6.67% fixed-rate, $15 million due in December 2004 and 2005			30.0			30.0			30.0
		MBFC Loan, 8.70% fixed-rate, due March 2010			54.0			54.0			54.0
		Senior Notes B, 7.50% fixed-rate, due February 2011			450.0			450.0			450.0
		Senior Notes C, 6.375% fixed-rate, due February 2013			350.0			350.0			350.0
		Senior Notes D, 6.875% fixed-rate, due March 2033			500.0			500.0			500.0
		Senior Notes E, 4.00% fixed-rate, due October 2007						500.0			500.0
		Senior Notes F, 4.625% fixed-rate, due October 2009						500.0			500.0
		Senior Notes G, 5.60% fixed-rate, due October 2014						650.0			650.0
		Senior Notes H, 6.65% fixed-rate, due October 2034						350.0			350.0
	GulfTerra amounts:
		Senior Notes, 6.25% fixed-rate, due June 2010			250.0			0.7			0.7
		Senior Subordinated Notes, 8.50% fixed-rate, due June 2010			215.9			3.9			3.9
		Senior Subordinated Notes, 8.50% fixed-rate, due June 2011			321.6			1.8			1.8
		Senior Subordinated Notes, 10.625% fixed-rate, due December 2012			134.0			0.1			0.1
		Fair value of GulfTerra notes at merger closing date			132.4			—			—

			Total principal amount		5,582.9			4,551.0			4,284.5
	Other				(3.5	)		(19.0	)		(19.0	)

			Total debt obligations		5,579.4			4,532.0			4,265.5
Minority interest					61.3			61.3			61.3
Partners’ equity:
	Common units, including restricted common units				5,164.4			5,251.5			5,512.6
	General partner				105.4			107.2			112.6
	Accumulated other comprehensive income				24.1			24.1			24.1
	Other				(14.3	)		(14.3	)		(14.3	)

			Total partners’ equity		5,279.6			5,368.5			5,635.0

			Total capitalization	$	10,920.3		$	9,961.8		$	9,961.8

S-31

BUSINESS AND PROPERTIES

Our Business and Properties

Formed in 1998 as a limited partnership, we are a leading North American midstream energy company that provides a wide range of services to producers and consumers of natural gas, natural gas liquids, or NGLs, and crude oil and we are an industry leader in the development of midstream infrastructure in the deepwater trend of the Gulf of Mexico. We provide integrated services to our customers and generate fee-based cash flow from multiple sources along our midstream energy value chain.

Our midstream energy services include:


	•	gathering and transportation of raw natural gas from both onshore and offshore Gulf of Mexico developments;

	•	gathering and transportation of crude oil from offshore Gulf of Mexico developments;

	•	offshore production platform services;

	•	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, 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 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 system of assets in the Gulf Coast region of the United States, combined with our Mid-America and Seminole pipeline systems, create the only integrated North American midstream network.

Our Business Segments

As a result of the GulfTerra merger and related transactions, we have reorganized our business activities into four reportable business segments: (i) Offshore Pipelines & Services; (ii) Onshore Natural Gas Pipelines & Services; (iii) NGL Pipelines & Services; and (iv) Petrochemical Services. Our business segments are generally organized and managed along our midstream energy value chain according to the type of services rendered and products produced and sold.

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	Offshore Pipelines & Services

Our Offshore Pipelines & Services business segment consists of:


	•	approximately 1,390 miles of offshore natural gas pipelines strategically located to serve production activities in some of the most active drilling and development regions in the Gulf of Mexico;

	•	ownership interests in offshore oil pipeline systems aggregating approximately 800 miles, which are strategically located in the vicinity of some prolific oil-producing regions in the Gulf of Mexico;

	•	ownership interests in seven multi-purpose offshore hub platforms located in the Gulf of Mexico which are used to process production from offshore oil and natural gas developments, interconnect our offshore pipeline grid and assist in performing pipeline maintenance; and

	•	ownership interests in four minor oil and natural gas producing properties located in the waters offshore of Louisiana.


	Onshore Natural Gas Pipelines & Services

Our Onshore Natural Gas Pipelines & Services business segment includes onshore natural gas pipeline systems aggregating approximately 17,180 miles that provide for the gathering and transmission of natural gas in Alabama, Colorado, Louisiana, Mississippi, New Mexico and Texas. Included in this segment are two salt dome natural gas storage facilities located in Mississippi, which are strategically located to serve the Northeast, Mid-Atlantic and Southeast natural gas markets. We also lease natural gas storage facilities located in Texas and Louisiana.


	NGL Pipelines & Services

Our NGL Pipelines & Services business segment consists of:


	•	our natural gas processing business and related NGL marketing activities;

	•	NGL pipelines aggregating approximately 12,600 miles and related storage facilities, which include our strategic Mid-America and Seminole NGL pipeline systems;

	•	NGL fractionation facilities located in Texas and Louisiana; and

	•	our import and export terminaling operations.

At the core of our natural gas processing business are 24 processing plants, located primarily in south Louisiana, south Texas and New Mexico, that process raw natural gas into a product that meets pipeline and industry specifications by removing NGLs and impurities. In connection with our processing business, we receive a portion of the NGL production from the gas plants. This equity NGL production, together with the NGLs we purchase, supports the NGL marketing activities included in this business segment. Additionally, our NGL pipelines transport mixed NGLs and other hydrocarbons to fractionation plants, distribute and collect NGL products to and from petrochemical plants and refineries. Our NGL fractionation facilities separate mixed NGL streams into discrete NGL products: ethane, propane, isobutane, normal butane and natural gasoline.


	Petrochemical Services

Our Petrochemical Services business segment includes our four propylene fractionation facilities, isomerization complex, and octane additive production facility. This segment also includes approximately 460 miles of various propylene pipeline systems and a 70-mile hi-purity isobutane pipeline.

Our propylene fractionation facilities separate refinery-sourced propane/propylene mix into propane, propylene and mixed butane. Our isomerization complex converts normal butane into isobutane.

S-33

MANAGEMENT

Our Management

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


			Position with General Partner
Name	Age		of Enterprise

Dan L. Duncan		72	Director and Chairman of the Board
O.S. Andras		69	Director and Vice Chairman of the Board and Chief Executive Officer
Robert G. Phillips		50	Director and President and Chief Operating Officer
Dr. Ralph S. Cunningham		63	Director*
Lee W. Marshall, Sr.		71	Director*
W. Matt Ralls		55	Director*
Richard S. Snell		62	Director*
Richard H. Bachmann		52	Executive Vice President, Secretary and Chief Legal Officer
Michael A. Creel		51	Executive Vice President and Chief Financial Officer
James H. Lytal		47	Executive Vice President
A. James Teague		59	Executive Vice President
Charles E. Crain		71	Senior Vice President
W. Ordemann		45	Senior Vice President
Gil H. Radtke		43	Senior Vice President
James M. Collingsworth		49	Senior Vice President
James A. Cisarik		46	Senior Vice President
Lynn L. Bourdon, III		43	Senior Vice President
Bart H. Heijermans		38	Senior Vice President
Richard H. Hoover		48	Senior Vice President
Joel D. Moxley		46	Senior Vice President
Michael J. Knesek		50	Vice President, Controller and Principal Accounting Officer
W. Randall Fowler		48	Vice President and Treasurer


*	Independent directors

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

O.S. Andras was elected Chief Executive Officer, Vice Chairman and a Director of our general partner in September 2004. Mr. Andras served as President, Chief Executive Officer and a Director of our general partner from April 1998 until September 2004. 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.

Robert G. Phillips was elected President, Chief Operating Officer and Director of our general partner in September 2004. Mr. Phillips served as a Director of GulfTerra’s general partner from August 1998 until September 2004. He served as Chief Executive Officer for GulfTerra and its general partner from November 1999 and as Chairman from October 2002 until September 2004. He served as Executive Vice President

S-34

from August 1998 to October 1999. Mr. Phillips served as President of El Paso Field Services Company between June 1997 and September 2004. 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.

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 general partner’s Audit and Conflicts Committee and is a member of our general partner’s Governance 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 general partner’s Audit and Conflicts Committee.

W. Matt Ralls was elected a Director of our general partner in September 2004. Mr. Ralls served as a Director of GulfTerra’s general partner from May 2003 to September 2004 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. Previously, he served as Executive Vice President, Chief Financial Officer, and Director of Kelley Oil and Gas Corporation and as Vice President of Capital Markets and Corporate Development for The Meridian Resource Corporation before joining Global Marine. He spent the first 17 years of his career in commercial banking at the senior management level. Mr. Ralls is a member of our general partner’s Audit and Conflicts Committee and serves as Chairman of our general partner’s Governance 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 general partner’s Governance Committee.

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.

James H. Lytal was elected Executive Vice President of our general partner in September 2004. Mr. Lytal served as a Director of GulfTerra’s general partner from August 1994 until September 2004 and as GulfTerra’s President and the President of GulfTerra’s general partner from July 1995 until September 2004. 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.

A. James 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.

S-35

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.

Bart H. Heijermans was elected Senior Vice President of our general partner in September 2004. Mr. Heijermans served as GulfTerra’s Vice President, Offshore from June 2003 until September 2004. From June 2001 to June 2003, he served as GulfTerra’s Vice President, Deepwater Project Development. He served as GulfTerra’s Vice President, Operations and Engineering from August 1997 to June 2001. Prior to joining GulfTerra, Mr. Heijermans served in various capacities in the development and construction of offshore oil and gas infrastructure for Shell E&P International and Shell Research in The Netherlands, United Kingdom and United States of America.

Richard A. Hoover was elected Senior Vice President of our general partner in September 2004. Mr. Hoover served as GulfTerra’s Vice President Western Division — Commercial from January 2001 until September 2004. This position included management of GulfTerra’s San Juan and Permian Basin assets. Mr. Hoover has held various other commercial positions since joining GulfTerra in June 1996 including management of assets in the Texas Gulf Coast, Anadarko Basin, Mid Continent and Rockies. Prior to joining GulfTerra, Mr. Hoover held various positions over 16 years in the Midstream, Independent Power and E&P sectors with Delhi Gas Pipeline Corporation, Panda Energy Corporation and Champlin Petroleum Corporation.

Joel D. Moxley was elected Senior Vice President of our general partner in September 2004. Mr. Moxley served as GulfTerra’s Vice President, Processing and NGL Marketing from December 2000 until September 2004. From August 1997 to December 2000, Mr. Moxley was a Vice President at PG&E Gas Transmission-

S-36

Texas where he had responsibilities for gas processing, gas supply and NGL marketing. Mr. Moxley held various positions with natural gas, gas processing and business development operations at Valero Energy Corporation from July 1991 to July 1997. He spent the first 11 years of his career at Occidental Petroleum where he served in various engineering, operations, marketing and business development positions within the gas processing division.

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.

S-37

TAX CONSEQUENCES

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 that are specific to your particular circumstances.

We estimate that if you purchase common units in this offering and own them through December 31, 2007, 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. 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 $0.40 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.

Ownership of common units by tax-exempt entities, regulated investment companies and foreign investors raises issues unique to such persons. Recent legislation treats net income derived from the ownership of certain publicly traded partnerships (including us) as qualifying income to a regulated investment company. However, this legislation is only effective for taxable years beginning after October 22, 2004, the date of enactment. For taxable years beginning prior to the date of enactment, very little of our income will be qualifying income to a regulated investment company. Please read “Tax Consequences — Tax-Exempt Organizations and Other Investors” in the accompanying prospectus.

The top marginal United States federal income tax rate for individuals is currently 35%. In general, net capital gains of an individual are subject to a maximum 15% United States federal income tax rate if the asset disposed of was held for more than twelve months at the time of disposition.

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. 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; 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.

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

S-38

UNDERWRITING

We are offering the common units described in this prospectus through the underwriters named below. UBS Securities LLC and Citigroup Global Markets Inc. are acting as joint book-running managers and representatives of the underwriters.

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


		Number of
Name of Underwriter		Common Units

UBS Securities LLC
Citigroup Global Markets Inc.
Goldman, Sachs & Co.
Lehman Brothers Inc.
Morgan Stanley & Co. Incorporated
Wachovia Capital Markets, LLC
A.G. Edwards & Sons, Inc.
Merrill Lynch, Pierce, Fenner & Smith Incorporated
Raymond James & Associates, Inc.
Sanders Morris Harris Inc.
RBC Capital Markets Corporation
KeyBanc Capital Markets, a Division of McDonald Investments Inc.

	Total		10,000,000

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 and our affiliates 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.

Over-Allotment Option

We have granted to the underwriters an option to purchase up to an aggregate of 1,500,000 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.

S-39

Commissions and Expenses

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



		Paid By Us

		No Exercise	Full Exercise

Per common unit		$	$
	Total	$	$

We have been advised by the underwriters that the underwriters propose to offer the common units directly to the public at the offering price to the public set forth on the cover page of this prospectus supplement and to dealers (who may include the underwriters) at this price to the public less a concession not in excess of $ per common unit. The underwriters may allow, and the dealers may reallow, a concession not in excess of $ per common 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 $1,000,000.

Indemnification

We and certain of our affiliates have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act of 1933, as amended, and to contribute to payments that may be required to be made in respect of these liabilities.

Lock-Up Agreements

We, certain of our affiliates, the directors and executive officers of our general partner and an affiliate of Shell 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 UBS Securities LLC and Citigroup Global Markets Inc. The restrictions described in this paragraph do not apply to:


	•	the issuance and sale of common units by us 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 our distribution reinvestment plan; or

	•	the potential sale of certain common units held by the affiliate of Shell pursuant to an outstanding purchase option. The number of common units that may be acquired pursuant to this option is that number of common units equal to the aggregate purchase price of $50,000,000 divided by 0.935 times the average closing price of common units on the NYSE during the 20-day trading period terminating five trading days prior to the date 90 days from December 31, 2004. The reference date for making this calculation may be deferred by an additional ten trading days under certain circumstances.

UBS Securities LLC and Citigroup Global Markets Inc. 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, UBS Securities LLC and Citigroup Global Markets Inc. will consider, among other factors, our unitholders’ reasons for requesting the release, the number of common units for which the release is being requested and market conditions at the time.

S-40

Price Stabilization, Short Positions And Penalty Bids

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


	•	Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.

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

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

	•	Penalty bids permit the underwriters to reclaim a selling concession from a syndicate member when the common units originally sold by the syndicate member are purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.

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

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

Listing

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

Affiliations

Some of the underwriters and their affiliates have performed investment banking, commercial banking and advisory services for us from time to time for which they have received customary fees and expenses. The underwriters and their affiliates may, from time to time in the future, engage in transactions with and perform services for us in the ordinary course of business.

Affiliates of UBS Securities LLC, Citigroup Global Markets Inc., Lehman Brothers Inc., Morgan Stanley & Co. Incorporated, Wachovia Capital Markets, LLC and RBC Capital Markets Corporation are lenders under our 364-day acquisition revolving credit facility. These affiliates will receive their respective

S-41

share of any repayment by us of amounts outstanding under the 364-day acquisition revolving credit facility from the proceeds of this offering. Because we intend to use more than 10% of the net proceeds from this offering to reduce indebtedness owed by us to such affiliates, this offering is being conducted in compliance with the requirements of Rule 2710(h) of the Conduct Rules of the National Association of Securities Dealers, Inc.

In addition, affiliates of UBS Securities LLC, Citigroup Global Markets Inc., Lehman Brothers Inc., Morgan Stanley & Co. Incorporated, Wachovia Capital Markets, LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, RBC Capital Markets Corporation and KeyBanc Capital Markets, a Division of McDonald Investments Inc. are lenders under our multi-year revolving credit facility.

NASD Conduct Rules

Because the National Association of Securities Dealers, Inc. views the common units offered by this prospectus as interests in a direct participation program, this offering is being made in compliance with Rule 2810 of the NASD’s Conduct Rules.

Electronic Distribution

A prospectus in electronic format may be made available by one or more of the underwriters or their affiliates. The representatives may agree to allocate a number of common units to underwriters for sale to their online brokerage account holders. The representatives will allocate common units to underwriters that may make Internet distributions on the same basis as other allocations. In addition, common units may be sold by the underwriters to securities dealers who resell common units to online brokerage account holders.

Other than the prospectus in electronic format, the information on any underwriter’s web site and any information contained in any other web site maintained by an underwriter is not part of the prospectus or the registration statement of which this prospectus forms a part, has not been approved and/or endorsed by us or any underwriter in its capacity as an underwriter and should not be relied upon by investors.

LEGAL MATTERS

Certain legal matters with respect to the common units will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas. Certain legal matters with respect to the common units will be passed upon for the underwriters by Andrews Kurth LLP, Houston, Texas. 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 3,200 common units of Enterprise.

EXPERTS

The (1) consolidated financial statements and the related consolidated financial statement schedule of Enterprise Products Partners L.P. and subsidiaries as incorporated in this prospectus supplement, by reference from Enterprise Products Partners L.P.’s 2003 Annual Report filed on Form 8-K with the Securities and Exchange Commission on December 6, 2004, 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.

S-42

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.

INCORPORATION OF DOCUMENTS BY REFERENCE

The Commission allows us to incorporate by reference into this prospectus supplement and the accompanying prospectus the information we file with it, which means that we can disclose important information to you by referring you to those documents. The information incorporated by reference is considered to be part of this prospectus supplement and the accompanying prospectus, and later information that we file with the Commission will automatically update and supersede this information. We incorporate by reference the documents listed below and any future filings we make with the Commission under section 13(a), 13(c), 14 or 15(d) of the Securities Exchange Act of 1934 until our offering is completed (other than information furnished under Items 2.02, 7.01, 9 or 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 except for Items 1, 2, 7 and 8, which have been superseded by the Current Report on Form 8-K filed with the Commission on December 6, 2004, Commission File No. 1-14323;

	•	Quarterly Reports on Form 10-Q for the quarters ended March 31, 2004, June 30, 2004 and September 30, 2004, Commission File Nos. 1-14323;

	•	Current Reports on Form 8-K filed with the Commission on December 15, 2003, 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, August 2, 2004, August 5, 2004, August 11, 2004, August 30, 2004, September 1, 2004, September 7, 2004, September 8, 2004, September 14, 2004, September 17, 2004, September 21, 2004, September 27, 2004, September 28, 2004, October 1, 2004, October 6, 2004, October 27, 2004, December 6, 2004, December 15, 2004, January 4, 2005 and January 18, 2005, Commission File Nos. 1-14323;

	•	Current Report on Form 8-K filed with the Commission on June 16, 2004, as amended by the Current Report on Form 8-K/ A (Amendment No. 1) filed with the Commission on August 4, 2004, Commission File Nos. 1-14323;

	•	Current Report on Form 8-K filed with the Commission on August 2, 2004, as amended by the Current Report on Form 8-K/ A (Amendment No. 1) filed with the Commission on August 5, 2004, Commission File Nos. 1-14323;

S-43


	•	Current Report on Form 8-K filed with the Commission on September 30, 2004, as amended by the Current Reports on Form 8-K/ A filed with the Commission on October 5, 2004 (Amendment No. 1), October 18, 2004 (Amendment No. 2), December 3, 2004 (Amendment No. 3), December 6, 2004 (Amendment No. 4) and December 27, 2004 (Amendment No. 5), Commission File Nos. 1-14323; and

	•	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.

FORWARD-LOOKING STATEMENTS

This prospectus supplement, the related prospectus and some of the documents we have incorporated herein and therein 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 and information currently available to us. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. When used in this prospectus supplement, the accompanying prospectus or the documents we have incorporated herein or therein by reference, 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 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. Among the key risk factors that may have a direct bearing on our results of operations and financial condition are:


	•	fluctuations in oil, natural gas and NGL prices and production due to weather and other natural and economic forces;

	•	a reduction in demand for our products by the petrochemical, refining or heating industries;

	•	the effects of our debt level on our future financial and operating flexibility;

	•	a decline in the volumes of NGLs delivered by our facilities;

	•	the failure of our credit risk management efforts to adequately protect us against customer non-payment;

	•	terrorist attacks aimed at our facilities;

	•	the failure to successfully integrate our operations with GulfTerra’s or any other companies we acquire; and

	•	the failure to realize the anticipated cost savings, synergies and other benefits of our merger with GulfTerra.

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 supplement and the accompanying prospectus.

S-44

INDEX TO UNAUDITED PRO FORMA FINANCIAL STATEMENTS

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


Introduction			F-2
Unaudited Pro Forma Condensed Statement of Consolidated Operations for the nine months ended September 30, 2004			F-4
Unaudited Pro Forma Condensed Statement of Consolidated Operations for the year ended December 31, 2003			F-5
Unaudited Pro Forma Condensed Consolidated Balance Sheet at September 30, 2004			F-6
Notes to Unaudited Pro Forma Condensed Consolidated Financial Statements			F-7

F-1

ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Introduction

The following unaudited pro forma condensed consolidated financial statements have been prepared to assist in the analysis of the financial effects of the transactions noted below. Unless the context requires otherwise, for purposes of this pro forma presentation, references to “we,” “our,” “us,” “the Company” or “Enterprise” are intended to mean the consolidated business and operations of Enterprise Products Partners L.P. References to “Operating Partnership” are intended to mean the consolidated business and operations of our primary operating subsidiary, Enterprise Products Operating L.P. References to “GulfTerra” are intended to mean the consolidated business and operations of GulfTerra Energy Partners, L.P. References to “El Paso” are intended to mean El Paso Corporation, its subsidiaries and affiliates. References to “EPCO” are intended to mean EPCO, Inc., an affiliate of the Company and our ultimate parent company.

The unaudited pro forma condensed consolidated financial statements give effect to the following transactions:


	•	The completion of Enterprise’s merger with GulfTerra and the related transactions on September 30, 2004 (the “GulfTerra Merger Transactions”). The GulfTerra Merger Transactions took place in three steps as described on page F-8.

	•	The issuance by our Operating Partnership of $2 billion of senior unsecured notes on October 4, 2004. The net proceeds from this offering were used to reduce debt amounts outstanding under our $2.25 billion 364-Day Acquisition Revolving Credit Facility that was used to fund a portion of the purchase price at the closing of the GulfTerra Merger Transactions on September 30, 2004.

	•	The completion on October 5, 2004 of our Operating Partnership’s four cash tender offers for $915 million in principal amount of GulfTerra’s senior and senior subordinated notes using $1.1 billion in cash borrowed under our $2.25 billion 364-Day Acquisition Revolving Credit Facility, which was placed in escrow on September 30, 2004.

	•	The public sale of 17,250,000 common units in both May 2004 and August 2004 by Enterprise. In addition, Enterprise issued a total of 5,183,591 common units in connection with its distribution reinvestment plan (“DRIP”) during the first eleven months of 2004 (2,199,350 common units were issued in November 2004).

	•	The conversion of the remaining outstanding 80 Series F2 convertible units, which were originally issued by GulfTerra, into 1,950,317 Enterprise common units in October and November 2004.

The unaudited pro forma as adjusted condensed consolidated financial statements also give effect to the sale of 10,000,000 of our common units to the public at an assumed offering price of $27.28 per unit and the application of the net proceeds therefrom as described in Note (s) on page F-17.

The unaudited pro forma condensed statements of consolidated operations for the nine months ended September 30, 2004 and the year ended December 31, 2003 assume the pro forma transactions noted above occurred on January 1, 2003 (to the extent not already reflected in the historical statements of consolidated operations). The unaudited pro forma condensed consolidated balance sheet shows the financial effects of the pro forma transactions as if they had occurred on September 30, 2004 (to the extent not already recorded in the historical balance sheet).

Dollar amounts presented in the tabular data within these pro forma condensed consolidated financial statements and footnotes are stated in millions of dollars, unless otherwise indicated.

The unaudited pro forma condensed consolidated financial statements and related pro forma information are based on assumptions that Enterprise believes are reasonable under the circumstances and are intended for informational purposes only. They are not necessarily indicative of the financial results that would have

F-2

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.

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 2003 Annual Report filed on Form 8-K with the Securities and Exchange Commission (the “Commission”) on December 6, 2004 and its Quarterly Report on Form 10-Q for the three and nine months ended September 30, 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 for the year ended December 31, 2003 and for the three and nine months ended September 30, 2004, contained in Enterprise’s Current Report on Form 8-K filed with the Commission on April 20, 2004 and Current Report on Form 8-K/ A (Amendment No. 5) filed with the Commission on December 27, 2004, respectively.

The combined financial statements for the year ended December 31, 2003 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 Report on Form 8-K filed with the Commission on April 16, 2004. The combined financial statements of the South Texas midstream assets for the eight months ended August 31, 2004 included herein were derived from the historical accounts and records of these entities.


	*Divestiture of Assets Required for FTC Approval of the GulfTerra Merger Transactions*

In connection with the GulfTerra Merger Transactions, we are required under a consent decree published for comment by the FTC on September 30, 2004 to sell our 50% interest in an entity which owns the Stingray natural gas pipeline and related gathering pipelines and dehydration and other facilities located in south Louisiana and the Gulf of Mexico offshore Louisiana. The $37.2 million carrying value of this investment was classified under “Assets Held for Sale” on our Unaudited Condensed Consolidated Balance Sheet at September 30, 2004. Enterprise recognized approximately $3 million in equity earnings from this investment for both the nine months ended September 30, 2004 and the year ended December 31, 2003. We are required to sell this investment by March 31, 2005. We have entered into a contract with a third party to sell this investment. We expect this sale to occur in the first quarter of 2005. The sale requires Federal Trade Commission approval under the terms of the consent decree relating to the GulfTerra Merger Transactions and is subject to other customary closing conditions.

We expect the proceeds from the sale of this investment will exceed the carrying value of this investment. For purposes of pro forma presentation, we have not estimated the proceeds from this sale and therefore, our pro forma statements of operations do not reflect any net gain or loss. In addition, our pro forma statements of operations do not reflect the removal of equity earnings from this investment due to the insignificant effect on the pro forma results of operations.

F-3

ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED PRO FORMA CONDENSED STATEMENT OF CONSOLIDATED OPERATIONS

For the Nine Months Ended September 30, 2004


									South Texas												Adjusted
									Midstream									Adjustments			Enterprise
			Enterprise			GulfTerra			Assets			Pro Forma			Enterprise			Due to this			Pro
			Historical			Historical			Historical			Adjustments			Pro Forma			Offering			Forma

REVENUES			$	5,458.5		$	676.7		$	1,103.2		$	(426.6	)(m)	$	6,752.4					$	6,752.4
													(59.4	)(q)
COSTS AND EXPENSES
Operating costs and expenses				5,226.4			432.3			1,058.3			103.2	(k)		6,272.8						6,272.8
													(20.0	)(l)
													(421.5	)(m)
													(46.5	)(p)
													(59.4	)(q)
Selling, general and administrative				26.6									46.5	(p)		73.1						73.1

		Total		5,253.0			432.3			1,058.3			(397.7	)		6,345.9						6,345.9

EQUITY IN INCOME (LOSS) OF UNCONSOLIDATED AFFILIATES				42.2									(32.0	)(n)		17.8						17.8
													7.6	(p)

OPERATING INCOME				247.7			244.4			44.9			(112.7	)		424.3						424.3

OTHER INCOME (EXPENSE)
Interest expense				(96.9	)		(82.7	)					5.1	(a)		(186.2	)	$	6.8	(s)		(179.4	)
													(42.6	)(g)
													(28.4	)(h)
													3.0	(i)
													56.3	(j)
Loss due to early redemptions of debt							(16.3	)								(16.3	)					(16.3	)
Earnings from unconsolidated affiliates							7.6						(7.6	)(p)
Other, net				0.9			0.5			(0.1	)		1.2	(o)		2.5						2.5

		Total		(96.0	)		(90.9	)		(0.1	)		(13.0	)		(200.0	)		6.8			(193.2	)

PROVISION FOR INCOME TAXES				(2.7	)											(2.7	)					(2.7	)
MINORITY INTEREST				(6.9	)		1.8									(5.1	)					(5.1	)

INCOME FROM CONTINUING OPERATIONS			$	142.1		$	155.3		$	44.8		$	(125.7	)	$	216.5		$	6.8		$	223.3

INCOME ALLOCATION:
	Limited partners		$	120.2											$	181.8					$	187.6

	General partner		$	21.9											$	34.7					$	35.7

BASIC EARNINGS PER UNIT:
	Number of units used in denominator			232.7									23.2	(a)		364.2			10.0	(s)		374.2

													2.0	(b)
													2.2	(c)
													104.1	(f)
	Income from continuing operations		$	0.52											$	0.50					$	0.50

DILUTED EARNINGS PER UNIT:
	Number of units used in denominator			233.2									23.2	(a)		364.7			10.0	(s)		374.7

													2.0	(b)
													2.2	(c)
													104.1	(f)
	Income from continuing operations		$	0.52											$	0.50					$	0.50

See Notes to Unaudited Pro Forma Condensed Consolidated Financial Statements.

F-4

ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED PRO FORMA CONDENSED STATEMENT OF CONSOLIDATED OPERATIONS

For the Year Ended December 31, 2003


									South Texas
									Midstream								Adjustments			Adjusted
			Enterprise			GulfTerra			Assets		Pro Forma			Enterprise			Due to this			Enterprise
			Historical			Historical			Historical		Adjustments			Pro Forma			Offering			Pro Forma

REVENUES			$	5,346.4		$	871.5		$	1,430.7	$	(431.9	)(m)	$	7,153.0					$	7,153.0
												(63.7	)(q)
COSTS AND EXPENSES
Operating costs and expenses				5,046.8			557.0			1,423.2		153.0	(k)		6,633.1						6,633.1
												(1.5	)(l)
												(427.2	)(m)
												(54.5	)(p)
												(63.7	)(q)
Selling, general and administrative				37.5								54.5	(p)		92.0						92.0

		Total		5,084.3			557.0			1,423.2		(339.4	)		6,725.1						6,725.1

EQUITY IN INCOME (LOSS) OF UNCONSOLIDATED AFFILIATES				(14.0	)							11.4	(p)		(2.6	)					(2.6	)

OPERATING INCOME				248.1			314.5			7.5		(144.8	)		425.3						425.3

OTHER INCOME (EXPENSE)
Interest expense				(140.8	)		(127.8	)				16.0	(a)		(284.2	)	$	9.1	(s)		(275.1	)
												(10.5	)(e)
												(62.3	)(g)
												(37.7	)(h)
												3.9	(i)
												75.0	(j)
Loss due to early redemptions of debt							(36.9	)							(36.9	)					(36.9	)
Earnings from unconsolidated affiliates							11.4					(11.4	)(p)
Other, net				6.4			1.1			0.1		0.8	(o)		8.4						8.4

		Total		(134.4	)		(152.2	)		0.1		(26.2	)		(312.7	)		9.1			(303.6	)

PROVISION FOR INCOME TAXES				(5.3	)										(5.3	)					(5.3	)
MINORITY INTEREST				(3.9	)		(0.9	)				0.9	(d)		(3.9	)					(3.9	)

INCOME FROM CONTINUING OPERATIONS			$	104.5		$	161.4		$	7.6	$	(170.1	)	$	103.4		$	9.1		$	112.5

INCOME ALLOCATION:
	Limited partners		$	83.8										$	67.1					$	75.1

	General partner		$	20.7										$	36.3					$	37.4

BASIC EARNINGS PER UNIT:
	Number of units used in denominator			199.9								37.5	(a)		350.3			10.0	(s)		360.3

												2.0	(b)
												2.2	(c)
												4.2	(e)
												104.5	(f)
	Income from continuing operations		$	0.42										$	0.19					$	0.21

DILUTED EARNINGS PER UNIT:
	Number of units used in denominator			206.4								37.5	(a)		356.8			10.0	(s)		366.8

												2.0	(b)
												2.2	(c)
												4.2	(e)
												104.5	(f)
	Income from continuing operations		$	0.41										$	0.19					$	0.20

See Notes to Unaudited Pro Forma Condensed Consolidated Financial Statements.

F-5

ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED BALANCE SHEET

September 30, 2004


												Adjustments			Adjusted
			Enterprise			Pro Forma			Enterprise			Due to this			Enterprise
			Historical			Adjustments			Pro Forma			Offering			Pro Forma

ASSETS
Current Assets
	Cash and cash equivalents		$	146.6		$	39.6	(b)	$	234.0		$	278.4	(s)	$	234.0
							49.3	(c)					(11.9	)(s)
							1,984.5	(h)					(266.5	)(s)
							(1,984.5	)(h)
							(1.5	)(r)
	Restricted cash, including $1.1 billion held in escrow for tender offers			1,116.9			(1,073.3	)(j)		43.6						43.6
	Accounts and notes receivable, net			828.7			3.7	(r)		832.4						832.4
	Inventories			327.0			1.9	(r)		328.9						328.9
	Assets held for sale			37.2						37.2						37.2
	Other current assets			72.3			(8.5	)(r)		63.8						63.8

		Total Current Assets		2,528.7			(988.8	)		1,539.9			—			1,539.9
Property, plant and equipment, net				7,723.7			(10.4	)(r)		7,713.3						7,713.3
Investments in and Advances to Unconsolidated Affiliates				464.3			(6.6	)(r)		457.7						457.7
Intangible Assets, net				961.9			29.5	(r)		991.4						991.4
Goodwill				445.9			16.8	(r)		462.7						462.7
Other Assets				58.9						58.9						58.9

		Total Assets	$	12,183.4		$	(959.5	)	$	11,223.9		$	—		$	11,223.9

LIABILITIES & PARTNERS’ EQUITY
Current Liabilities
	Current maturities of debt		$	607.2					$	607.2			(265.5	)(s)	$	341.7
	Accounts payable			107.7						107.7						107.7
	Accrued gas payables			921.1		$	11.2	(r)		932.3						932.3
	Other current liabilities			180.1			(25.9	)(j)		162.5						162.5
							8.3	(r)

		Total Current Liabilities		1,816.1			(6.4	)		1,809.7			(265.5	)		1,544.2
Long-Term Debt				4,972.2			1,984.5	(h)		3,924.8			(1.0	)(s)		3,923.8
							(1,984.5	)(h)
							(1,047.4	)(j)
Other Long-Term Liabilities				54.2			5.4	(r)		59.6						59.6
Minority Interest				61.3						61.3						61.3
Commitments and Contingencies Partners’ Equity
	Limited Partners			5,164.4			38.8	(b)		5,251.5			261.1	(s)		5,512.6
							48.3	(c)
	General Partner			105.4			0.8	(b)		107.2			5.4	(s)		112.6
							1.0	(c)
	Accumulated other comprehensive income			24.1						24.1						24.1
	Other			(14.3	)					(14.3	)					(14.3	)

	Total Combined Equity			5,279.6			88.9			5,368.5			266.5			5,635.0

		Total Liabilities & Combined Equity	$	12,183.4		$	(959.5	)	$	11,223.9		$	—		$	11,223.9

See Notes to Unaudited Pro Forma Condensed Consolidated Financial Statements.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED PRO FORMA CONDENSED

CONSOLIDATED FINANCIAL STATEMENTS

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

Completion of the GulfTerra Merger Transactions


	*General*

On September 30, 2004, Enterprise and GulfTerra completed the merger of GulfTerra with a wholly-owned subsidiary of Enterprise, with GulfTerra being the surviving entity thereof. Additionally, Enterprise completed certain other transactions related to the merger, including the contribution by Enterprise’s general partner (“Enterprise GP”) of a 50% membership interest in GulfTerra’s general partner (“GulfTerra GP”), which was acquired by Enterprise GP from El Paso, and the purchase of certain midstream energy assets located in South Texas from El Paso. The aggregate value of the total consideration Enterprise paid or issued to complete the GulfTerra Merger Transactions was approximately $4 billion. These transactions were accounted for using purchase accounting.

Our September 30, 2004 Unaudited Condensed Consolidated Balance Sheet reflects the GulfTerra merger. Since the GulfTerra Merger Transactions closed during the day of September 30, 2004, our Unaudited Condensed Statements of Consolidated Operations and Comprehensive Income do not include any earnings from GulfTerra due to the immateriality of the amounts. Pursuant to written agreements, the effective closing date of our purchase of the South Texas midstream assets was September 1, 2004. Our Unaudited Condensed Statements of Consolidated Operations and Comprehensive Income for the three and nine months ended September 30, 2004 include one month of results of operations from the South Texas midstream assets.

As a result of the GulfTerra Merger Transactions, GulfTerra and GulfTerra GP became wholly-owned subsidiaries of Enterprise on September 30, 2004. On October 1, 2004, we contributed our ownership interests in GulfTerra and GulfTerra GP to our Operating Partnership, which resulted in GulfTerra and GulfTerra GP becoming wholly-owned subsidiaries of the Operating Partnership.


	*Overview of the GulfTerra Assets and the South Texas Midstream Assets*

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

In addition, GulfTerra has interests in seven multi-purpose offshore hub platforms in the Gulf of Mexico, including the recently completed Marco Polo TLP. 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.

GulfTerra also owns two salt dome natural gas storage facilities in Mississippi that are connected to five interstate pipeline systems, have a combined current working capacity of 13.5 billion cubic feet (“Bcf”) and are capable of delivering in excess of 1.2 Bcf per day of natural gas. In addition, GulfTerra has the exclusive right to use a natural gas storage facility in South Texas under an operating lease that expires in January 2008.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED PRO FORMA CONDENSED

CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

This facility has a working gas capacity of 6.4 Bcf and a maximum withdrawal capacity of 0.8 Bcf per day of natural gas.

In addition, GulfTerra owns interests in five offshore crude oil pipeline systems, which extend over 800 miles, including the recently completed 390-mile Cameron Highway oil pipeline. GulfTerra also owns over 1,000 miles of intrastate NGL pipelines and four NGL fractionation plants in Texas and a 3.3 million barrel (“MMBbl”) propane storage facility in Mississippi; and, owns or leases NGL storage facilities in Louisiana and Texas with aggregate capacity of approximately 21.3 MMBbls. GulfTerra also owns interests in four minor oil and natural gas producing properties located in the Gulf of Mexico offshore Louisiana.

The South Texas midstream assets purchased from El Paso consist of nine natural gas processing plants with a combined capacity of 1.9 Bcf per day, a 294-mile natural gas gathering system, a natural gas treating facility with a capacity of 150 MMcf per day and a small NGL pipeline.


	*The GulfTerra Merger Transactions*

The GulfTerra Merger Transactions occurred in several interrelated steps as described below.


	•	Step One. On December 15, 2003, Enterprise purchased a 50% membership interest in GulfTerra GP from El Paso for $425 million in cash. GulfTerra GP owned a 1% general partner interest in GulfTerra. Prior to completion of the GulfTerra Merger Transactions, Enterprise accounted for its investment in GulfTerra GP using the equity method of accounting. The $425 million in funds required to complete Step One were borrowed under an Interim Term Loan and our pre-merger revolving credit facilities. This borrowed amount was fully repaid with the net proceeds from equity offerings completed during the first nine months of 2004.

	•	Step Two. On September 30, 2004, the GulfTerra merger was consummated and GulfTerra and GulfTerra GP became wholly-owned subsidiaries of Enterprise. Step Two of the GulfTerra Merger Transactions included the following:


	•	Immediately prior to closing the GulfTerra merger, Enterprise GP acquired El Paso’s remaining 50% membership interest in GulfTerra GP for $370 million in cash paid to El Paso and the issuance of a 9.9% membership interest in Enterprise GP to El Paso. Subsequently, Enterprise GP contributed this 50% membership interest in GulfTerra GP to us without the receipt of additional general partner interest, common units or other consideration. Enterprise GP borrowed the foregoing $370 million from Dan Duncan LLC (which owns a 4.505% membership interest in Enterprise GP), which obtained the funds from a loan from EPCO (which indirectly owns an 85.595% membership interest in Enterprise GP).

	•	Immediately prior to closing the GulfTerra merger, Enterprise paid $500 million in cash to El Paso for 10,937,500 Series C units of GulfTerra and 2,876,620 common units of GulfTerra. The remaining 57,762,369 GulfTerra common units (7,433,425 of which were owned by El Paso) were converted into 104,549,823 Enterprise common units (13,454,499 of which are held by El Paso) at the time of the consummation of the GulfTerra merger.


	•	Step Three. Immediately after Step Two was completed, Enterprise acquired the South Texas midstream assets from El Paso for $155.3 million in cash, which was effective September 1, 2004 and is subject to post-closing adjustments.

In connection with the closing of the GulfTerra Merger Transactions, on September 30, 2004, our Operating Partnership borrowed an aggregate of $2.8 billion under its 364-Day Acquisition Revolving Credit Facility and Multi-Year Revolving Credit Facility (collectively referred to as the “Merger Revolving Credit Facilities”) in order to fund its cash payment obligations under Step Two and Step Three of the GulfTerra

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED PRO FORMA CONDENSED

CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Merger Transactions, including the tender offers for GulfTerra’s outstanding senior and senior subordinated notes.

The total consideration paid or granted for the GulfTerra Merger Transactions is summarized below:


Step One transaction:
	Cash payment by Enterprise to El Paso for initial 50% membership interest in GulfTerra GP (a non-voting interest) made in December 2003		$	425.0

		Total Step One consideration		425.0

Step Two transactions:
	Cash payment by Enterprise to El Paso for 10,937,500 GulfTerra Series C units and 2,876,620 GulfTerra common units			500.0
	Fair value of equity interests granted to acquire remaining 50% membership interest in GulfTerra GP (voting interest)(1)			461.3
	Fair value of Enterprise common units issued in exchange for remaining GulfTerra common units			2,445.4
	Fair value of other Enterprise equity interests granted for unit awards and Series F2 convertible units			4.0
	Fair value of receivable from El Paso for transition support payments(2)			(40.3	)
	Transaction fees and other direct costs incurred by Enterprise as a result of the GulfTerra Merger Transactions(3)			24.1

		Total Step Two consideration		3,394.5

		Total Step One and Step Two consideration		3,819.5

Step Three transaction:
	Purchase of South Texas midstream assets from El Paso			155.3

		Total consideration for Steps One through Three	$	3,974.8


(1)	This preliminary fair value is based on 50% of an implied $922.7 million total value of GulfTerra GP, which assumes that the $370 million cash payment made by Enterprise GP to El Paso represented consideration for a 40.1% interest in GulfTerra GP. The 40.1% interest was derived by deducting the 9.9% membership interest in Enterprise GP granted to El Paso in this transaction from the 50% membership interest in GulfTerra GP that Enterprise GP received. The preliminary fair value of $461.3 million assigned to this voting membership interest in GulfTerra GP compares favorably to the $425 million paid to El Paso by Enterprise to purchase its initial 50% non-voting membership interest in GulfTerra GP in December 2003.

(2)	Reflects the present value of a contract-based receivable from El Paso received as part of the negotiated net consideration reached in Step One of the GulfTerra Merger Transactions. The agreements between Enterprise and El Paso provide that for a period of three years following the closing of the GulfTerra merger, El Paso 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 receivable from El Paso has been discounted to fair value and recorded as a reduction in the purchase consideration for GulfTerra. As of September 30, 2004, the fair value of the current portion and non-current portion of this contract-based receivable was $17.2 million and $23.1 million, respectively; these amounts are reflected as a component

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED PRO FORMA CONDENSED

CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	of “Prepaid and other current assets” and “Other assets” on our historical Unaudited Condensed Consolidated Balance Sheet as of September 30, 2004 presented herein.

(3)	As a result of the GulfTerra Merger Transactions, Enterprise incurred expenses of approximately $24 million for various transaction fees and other direct costs. These direct costs include fees for legal, accounting, printing, financial advisory and other services rendered by third-parties to Enterprise over the course of the GulfTerra Merger Transactions. This amount also includes $3.4 million of involuntary severance costs.

Allocation of purchase price of GulfTerra Merger Transactions

The GulfTerra Merger Transactions were recorded using the purchase method of accounting. Purchase accounting requires us to allocate the cost of a business combination to the assets acquired and liabilities assumed based on their estimated fair values. Enterprise has engaged an independent third-party business valuation expert to assess the fair value of GulfTerra’s and the South Texas midstream asset’s tangible and intangible assets. This information will assist management in the development of a definitive allocation of the overall purchase price of the GulfTerra Merger Transactions.

The preliminary fair values shown in the following table are estimates based on information available to management at December 31, 2004. Subsequent to September 30, 2004, we made purchase price adjustments of $1.5 million related to additional transaction fees associated with the GulfTerra Merger Transactions. Additionally, we adjusted our initial preliminary purchase price allocation to property, plant and equipment, intangible assets, goodwill and other various assets and liabilities we assumed in the GulfTerra Merger Transactions. The subsequent adjustments are reflected as pro forma adjustments on our Unaudited Pro Forma Condensed Consolidated Balance Sheet at September 30, 2004. The fair value conclusions related to the GulfTerra Merger Transactions may be updated further when the underlying valuation study is finalized and we have completed our review of all other related information.



				GulfTerra Merger Transactions

							Purchase of
				Merger			South Texas
				with			Midstream
				GulfTerra			Assets			Total

Purchase price allocation:
	Assets acquired in business combination:
		Current assets, including cash of $40,453		$	202.3		$	7.6		$	209.9
		Property, plant and equipment, net			4,579.7			121.5			4,701.2
		Investments in and advances to unconsolidated affiliates			202.7						202.7
		Intangible assets			705.5			29.1			734.6
		Other assets			27.5						27.5

			Total assets acquired		5,717.7			158.2			5,875.9

	Liabilities assumed in business combination:
		Current liabilities			(215.0	)		(2.9	)		(217.9	)
		Long-term debt, including current maturities(1)			(2,015.6	)					(2,015.6	)
		Other long-term liabilities			(47.9	)					(47.9	)

			Total liabilities assumed		(2,278.5	)		(2.9	)		(2,281.4	)

			Total assets acquired less liabilities assumed		3,439.2			155.3			3,594.5
			Total consideration for Steps One through Three		3,819.5			155.3			3,974.8

	Goodwill			$	380.3		$	—		$	380.3

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED PRO FORMA CONDENSED

CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(1)

Represents GulfTerra’s outstanding senior and senior secured note obligations prior to the completion of Enterprise’s tender offers on October 5, 2004. This amount also includes GulfTerra’s outstanding obligations under its revolving credit facility and secured term loans prior to Enterprise’s repayment of these debt obligations, which occurred on the GulfTerra Merger Transactions closing date.

As a result of the preliminary purchase price allocation for Step Two and Step Three of the GulfTerra Merger Transactions, we recorded $734.6 million of amortizable intangible assets, primarily those related to customer relationships and contracts. The remaining preliminary amount represents goodwill of $380.3 million associated with our view of the future results from GulfTerra’s operations, based on the strategic location of GulfTerra’s assets as well as their industry connections.

Pro Forma Adjustments

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

(a) During the first nine months of 2004, Enterprise issued 37,484,241 common units in public sales of common units and in connection with its DRIP and related programs, which generated aggregate net proceeds of approximately $755.9 million. The issuance of common units was as follows:


	•	1,053,861 common units issued in February 2004 in connection with the DRIP and related programs. Including our general partner’s related 2% capital contribution, total net proceeds from this offering were $23.1 million. Enterprise used the net proceeds from this offering for general partnership purposes.

	•	17,250,000 common units sold to the public and 1,757,347 common units issued in connection with the DRIP and related programs in May 2004. Including our general partner’s related 2% capital contribution, total net proceeds from these offerings were $388.4 million. Enterprise used $353.1 million of the net proceeds from such public offering to repay its $225 million Interim Term Loan and to temporarily reduce borrowings outstanding under its then existing revolving credit facilities by approximately $130 million. Enterprise used the $35.3 million in net proceeds received in connection with its DRIP for general partnership purposes.

	•	17,250,000 common units sold to the public and 173,033 common units issued in connection with the DRIP and related programs in August 2004. Including our general partner’s related 2% capital contribution, total net proceeds from these offerings were $344.4 million. Enterprise used $210 million of the net proceeds from such public offering to temporarily reduce borrowings outstanding under its then existing revolving credit facilities and the remainder to fund its payment obligations to El Paso in connection with Step Two of the GulfTerra Merger Transactions.

As a result of the February, May and August 2004 offerings described above, the weighted-average number of common units outstanding increased 23.2 million for the nine months ended September 30, 2004 and 37.5 million for the year ended December 31, 2003. Since the receipt of proceeds from these offerings and the related increases in partners’ equity are already reflected in Enterprise’s historical consolidated balance sheet at September 30, 2004, no pro forma adjustments to the balance sheet are necessary.

As a result of the use of proceeds from these offerings, pro forma interest expense decreased $5.1 million for the nine months ended September 30, 2004 and $16.0 million for the year ended December 31, 2003. In calculating the pro forma adjustment to interest expense for the nine months ended September 30, 2004, we used an average historical variable interest rate of 1.8%, which was determined by reference to the debt obligations that were either completely repaid or temporarily reduced using proceeds from such offerings. In calculating the pro forma adjustment to interest expense for the year ended December 31, 2003, we used a weighted-average estimated variable interest rate of 3.0% based on a combination of the 3.4% estimated variable

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED PRO FORMA CONDENSED

CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

interest rate we are currently being charged on amounts borrowed under our Merger Revolving Credit Facilities and average historical variable interest rates of other debt obligations that would have been temporarily reduced using proceeds from such offerings. If the variable interest rates used to determine the pro forma adjustments to interest expense were 1/8% higher, the pro forma reduction in interest expense would have been $5.5 million for the nine months ended September 30, 2004 and $16.7 million for the year ended December 31, 2003.

The pro forma adjustment to interest expense for the year ended December 31, 2003 also reflects the write-off of $1 million in prepaid debt issuance costs resulting from the repayment of Enterprise’s Interim Term Loan. The removal of the debt issuance costs is already reflected in Enterprise’s historical statement of consolidated operations for the nine months September 30, 2004; therefore, no pro forma adjustment is required for the interim period.

(b) In May 2003, GulfTerra issued 80 Series F convertible units in a registered offering to an institutional investor. Each Series F convertible unit was comprised of two separate detachable units — a Series F1 convertible unit and Series F2 convertible unit — that had identical terms except for vesting and termination dates and the number of common units into which they could be converted upon payment of the calculated purchase price per common unit. Prior to the GulfTerra merger, all the Series F1 convertible units were converted to GulfTerra common units by the holder. As a result of the GulfTerra merger, Enterprise assumed GulfTerra’s obligation associated with the Series F2 convertible units. All Series F2 convertible units outstanding at the merger date were converted into rights to purchase Enterprise common units. The Series F2 units were convertible into up to $40 million of Enterprise common units.

On October 29, 2004, 60 of the 80 outstanding Series F2 convertible units were converted into 1,458,434 Enterprise common units. On November 8, 2004, the remaining 20 outstanding Series F2 convertible units were converted into 491,883 Enterprise common units. As a result of these conversions, Enterprise received net proceeds of approximately $39.6 million, which includes the related 2% capital contributions made by Enterprise’s general partner. Enterprise used the net proceeds from these conversions for general partnership purposes. As a result of these transactions, the weighted-average number of common units outstanding increased 2 million for the nine months ended September 30, 2004 and the year ended December 31, 2003.

(c) Reflects Enterprise’s November 2004 issuance of 2,199,350 Enterprise common units in connection with its DRIP and related programs. Including our general partner’s related 2% capital contribution, total net proceeds from this offering were $49.3 million. Enterprise used the net proceeds for general partnership purposes. As a result of this offering, the weighted-average number of common units outstanding increased 2.2 million for the nine months ended September 30, 2004 and the year ended December 31, 2003.

(d) 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% direct interest in the Operating Partnership to a 2% direct interest in Enterprise in December 2003. 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 Partnership during 2003. As a result of this adjustment, Enterprise’s allocation of earnings to its general partner increases by a similar amount.

(e) Reflects the pro forma adjustment to interest expense related to the $425 million borrowed by Enterprise to finance its December 15, 2003 purchase of a 50% membership interest in GulfTerra’s general partner (Step One of the GulfTerra Merger Transactions). This transaction was financed by $225 million borrowed under Enterprise’s Interim Term Loan (which was repaid using proceeds from our May 2004 public offering of common units — see Note (a)) and $200 million borrowed under its then existing revolving credit facilities. The $425 million borrowed to complete Step One of the GulfTerra Merger Transactions was

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED PRO FORMA CONDENSED

CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

subsequently reduced by $100 million using net proceeds from a private offering of 4,413,549 Class B special units to an affiliate of EPCO in December 2003.

If this net borrowing of $325 million had occurred on January 1, 2003, pro forma interest expense for the year ended December 31, 2003 would have increased by $10.5 million. In calculating the pro forma adjustment to interest expense, we used an estimated variable interest rate of 3.4%, which approximates the interest rate we are currently being charged on amounts borrowed under our Merger Revolving Credit Facilities. If this estimated interest rate were 1/8% higher, the pro forma adjustment to interest expense would be $10.9 million.

Enterprise’s September 30, 2004 historical consolidated balance sheet and statement of consolidated operations for the nine months ended September 30, 2004 already reflect the impact of such investment in GulfTerra GP; therefore, no pro forma adjustments are required. The pro forma effect of the December 2003 issuance of Class B special units on the weighted-average number of Enterprise units outstanding was an increase of 4.2 million units for the year ended December 31, 2003.

(f) Reflects the pro forma adjustment to common units outstanding resulting from the issuance of 104,549,823 Enterprise common units in the exchange with GulfTerra’s common unitholders on September 30, 2004 under Step Two of the GulfTerra Merger Transactions. The pro forma effect of these new common units on the weighted-average number of Enterprise units outstanding is an increase of 104.1 million common units for the nine months ended September 30, 2004 and 104.5 million common units for the year ended December 31, 2003.

(g) On September 30, 2004, Enterprise borrowed approximately $2.8 billion under its Merger Revolving Credit Facilities to (i) fund $655.3 million in cash payment obligations to El Paso under Step Two and Step Three of the GulfTerra Merger Transactions, (ii) escrow $1.1 billion in cash to finance its tender offers for GulfTerra’s senior and senior subordinated notes and (iii) repay $962 million outstanding under GulfTerra’s revolving credit facility and secured term loans on the merger closing date.

The pro forma adjustment to interest expense resulting from these borrowings is $42.6 million for the nine months ended September 30, 2004 and $62.3 million for the year ended December 31, 2003. In calculating the pro forma adjustment to interest expense, we used an estimated variable interest rate of 3.4%, which approximates the interest rate we are currently being charged on amounts borrowed under our Merger Revolving Credit Facilities. If this estimated interest rate were 1/8% higher, the pro forma adjustment to interest expense would be $45.0 million for the nine months ended September 30, 2004 and $65.5 million for the year ended December 31, 2003. The pro forma adjustment to interest expense also reflects the removal of historical interest expense amounts recorded by GulfTerra on its revolving credit facility and secured term loans of $22.5 million for the nine months ended September 30, 2004 and $24.7 million for the year ended December 31, 2003. Enterprise’s September 30, 2004 historical balance sheet already reflects these borrowings; therefore, no pro forma adjustment is required.

(h) On October 4, 2004, the Operating Partnership issued $2 billion of senior unsecured notes in a private offering. The net proceeds from this offering were used to reduce debt outstanding under the Merger

F-13

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED PRO FORMA CONDENSED

CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Revolving Credit Facilities. The fixed-interest rate, principal amount issued and net proceeds (before offering expenses) of each senior note in this offering were as follows:


	Fixed						Proceeds to
	Interest		Principal		Bond		Us, Before
Senior Note Issued	Rate		Amount		Discount		Expenses

Senior Notes E, due October 2007		4.000%	$	500.0	$	2.1	$	497.9
Senior Notes F, due October 2009		4.625%		500.0		4.4		495.6
Senior Notes G, due October 2014		5.600%		650.0		4.8		645.2
Senior Notes H, due October 2034		6.650%		350.0		4.2		345.8

Totals			$	2,000.0	$	15.5	$	1,984.5

After giving effect to the application of proceeds to reduce principal amounts outstanding under our variable-rate Merger Revolving Credit Facilities, the pro forma adjustment to interest expense resulting from the issuance of these senior notes is $28.4 million for the nine months ended September 30, 2004 and $37.7 million for the year ended December 31, 2003. If the variable-rates used to calculate the reduction in interest expense associated with the repayment of amounts outstanding under the Merger Revolving Credit Facilities were 1/8% higher, the pro forma adjustment to interest expense would have been $26.6 million for the nine months ended September 30, 2004 and $35.2 million for the year ended December 31, 2003.

The pro forma adjustments to Enterprise’s September 30, 2004 consolidated balance sheet reflect the issuance of these senior notes and the subsequent repayment of $2 billion in principal amounts outstanding under the Merger Revolving Credit Facilities.

(i) During the first nine months of 2004, we entered into eight forward-starting interest rate swap transactions having an aggregate notional amount of $2 billion in anticipation of financing activities associated with closing the GulfTerra Merger Transactions. Our purpose in entering into these transactions was to effectively hedge the underlying U.S. treasury rate related to our expected issuance of $2 billion of fixed-rate debt. On October 4, 2004, the Operating Partnership issued $2 billion of senior unsecured notes in a private offering (see Note (h)). Each of the forward starting swaps was designated as a cash flow hedge in accordance with applicable accounting guidance.

In April 2004, we elected to terminate the initial four forward-starting swaps in order to manage and maximize the value of the swaps and to reduce future debt service costs. As a result, we received $104.5 million in cash from the counterparties. In September 2004, we settled the remaining four swaps resulting in an $85.1 million payment to the counterparties. The net gain of $19.4 million from these settlements was recorded in Accumulated Other Comprehensive Income and will be amortized over the life of the associated debt as a reduction in interest expense and Accumulated Other Comprehensive Income. The pro forma amortization of this gain reduced interest expense by $3 million for the nine months ended September 30, 2004 and $3.9 million for the year ended December 31, 2003. No pro forma adjustment to the condensed consolidated balance sheet is required.

(j) On October 4, 2004, all of the cash tender offers made by the Operating Partnership for any and all of GulfTerra’s outstanding senior and senior subordinated notes expired. As of the expiration time, the Operating Partnership had received tenders of such notes aggregating $915 million, or 99.3% of the notes outstanding. On October 5, 2004, the Operating Partnership purchased the notes for a total price of approximately $1.1 billion using cash held in escrow that was borrowed on September 30, 2004 under the Merger Revolving Credit Facilities. The following table shows the four GulfTerra senior debt obligations

F-14

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED PRO FORMA CONDENSED

CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

affected, including the principal amount of each series of notes tendered, as well as the payment made by Enterprise to complete the tender offers.



				Cash Payments Made by Enterprise
		Principal
		Amount		Accrued		Tender		Total
Description		Tendered		Interest		Price		Price

8.50% Senior Subordinated Notes due 2010 (Represents 98.2% of principal amount outstanding)		$	212.1	$	6.2	$	246.4	$	252.6
10.625% Senior Subordinated Notes due 2012 (Represents 99.9% of principal amount outstanding)			133.9		4.9		167.6		172.5
8.50% Senior Subordinated Notes due 2011 (Represents 99.5% of principal amount outstanding)			319.8		9.4		359.4		368.8
6.25% Senior Notes due 2010 (Represents 99.7% of principal amount outstanding)			249.3		5.4		274.0		279.4

	Totals	$	915.1	$	25.9	$	1,047.4	$	1,073.3

The pro forma adjustments to Enterprise’s September 30, 2004 consolidated balance sheet reflect the use of $1.1 billion of restricted cash to complete the tender offers.

The pro forma adjustments to interest expense reflect the removal of historical interest expense amounts recorded by GulfTerra associated with such senior note obligations. These adjustments decreased pro forma fixed-rate interest expense by $56.3 million for the nine months ended September 30, 2004 and $75 million for the year ended December 31, 2003.

(k) Reflects the pro forma depreciation and amortization adjustment for GulfTerra’s and the South Texas midstream assets’ property, plant and equipment and intangible assets based on the preliminary purchase price allocation for the GulfTerra Merger Transactions (see page F-10). For purposes of calculating pro forma depreciation expense, we applied the straight-line method using estimated remaining useful lives ranging from 10 years to 33 years (depending on the type of asset) to Enterprise’s new basis in such assets of approximately $4.7 billion.

In addition, Enterprise recorded $734.6 million of amortizable intangible assets, which are primarily comprised of the fair value of certain customer relationships and storage contracts. For purposes of calculating pro forma amortization expense related to the customer relationships, we used a pattern in which the economic benefits are consumed or otherwise used as associated with the resource bases (i.e., the oil and gas reserves associated with the intangible assets) from which these customers produce. For purposes of calculating pro forma amortization expense related to the storage contracts, we applied the straight-line method to the remainder of the respective contract terms, which we estimate could range from 2 to 18 years.

Overall, the pro forma depreciation and amortization expense adjustment was $103.2 million for the nine months ended September 30, 2004 and $153.0 million for the year ended December 31, 2003, after taking into account the historical expense amounts recorded by GulfTerra and the South Texas midstream assets.

(l) Reflects the pro forma adjustment to remove $20 million in merger-related expenses recorded by GulfTerra during the nine months ended September 30, 2004, including $0.4 million related to the amortization of unit options that were extinguished immediately prior to the GulfTerra merger. The pro forma adjustment for year ended December 31, 2003 reflects the removal of $1.5 million of amortization expense associated with the GulfTerra unit options.

(m) In accordance with the purchase and sale agreement between Enterprise and El Paso for the South Texas midstream assets, El Paso will retain a number of natural gas liquids marketing contracts. Enterprise’s

F-15

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED PRO FORMA CONDENSED

CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

pro forma condensed statement of consolidated operations for the nine months ended September 30, 2004 includes adjustments to remove $426.6 million of revenues and $421.5 million of operating costs and expenses associated with these retained contracts. Likewise, for the year ended December 31, 2003, Enterprise’s pro forma condensed statement of consolidated operations includes adjustments to remove $431.9 million of revenues and $427.2 million of operating costs and expenses.

(n) After Step Two of the GulfTerra Merger Transactions was completed on September 30, 2004, the general partner of GulfTerra became a wholly-owned subsidiary of Enterprise. This pro forma adjustment reflects the replacement of equity earnings from the general partner of GulfTerra that Enterprise recorded under Step One of the merger with consolidated earnings from GulfTerra, as if Step Two had occurred on January 1, 2003. This adjustment required the removal of $32 million of equity earnings from the general partner of GulfTerra that Enterprise recorded during the nine months ended September 30, 2004. Since Enterprise’s equity in the earnings of GulfTerra GP was a loss of less than $0.1 million for December 2003, no pro forma adjustment was made for the 2003 period due to the insignificant nature of the amount. Enterprise acquired its initial 50% membership interest in the general partner of GulfTerra on December 15, 2003 under Step One of the GulfTerra Merger Transactions.

(o) In connection with the GulfTerra Merger Transactions, Enterprise recorded the present value of a contract-based receivable from El Paso totaling $40.3 million, which was part of the negotiated net consideration reached in Step Two of the GulfTerra Merger Transactions. Our pro forma condensed statements of consolidated operations reflect $1.2 million and $0.8 million of imputed interest income that would have been recognized from this agreement during the nine months ended September 30, 2004 and the year ended December 31, 2003, respectively.

(p) Reflects pro forma classification adjustments necessary to conform GulfTerra’s and the South Texas midstream assets’ historical condensed statements of consolidated operations to Enterprise’s method of presentation. The reclassifications were as follows:


	•	GulfTerra’s and 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. GulfTerra’s and the South Texas midstream assets’ general and administrative costs were $46.5 million for the nine months ended September 30, 2004 and $54.5 million for the year ended December 31, 2003.

	•	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 $7.6 million for the nine months ended September 30, 2004 and by $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. Such investments 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, the relationship between GulfTerra and its equity investees is similar.

(q) Reflects the pro forma elimination of significant revenues and expenses between Enterprise, GulfTerra and the South Texas midstream assets as appropriate in consolidation. Upon completion of the GulfTerra Merger Transactions, GulfTerra and the South Texas midstream assets became wholly-owned subsidiaries of Enterprise.

F-16

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED PRO FORMA CONDENSED

CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Additionally, we agreed in the merger agreement with GulfTerra, subject to the terms of our partnership agreement, to increase the quarterly cash distribution for the quarterly distribution date immediately following the closing of the merger to at least $0.395 per unit, or $1.58 per common unit on an annualized basis. The increase in our quarterly cash distribution commenced with the distribution paid with respect to the third quarter of 2004.

(r) Reflects subsequent purchase price adjustments and purchase price allocations associated with the GulfTerra Merger Transactions since September 30, 2004.

(s) Reflects the sale in this offering of 10,000,000 Enterprise common units at an assumed offering price of $27.28 per unit in February 2005. Total net proceeds from this sale are expected to be approximately $266.5 million after deducting applicable underwriting discounts, commissions and offering expenses of $11.9 million. Included in the total net proceeds of $266.5 million is a net capital contribution made by the general partner of Enterprise of $5.4 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. For pro forma purposes, the net proceeds from this equity offering, including Enterprise’s general partner’s net capital contribution, will be used to reduce debt outstanding under the Merger Revolving Credit Facilities.

As a result of our pro forma application of proceeds from this offering to reduce debt outstanding, pro forma interest expense will decrease by $6.8 million and $9.1 million for the nine months ended September 30, 2004 and year ended December 31, 2003 and, respectively. If the variable rates used to calculate the reduction in interest expense associated with the repayment of amounts outstanding under the Merger Revolving Credit Facilities were 1/8% higher, the pro forma adjustment to interest expense would have been $7 million for the nine months ended September 30, 2004 and $9.4 million for the year ended December 31, 2003.

F-17

PROSPECTUS

(ENTERPRISE PRODUCTS PARTNERS L.P. LOGO)

$1,500,000,000

Enterprise Products Partners L.P.

Enterprise Products Operating L.P.

COMMON UNITS

DEBT SECURITIES

We may offer the following securities under this prospectus:


	•	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.

The date of this prospectus is April 21, 2003.

TABLE OF CONTENTS


			Page

ABOUT THIS PROSPECTUS				iii
OUR COMPANY				1
RISK FACTORS				2
	Risks Related to Our Business			2
		We have significant leverage that may restrict our future financial and operating flexibility		2
		A decrease in the difference between NGL product prices and natural gas prices results in lower margins on volumes processed, which would adversely affect our profitability		2
		A reduction in demand for our products by the petrochemical, refining or heating industries, could adversely affect our results of operations		3
		A decline in the volume of NGLs delivered to our facilities could adversely affect our results of operations		3
		Our business requires extensive credit risk management that may not be adequate to protect against customer nonpayment		4
		Acquisitions and expansions may affect our business by substantially increasing the level of our indebtedness and contingent liabilities and increasing our risks of being unable to effectively integrate these new operations		4
		Terrorist attacks aimed at our facilities could adversely affect our business		4
	Risks Related to Our Common Units as a Result of Our Partnership Structure			4
		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		4
		Cost reimbursements due our general partner may be substantial and will reduce our cash available for distribution to holders of common units		5
		Our general partner and its affiliates have limited fiduciary responsibilities and conflicts of interest with respect to our partnership		5
		Even if unitholders are dissatisfied, they cannot easily remove our general partner		6
		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		6
		We may issue additional common units without the approval of common unitholders, which would dilute their existing ownership interests		6
		Our general partner has a limited call right that may require common unitholders to sell their units at an undesirable time or price		7
		Common unitholders may not have limited liability if a court finds that limited partner actions constitute control of our business		7
	Tax Risks to Common Unitholders			7
		The IRS could treat us as a corporation for tax purposes, which would substantially reduce the cash available for distribution to common unitholders		8
		A successful IRS contest of the federal income tax positions we take may adversely impact the market for common units, and the costs of any contests will be borne by our unitholders and our general partner		8
		Common unitholders may be required to pay taxes even if they do not receive any cash distributions		8
		Tax gain or loss on disposition of common units could be different than expected		8
		Tax-exempt entities, regulated investment companies and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them		9
		We are registered as a tax shelter. This may increase the risk of an IRS audit of us or a unitholder		9
		We will treat each purchaser of common units as having the same tax benefits without regard to the units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units		9
		Common unitholders will likely be subject to state and local taxes in states where they do not live as a result of investment in our common units		9
USE OF PROCEEDS				10
RATIO OF EARNINGS TO FIXED CHARGES				10


		Page

DESCRIPTION OF DEBT SECURITIES			11
	General		11
	Guarantee		12
	Certain Covenants		12
	Events of Default		16
	Amendments and Waivers		17
	Defeasance		19
	Subordination		19
	Book-Entry System		21
	Limitations on Issuance of Bearer Securities		22
	No Recourse Against General Partner		23
	Concerning the Trustee		23
	Governing Law		24
DESCRIPTION OF OUR COMMON UNITS			25
	Meetings/Voting		25
	Status as Limited Partner or Assignee		25
	Limited Liability		25
	Reports and Records		26
	Class A Special Units		26
CASH DISTRIBUTION POLICY			27
	Distributions of Available Cash		27
	Operating Surplus and Capital Surplus		27
	Subordination Period		28
	Distributions of Available Cash from Operating Surplus During the Subordination Period		29
	Distributions of Available Cash from Operating Surplus After Subordination Period		30
	Incentive Distributions		30
	Distributions from Capital Surplus		30
	Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels		31
	Distributions of Cash upon Liquidation		31
DESCRIPTION OF OUR PARTNERSHIP AGREEMENT			34
	Purpose		34
	Power of Attorney		34
	Reimbursements of Our General Partner		34
	Issuance of Additional Securities		34
	Amendments to Our Partnership Agreement		35
	Withdrawal or Removal of Our General Partner		36
	Liquidation and Distribution of Proceeds		36
	Change of Management Provisions		37
	Limited Call Right		37
	Indemnification		37
	Registration Rights		38
TAX CONSEQUENCES			39
	Partnership Status		39
	Limited Partner Status		40
	Tax Consequences of Unit Ownership		41
	Tax Treatment of Operations		45
	Disposition of Common Units		46
	Uniformity of Units		48
	Tax-Exempt Organizations and Other Investors		48
	Administrative Matters		49
	State, Local and Other Tax Considerations		51
	Tax Consequences of Ownership of Debt Securities		51
SELLING UNITHOLDERS			52
PLAN OF DISTRIBUTION			52
	Distribution by Selling Unitholders		53
WHERE YOU CAN FIND MORE INFORMATION			53
FORWARD-LOOKING STATEMENTS			54
LEGAL MATTERS			54
EXPERTS			54

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.

ABOUT THIS PROSPECTUS

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.

iii

OUR COMPANY

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.

RISK FACTORS

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.

Risks Related to Our Business


	*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.


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

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, could adversely affect our results of operations.*

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.


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


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

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.


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

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.


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

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.

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

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.

Such conflicts may include, among others, the following:


	•	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.

Tax Risks to Common Unitholders

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 IRS could treat us as a corporation for tax purposes, which would substantially reduce the cash available for distribution to common unitholders.*

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.

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.

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.


	A successful IRS contest of the federal income tax positions we take may adversely impact the market for common units, and the costs of any contests will be borne by our unitholders and our general partner.

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 may be required to pay taxes even if they do not receive any cash distributions.*

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.


	*Tax gain or loss on disposition of common units could be different than expected.*

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.


	*Tax-exempt entities, regulated investment companies and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.*

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 as a tax shelter. This may increase the risk of an IRS audit of us or a unitholder.*

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.


	We will treat each purchaser of common units as having the same tax benefits without regard to the units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.

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.


	*Common unitholders will likely be subject to state and local taxes in states where they do not live as a result of an investment in our common units.*

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.

USE OF PROCEEDS

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.

RATIO OF EARNINGS TO FIXED CHARGES

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



	Year Ended December 31,

Company	1998		1999		2000		2001		2002

Enterprise Products Partners L.P.		1.16		5.84		6.40		5.10		2.07
Enterprise Products Operating L.P.		1.16		5.90		6.46		5.14		2.08

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.

Add the following:


	•	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.

From the total of the added items, subtract the following:


	•	interest capitalized;

	•	preference security dividend requirements of consolidated subsidiaries; and

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

The term “fixed charges” means the sum of the following:


	•	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.

DESCRIPTION OF DEBT SECURITIES

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.

General

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.

Guarantee

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.

Certain Covenants

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.

In the Indenture, the term “Subsidiary” means:


	(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.

“Permitted Liens” means:


	(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,


	except, in the case of either of the foregoing clauses (1) or (2):


	(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

(excluding Sale-Leaseback Transactions permitted by clauses (1) through (4), inclusive, of the first paragraph of the restriction on sale-leasebacks covenant described below) does not exceed 10% of Consolidated Net Tangible Assets.

“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

(other than the debt securities) secured by liens other than Permitted Liens upon Principal Property, do not exceed 10% of Consolidated Net Tangible Assets.

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.

Events of Default

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

described in clause (4) above occurs and is continuing, the principal of, premium, if any, and accrued and unpaid interest on all the debt securities will become and be immediately due and payable without any declaration or other act on the part of the Trustee or any holders. The holders of a majority in principal amount of the outstanding debt securities of a series may waive all past defaults (except with respect to nonpayment of principal, premium or interest) and rescind any such acceleration with respect to the debt securities of that series and its consequences if rescission would not conflict with any judgment or decree of a court of competent jurisdiction and all existing Events of Default, other than the nonpayment of the principal of, premium, if any, and interest on the debt securities of that series that have become due solely by such declaration of acceleration, have been cured or waived.

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.

Amendments and Waivers

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

debt securities). However, without the consent of each holder of outstanding debt securities of each series affected thereby, no amendment may, among other things:


	(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

notice briefly describing such amendment. However, the failure to give such notice to all the holders, or any defect therein, will not impair or affect the validity of the amendment.

Defeasance

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.

Subordination

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

holders may receive units representing limited partner interests and any debt securities that are subordinated to Senior Indebtedness to at least the same extent as the subordinated debt securities.

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,

unless, in either case,


	•	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.”

Generally, “Designated Senior Indebtedness” will include:


	•	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.

The Payment Blockage Period may be terminated before its expiration:


	•	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.

Book-Entry System

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 has advised us as follows:


	•	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

beneficial owners. The direct and indirect participants will remain responsible for keeping account of their holdings on behalf of their customers.

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.

Limitations on Issuance of Bearer Securities

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.

No Recourse Against General Partner

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.

Concerning the Trustee

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

its rights or powers under the Indenture at the request of any of the holders of debt securities unless they shall have offered to such Trustee reasonable security and indemnity.

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.

Governing Law

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.

DESCRIPTION OF OUR COMMON UNITS

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.

Meetings/ Voting

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

Status as Limited Partner or Assignee

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.

Limited Liability

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

included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act is liable to the limited partnership for the amount of the distribution for three years from the date of the distribution.

Reports and Records

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.

Class A Special Units

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.

CASH DISTRIBUTION POLICY

Distributions of Available Cash

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.

Operating Surplus and Capital Surplus

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.

Subordination Period

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


	•	there are no outstanding common unit arrearages.

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

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.

Distributions from Capital Surplus

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.

Distributions of Cash upon Liquidation

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.

DESCRIPTION OF OUR PARTNERSHIP AGREEMENT

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.”

Purpose

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.

Power of Attorney

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.

Reimbursements of Our General Partner

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.

Issuance of Additional Securities

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

partnership interests may dilute the value of the interests of the then-existing holders of common units in our net assets.

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

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.

Withdrawal or Removal of Our General Partner

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.

Liquidation and Distribution of Proceeds

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

the liquidator deems necessary or desirable in its good faith judgment, liquidate our assets. The proceeds of the liquidation will be applied as follows:


	•	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.

Change of Management Provisions

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.

Limited Call Right

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.

Indemnification

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

partner shall not be personally liable for, or have any obligation to contribute or loan funds or assets to us to enable us to effectuate any indemnification. We are authorized to purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.

Registration Rights

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.

TAX CONSEQUENCES

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”).

Partnership Status

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

year consists of “qualifying income.” Qualifying income includes income and gains derived from the exploration, development, mining or production, processing, refining, transportation and marketing of any mineral or natural resource. Other types of qualifying income include interest other than from a financial business, dividends, gains from the sale of real property and gains from the sale or other disposition of assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than 2% of our current gross income is not qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and the general partner and a review of the applicable legal authorities, counsel is of the opinion that at least 90% of our current gross income constitutes qualifying income.

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.

Limited Partner Status

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.

Tax Consequences of Unit Ownership

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

recourse to the general partner, but will have a share, generally based on his share of profits, of our nonrecourse liabilities. Please read “— Disposition of Common Units — Recognition of Gain or Loss.”

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

investment income to unitholders. In addition, the unitholder’s share of our portfolio income will be treated as investment income.

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

units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:


	•	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

or amortization position under which all purchasers acquiring units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read “— Tax Treatment of Operations — Uniformity of Units.”

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.

Tax Treatment of Operations

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.

Please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction” and “— Disposition of Common Units — Recognition of Gain or Loss.”

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.

Disposition of Common Units

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

electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of common units. We strongly recommend that a unitholder considering the purchase of additional units or a sale of common units purchased in separate transactions consult his tax advisor as to the possible consequences of this ruling and application of the final regulations.

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

our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination.

Uniformity of Units

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.”

Tax-Exempt Organizations and Other Investors

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

partnerships, we will withhold (currently at the rate of 38.6%) on cash distributions made quarterly to foreign unitholders. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8 BEN or applicable substitute form in order to obtain credit for these withholding taxes.

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.

Administrative Matters

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

($10,000 for most corporations). The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:


	(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%.

State, Local and Other Tax Considerations

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.

Tax Consequences of Ownership of Debt Securities

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.

SELLING UNITHOLDERS

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.

PLAN OF DISTRIBUTION

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 by Selling Unitholders

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.

WHERE YOU CAN FIND MORE INFORMATION

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

made by either company with the Commission under section 13(a), 13(c), 14 or 15(d) of the Securities Exchange Act until our offering is completed:


	•	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.

FORWARD-LOOKING STATEMENTS

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.

LEGAL MATTERS

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.

EXPERTS

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

December 31, 2002 and 2001, and for each of the three years in the period ended December 31, 2002, incorporated by reference in this prospectus, and (ii) the balance sheet of Enterprise Products GP, LLC as of December 31, 2002, incorporated by reference in this prospectus, have been audited by Deloitte & Touche LLP, independent auditors, as stated in their reports, which are incorporated by reference herein (each such report expresses an unqualified opinion and the reports for Enterprise Products Partners L.P. and Enterprise Products Operating L.P. each include 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 and Enterprise Products Operating L.P.’s consolidated financial statements, respectively) and have been so incorporated in reliance upon the reports of such firm given upon their authority as experts in accounting and auditing.

(ENTERPRISE PRODUCTS PARTNERS L.P. LOGO)

10,000,000 Common Units

Enterprise Products Partners L.P.

PROSPECTUS SUPPLEMENT

, 2005

UBS Investment Bank

Citigroup

Goldman, Sachs & Co.

Lehman Brothers

Morgan Stanley

Wachovia Securities

A.G. Edwards

Merrill Lynch & Co.

Raymond James

Sanders Morris Harris

RBC Capital Markets

KeyBanc Capital Markets