ENTERPRISE PRODUCTS PARTNERS L P - 10-Q Quarterly Report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2005 or

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _______ to _______.

Commission file number: 1-14323

ENTERPRISE PRODUCTS PARTNERS L.P.

(Exact name of Registrant as specified in its Charter)

Delaware	76-0568219
(State or Other Jurisdiction of	(I.R.S. Employer Identification No.)
Incorporation or Organization)

2727 North Loop West, Houston, Texas 77008-1044
(Address of Principal Executive Offices) (Zip Code)

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

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

YES x NO o

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

YES x NO o

There were 383,265,385 unrestricted common units of Enterprise Products Partners L.P. outstanding at May 4, 2005. Enterprise Products Partners L.P.’s common units trade on the New York Stock Exchange under the symbol “EPD.”

ENTERPRISE PRODUCTS PARTNERS L.P.

TABLE OF CONTENTS

		Page No.
PART I. FINANCIAL INFORMATION.
Item 1.	Financial Statements.
	Unaudited Condensed Consolidated Balance Sheets ....................................	1
	Unaudited Condensed Statements of Consolidated Operations
	and Comprehensive Income ......................................................................	2
	Unaudited Condensed Statements of Consolidated Cash Flows...................	3
	Unaudited Condensed Statements of Consolidated Partners’ Equity ...........	4
	Notes to Unaudited Condensed Consolidated Financial Statements:
	1. General .................................................................................................	5
	2. Recently Issued Accounting Standards ................................................	7
	3. Business Combinations ........................................................................	7
	4. Inventories ............................................................................................	9
	5. Property, Plant and Equipment .............................................................	9
	6. Investments in and Advances to Unconsolidated Affiliates .................	10
	7. Intangible Assets and Goodwill ...........................................................	12
	8. Related Party Transactions ...................................................................	13
	9. Capital Structure ..................................................................................	14
	10. Debt Obligations ..................................................................................	17
	11. Supplemental Cash Flows Disclosure ..................................................	19
	12. Financial Instruments ...........................................................................	20
	13. Business Segment Information ............................................................	20
	14. Earnings Per Unit .................................................................................	25
	15. Condensed Financial Information of Operating Partnership ...............	26
	16. Commitments and Contingencies.........................................................	27
Item 2.	Management's Discussion and Analysis of Financial Condition
	and Results of Operations. ........................................................................	29
Item 3.	Quantitative and Qualitative Disclosures about Market Risk. .................	46
Item 4.	Controls and Procedures. .............................................................................	47

PART II. OTHER INFORMATION.
Item 1.	Legal Proceedings. .........................................................................................	49
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds. ..................	49
Item 3.	Defaults upon Senior Securities. ...................................................................	49
Item 4.	Submission of Matters to a Vote of Security Holders. ...............................	49
Item 5.	Other Information. ........................................................................................	49
Item 6.	Exhibits. ..........................................................................................................	49

Signature page	..........................................................................................................................	55

PART I. FINANCIAL INFORMATION.

ITEM 1. FINANCIAL STATEMENTS.

ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

				March 31,	December 31,
ASSETS				2005	2004

Current assets
	Cash and cash equivalents			$ 57,730	$ 24,556
	Restricted cash			10,358	26,157
	Accounts and notes receivable - trade, net of allowance for doubtful accounts
		of $23,624 at March 31, 2005 and $24,310 at December 31, 2004		946,826	1,058,375
	Accounts receivable - related parties			146	25,161
	Inventories			309,552	189,019
	Assets held for sale				36,562
	Prepaid and other current assets			89,014	80,893
			Total current assets	1,413,626	1,440,723
Property, plant and equipment, net				8,059,247	7,831,467
Investments in and advances to unconsolidated affiliates				557,979	519,164
Intangible assets, net of accumulated amortization of $96,794 at
	March 31, 2005 and $74,183 at December 31, 2004			960,137	980,601
Goodwill				456,694	459,198
Deferred tax asset				8,915	6,467
Long-term receivables				15,144	14,931
Other assets				55,982	62,910
			Total assets	$ 11,527,724	$ 11,315,461

LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
	Current maturities of debt			$ 29,000	$ 15,000
	Accounts payable - trade			56,038	203,142
	Accounts payable - related parties			17,478	41,293
	Accrued gas payables			1,138,257	1,021,294
	Accrued expenses			45,244	130,051
	Accrued interest			66,717	70,335
	Other current liabilities			112,677	104,764
			Total current liabilities	1,465,411	1,585,879
Long-term debt				4,128,303	4,266,236
Other long-term liabilities				78,196	63,521
Minority interest				82,556	71,040
Commitments and contingencies
Partners’ equity
	Common units (383,258,901 units outstanding at March 31, 2005
	and 364,297,340 units at December 31, 2004)			5,642,223	5,204,940
	Restricted common units (501,417 units outstanding at March 31, 2005
	and 488,525 units at December 31, 2004)			12,513	12,327
	Treasury units, at cost (427,200 units outstanding at March 31, 2005
	and December 31, 2004)			(8,660)	(8,660)
	General partner			115,403	106,475
	Accumulated other comprehensive income			22,125	24,554
	Deferred compensation			(10,346)	(10,851)
			Total partners’ equity	5,773,258	5,328,785
			Total liabilities and partners’ equity	$ 11,527,724	$ 11,315,461

See Notes to Unaudited Condensed Consolidated Financial Statements

ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS

AND COMPREHENSIVE INCOME

(Dollars in thousands, except per unit amounts)

	For the Three Months
	Ended March 31,
	2005	2004
REVENUES
Third parties	$ 2,497,329	$ 1,549,587
Related parties	58,193	155,303
Total	2,555,522	1,704,890
COST AND EXPENSES
Operating costs and expenses
Third parties	2,318,529	1,405,983
Related parties	65,115	215,525
Total operating costs and expenses	2,383,644	1,621,508
General and administrative costs
Third parties	5,442	2,572
Related parties	9,251	6,894
Total general and administrative costs	14,693	9,466
Total costs and expenses	2,398,337	1,630,974
EQUITY IN INCOME OF UNCONSOLIDATED AFFILIATES	8,279	14,867
OPERATING INCOME	165,464	88,783
OTHER INCOME (EXPENSE)
Interest expense	(53,413)	(32,618)
Other, net	919	161
Other expense	(52,494)	(32,457)
INCOME BEFORE PROVISION FOR INCOME TAXES,
MINORITY INTEREST AND CHANGES IN ACCOUNTING PRINCIPLES	112,970	56,326
Provision for income taxes	(1,769)	(1,625)
INCOME BEFORE MINORITY INTEREST AND
CHANGES IN ACCOUNTING PRINCIPLES	111,201	54,701
Minority interest	(1,945)	(2,954)
INCOME BEFORE CHANGES IN ACCOUNTING PRINCIPLES	109,256	51,747
Cumulative effect of changes in accounting principles (see Note 1)		10,781
NET INCOME	109,256	62,528
Cash flow financing hedges		16,973
Reclassification (amortization) of cash flow financing hedges	(995)	(102)
Change in fair value of commodity hedges	(1,434)
COMPREHENSIVE INCOME	$ 106,827	$ 79,399

ALLOCATION OF NET INCOME:
Limited partners’ interest in net income	$ 93,723	$ 55,126
General partner interest in net income	$ 15,533	$ 7,402
EARNINGS PER UNIT: (see Note 14)
Basic income per unit before changes in accounting principles	$ 0.25	$ 0.21
Basic income per unit	$ 0.25	$ 0.26
Diluted income per unit before changes in accounting principles	$ 0.25	$ 0.21
Diluted income per unit	$ 0.25	$ 0.26

See Notes to Unaudited Condensed Consolidated Financial Statements

ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Dollars in thousands)

		For the Three Months
		Ended March 31,
		2005	2004
OPERATING ACTIVITIES
Net income		$ 109,256	$ 62,528
Adjustments to reconcile net income to cash flows provided by operating activities:
	Depreciation and amortization in operating costs and expenses	99,965	30,520
	Depreciation in general and administrative costs	1,922	65
	Amortization in interest expense	(477)	798
	Equity in income of unconsolidated affiliates	(8,279)	(14,867)
	Distributions received from unconsolidated affiliates	21,838	16,932
	Cumulative effect of changes in accounting principles		(10,781)
	Operating lease expense paid by EPCO	528	2,274
	Minority interest	1,945	2,954
	Loss (gain) on sale of assets	(5,436)	98
	Deferred income tax expense	1,802	1,687
	Changes in fair market value of financial instruments	102	3
	Decrease in restricted cash used for operating activities	15,799	5,825
	Net effect of changes in operating accounts (see Note 11)	(58,920)	(68,431)
Cash provided by operating activities		180,045	29,605
INVESTING ACTIVITIES
Capital expenditures		(175,230)	(15,216)
Contributions in aid of construction costs		8,942	213
Proceeds from sale of assets		42,158	10
Cash used for business combinations, net of cash received		(150,478)
Acquisition of intangible asset		(1,750)
Investments in and advances to unconsolidated affiliates		(88,634)	(818)
Cash used in investing activities		(364,992)	(15,811)
FINANCING ACTIVITIES
Borrowings under debt agreements		1,382,175	202,000
Repayments of debt		(1,500,979)	(137,000)
Debt issuance costs		(4,425)	(954)
Distributions paid to partners		(164,692)	(91,258)
Distributions paid to minority interests		(1,330)	(779)
Contributions from minority interests		6,327
Proceeds from issuance of common units		501,045	23,142
Treasury units reissued			5,384
Cash provided by financing activities		218,121	535
NET CHANGE IN CASH AND CASH EQUIVALENTS		33,174	14,329
CASH AND CASH EQUIVALENTS, JANUARY 1		24,556	30,466
CASH AND CASH EQUIVALENTS, MARCH 31		$ 57,730	$ 44,795

See Notes to Unaudited Condensed Consolidated Financial Statements

ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED PARTNERS’ EQUITY

(See Note 9 for Unit History and Detail of Changes in Limited Partners’ Equity)

(Dollars in thousands)

						Accumulated
						Other
		Limited	General	Treasury	Deferred	Comprehensive
		Partners	Partner	Units	Compensation	Income	Total
Balance, December 31, 2004		$ 5,217,267	$ 106,475	$ (8,660)	$ (10,851)	$ 24,554	$ 5,328,785
	Net income	93,720	15,536				109,256
	Operating leases paid by EPCO	517	11				528
	Cash distributions to partners	(148,047)	(16,645)				(164,692)
	Proceeds from sales of common units	486,006	9,919				495,925
	Proceeds from exercise of unit options	5,016	102				5,118
	Issuance of restricted units, net	257	5		(260)		2
	Amortization of deferred compensation				765		765
	Change in fair value of commodity
	hedges					(1,434)	(1,434)
	Interest rate hedging financial
	instruments recorded as cash flow
	hedges:
	Amortization of gain as
	component of interest expense					(995)	(995)
Balance, March 31, 2005		$ 5,654,736	$ 115,403	$ (8,660)	$ (10,346)	$ 22,125	$ 5,773,258

See Notes to Unaudited Condensed Consolidated Financial Statements

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. GENERAL

Enterprise Products Partners L.P., including its consolidated subsidiaries, is a publicly traded Delaware limited partnership listed on the NYSE under the ticker symbol “EPD.” Unless the context requires otherwise, references to “we,” “us,” “our,” “the Company” or “Enterprise” are intended to mean the consolidated business and operations of Enterprise Products Partners L.P. Certain abbreviated names, acronyms and other capitalized and industry terms are defined within the glossary following the Table of Contents of our Annual Report on Form 10-K for the year ended December 31, 2004. This glossary is incorporated by reference herein and is filed as Exhibit 99.1 to this quarterly report on Form 10-Q.

We conduct substantially all of our business through our wholly owned subsidiary, Enterprise Products Operating L.P. (our “Operating Partnership”). We are owned 98% by our limited partners and 2% by Enterprise Products GP, LLC (our general partner, referred to as “Enterprise GP”). We and Enterprise GP are affiliates of EPCO, Inc. (“EPCO”).

In the opinion of Enterprise, the accompanying unaudited condensed consolidated financial statements include all adjustments consisting of normal recurring accruals necessary for fair presentation. Although we believe the disclosures in these financial statements are adequate to make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to the rules and regulations of the SEC. These unaudited financial statements should be read in conjunction with our annual report on Form 10-K for the year ended December 31, 2004 (Commission File No. 1-14323).

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

The results of operations for the three months ended March 31, 2005 are not necessarily indicative of results expected for the full year.

Except per unit amounts, or as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars.

Certain reclassifications have been made to the prior year’s financial statements to conform to the current year presentation. In accordance with SFAS No. 3, “Reporting Accounting Changes in Interim Financial Statements,” we have reclassified amounts related to our adoption of EITF 03-16, “Accounting for Investments in Limited Liability Companies,” on July 1, 2004. Our adoption of EITF 03-16 on that date required us to change our method of accounting for our 13.1% investment in VESCO to the equity method from the cost method. Since this change in accounting principle was made during the third quarter of 2004, our statement of consolidated operations and statement of consolidated cash flows for the first quarter of 2004 has been recast for comparability purposes.

The cumulative effect of changes in accounting principles represents the combined impact of changing (i) the method our BEF subsidiary uses to account for its planned major maintenance activities from the accrue-in-advance method to the expense-as-incurred method and (ii) the method we used to account for our investment in VESCO.

In accordance with GAAP, we use estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during each reporting period. Our actual results could differ from these estimates.

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

	For the Three Months
	Ended March 31,
	2005	2004
Reported net income	$ 109,256	$ 62,528
Additional unit option-based compensation
expense estimated using fair value-based method	(138)	(233)
Pro forma net income	109,118	62,295
Less incentive earnings allocations to Enterprise GP	(13,620)	(6,277)
Pro forma net income after incentive earnings allocation	95,498	56,018
Multiplied by Enterprise GP ownership interest	2.0%	2.0%
Standard earnings allocation to Enterprise GP	$ 1,910	$ 1,120

Incentive earnings allocation to Enterprise GP	$ 13,620	$ 6,277
Standard earnings allocation to Enterprise GP	1,910	1,120
Enterprise GP interest in pro forma net income	$ 15,530	$ 7,397

Pro forma net income	$ 109,118	$ 62,295
Less Enterprise GP interest in pro forma net income	(15,530)	(7,397)
Pro forma net income available to limited partners	$ 93,588	$ 54,898

Basic earnings per unit, net of Enterprise GP interest:
Historical units outstanding	373,452	218,463
As reported	$ 0.25	$ 0.26
Pro forma	$ 0.25	$ 0.25
Diluted earnings per unit, net of Enterprise GP interest:
Historical units outstanding	374,206	218,960
As reported	$ 0.25	$ 0.26
Pro forma	$ 0.25	$ 0.25

The fair value of each option grant is estimated on the date of grant using the Black-Scholes option-pricing model and various assumptions. For those options granted during 2005, we used the following assumptions to develop our Black-Scholes model estimates: (i) expected life of options of 7 years; (ii) risk-free interest rate of 3.9%, (iii) expected dividend yield of 9.48% and (iv) expected unit price volatility of 28%.

2. RECENTLY ISSUED ACCOUNTING STANDARDS

SFAS No. 123(R), “Share-Based Payment.” This accounting guidance, which is applicable for public companies the first fiscal year beginning on or after June 15, 2005, replaces SFAS No. 123, “Accounting for Stock-Based Compensation” and supersedes APB No. 25, “Accounting for Stock Issued to Employees.” This Statement eliminates the ability to account for share-based compensation transactions using APB No. 25, and generally requires instead that such transactions be accounted for using a fair-value-based method. We are continuing to evaluate the provisions of SFAS No. 123(R) and will adopt the standard on January 1, 2006. Upon the required effective date, we will apply this statement using a modified version of prospective application as described in the standard.

On March 29, 2005, the SEC issued Staff Accounting Bulletin ("SAB") 107 to provide public companies additional guidance in applying the provisions of SFAS No. 123(R). Among other things, SAB 107 describes the SEC staff’s expectations in determining the assumptions that underlie the fair value estimates and discusses the interaction of SFAS No. 123(R) with certain existing SEC guidance. The guidance is also beneficial to users of financial statements in analyzing the information provided under SFAS No. 123(R). We will apply the provisions of SAB 107 upon the adoption of SFAS No. 123(R).

FIN 46(R)-5, “Implicit Variable Interests Under FASB Interpretation No. 46(R), Consolidation of Variable Interest Entities.” On March 3, 2005, the FASB issued this guidance to address whether a reporting enterprise has an implicit variable interest in a variable interest entity or potential variable interest entity when specific conditions exist. FIN 46(R)-5 covers issues that commonly arise in leasing arrangements among related parties, as well as other types of arrangements involving both related and unrelated parties. Implicit variable interests are implied financial interests in an entity’s net assets exclusive of variable interests. An implicit variable interest acts the same as in an explicit variable interest except it involves the absorbing and (or) receiving of variability indirectly from the entity (rather than directly). The identification of an implicit variable interest is a matter of judgment that depends on the relevant facts and circumstances. This guidance is effective for our fiscal quarter ending June 30, 2005. We are continuing to evaluate the provisions of FIN 46(R)-5, which may affect certain non-material leases of office space from a related party.

FIN 47, “Accounting for Conditional Asset Retirement Obligations.” Under SFAS No. 143, “Accounting for Asset Retirement Obligations,” a company must record a liability for its legal obligations resulting from the eventual retirement of its tangible long-lived assets, whether that obligation results from the acquisition, construction, or development of the asset. However, many companies have not recorded a liability, concluding that either (1) the conditional nature of the obligation does not create a liability until the retirement activity occurs or (2) the timing and/or the method of settling the obligation is unknown. FIN 47 concludes otherwise. If required legally, an obligation associated with the asset’s retirement is inevitable even though uncertainties exist about the timing and/or method of settling the obligation. According to FIN 47, these uncertainties affect the fair value of the liability, rather than prevent the need to record one at all. Additionally, the ability of a company to postpone indefinitely the settlement of the obligation, or to sell the asset prior to its retirement, does not relieve a company of its present duty to settle the obligation. We are currently studying the effects of FIN 47 on our accounting policy for asset retirement obligations. We will adopt FIN 47 in December 2005.

3. BUSINESS COMBINATIONS

Indian Springs acquisition in January 2005. In January 2005, we paid El Paso $74.5 million for their membership interests in Teco Gas Gathering, LLC and Teco Gas Processing, LLC. As a result of this acquisition, we indirectly own an 80% equity interest in the 89-mile Indian Springs Gathering System and a 75% equity interest in the Indian Springs natural gas processing facility, both of which are located in East Texas. The Indian Springs processing facility has capacity to process up to 120 MMcf/d of natural gas and there is an idle 20 MMcf/d production train available for restart to support increases in natural gas volumes. The natural gas processed at the Indian Springs processing facility is sourced from the Indian Springs Gathering System, as well as our nearby Big Thicket Gathering System.

Acquisition of additional interests in Dixie in January and February 2005. We purchased an approximate 20% interest in Dixie from an affiliate of ConocoPhillips in January 2005 for $31 million and an approximate 26% interest in Dixie from an affiliate of ChevronTexaco in February 2005 for $40 million. As a result of these acquisitions, our ownership interest in Dixie increased to approximately 66% and Dixie became a consolidated subsidiary of ours in February 2005. Dixie owns and operates the 1,301-mile Dixie Pipeline, which transports propane from supply areas in Texas, Louisiana and Mississippi to markets throughout the southeastern United States. The Dixie Pipeline is regulated by the FERC and transports an average of approximately 100 MBPD of propane.

GulfTerra Merger purchase price and purchase price allocation adjustments. During the first quarter of 2005, we made purchase price adjustments related to the GulfTerra Merger, and we revised our preliminary purchase price allocation related to the GulfTerra Merger. The purchase price adjustments of $6.5 million were primarily attributable to merger-related financial advisory services and involuntary severance costs, both of which were attributable to the GulfTerra Merger.

The GulfTerra Merger was completed on September 30, 2004, when GulfTerra merged with a wholly owned subsidiary of Enterprise. The aggregate value of total consideration Enterprise paid or issued to complete the GulfTerra Merger was approximately $4 billion. Our purchase price allocations related to the GulfTerra Merger remain preliminary and could change due to the refinement of our estimates.

Allocation of purchase price for 2005 business combinations and

other purchase accounting adjustments

The acquisitions and post-closing purchase price adjustments described previously were accounted for under the purchase method of accounting and, accordingly, the cost of each has been allocated to the assets acquired and liabilities assumed based on their estimated fair values as follows:

				Indian
				Springs	Dixie	GulfTerra	Other	Total
Purchase price allocation:
	Assets acquired in business combination:
		Current assets		$ 355	$ 6,038	$ 8,864		$ 15,257
		Property, plant and equipment, net		74,500	125,734		$ 1,121	201,355
		Investments in and advances to
		unconsolidated affiliates			(36,279)			(36,279)
		Other assets			276			276
			Total assets acquired	74,855	95,769	8,864	1,121	180,609
	Liabilities assumed in business combination:
		Current liabilities			(6,620)	89		(6,531)
		Long-term debt			(13,972)			(13,972)
		Other long-term liabilities			(2,552)			(2,552)
		Minority interest			(4,576)			(4,576)
			Total liabilities assumed	-	(27,720)	89	-	(27,631)
			Total assets acquired less liabilities assumed	74,855	68,049	8,953	1,121	152,978
			Total consideration given	74,855	68,049	6,453	1,121	150,478
	Goodwill			$ -	$ -	$ (2,500)	$ -	$ (2,500)

The purchase price allocations shown in the preceding table for the recent Indian Springs and Dixie business combinations are preliminary. Enterprise has engaged an independent third-party business valuation expert to assess the fair values of the tangible and intangible assets of these entities. This information will assist management in the development of definitive allocations of the overall purchase prices for these transactions.

4. INVENTORIES

Our inventories consisted of the following at the dates indicated:

	March 31,	December 31,
	2005	2004
Working inventory	$ 309,025	$ 171,485
Forward-sales inventory	527	17,534
Inventory	$ 309,552	$ 189,019

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

Costs and expenses, as shown on our Unaudited Condensed Statements of Consolidated Operations and Comprehensive Income, includes cost of sales related to inventories. For the three months ended March 31, 2005 and 2004, such consolidated cost of sales amounts were $2.1 billion and $1.5 billion, respectively.

Due to fluctuating prices in the NGL, natural gas and petrochemical industry, we occasionally recognize lower of cost or market adjustments when the carrying values of our inventories exceed their net realizable value. These non-cash adjustments are charged to cost of sales within operating costs and expenses in the period they are recognized. For the three months ended March 31, 2005 and 2004, we recognized $9.6 million and $4.2 million, respectively, of such adjustments.

5. PROPERTY, PLANT AND EQUIPMENT

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

	Estimated
	Useful Life	March 31,	December 31,
	in Years	2005	2004
Plants and pipelines (1)	5-35 (5)	$ 7,933,372	$ 7,691,197
Underground and other storage facilities (2)	5-35 (6)	527,619	531,394
Platforms and facilities (3)	23-31	162,645	162,645
Transportation equipment (4)	3-10	7,422	7,240
Land		30,293	29,142
Construction in progress		296,603	230,375
Total		8,957,954	8,651,993
Less accumulated depreciation		898,707	820,526
Property, plant and equipment, net		$ 8,059,247	$ 7,831,467

(1) Plants and pipelines includes processing plants; NGL, petrochemical, oil and natural gas pipelines; terminal loading and unloading facilities; office furniture and equipment; buildings; laboratory and shop equipment; and related assets. (2) Underground and other storage facilities includes underground product storage caverns; storage tanks; water wells; and related assets. (3) Platforms and facilities includes offshore platforms and related facilities and other associated assets. (4) Transportation equipment includes vehicles and similar assets used in our operations. (5) In general, the estimated useful lives of major components of this category are: processing plants, 20-35 years; pipelines, 18-35 years (with some equipment at 5 years); terminal facilities, 10-35 years; office furniture and equipment, 3-20 years; buildings 20-35 years; and laboratory and shop equipment, 5-35 years. (6) In general, the estimated useful lives of major components of this category are: underground storage facilities, 20-35 years (with some components at 5 years); storage tanks, 10-35 years; and water wells, 25-35 years (with some components at 5 years).

Depreciation expense for the three months ended March 31, 2005 and 2004 was $78.9 million and $26.8 million, respectively. Capitalized interest on our construction projects for the three months ended March 31, 2005 and 2004 was $4.4 million and $0.3 million, respectively.

6. INVESTMENTS IN AND ADVANCES TO UNCONSOLIDATED AFFILIATES

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

		Ownership	Investments in and advances to
		Percentage at	Unconsolidated Affiliates at
		March 31,	March 31,	December 31,
		2005	2005	2004
Offshore Pipelines & Services:
	Poseidon	36%	$ 64,617	$ 63,944
	Cameron Highway (1)	50%	126,581	114,354
	Deepwater Gateway	50%	119,098	56,527
	Neptune	25.67%	71,109	72,052
	Nemo	33.92%	12,932	12,586
Onshore Natural Gas Pipelines & Services:
	Evangeline	49.5%	2,939	2,810
	Coyote	50%	2,218	2,441
NGL Pipelines & Services:
	Dixie (2)			32,514
	VESCO	13.1%	37,762	38,437
	Belle Rose	41.7%	10,059	10,172
	Promix	50%	63,378	65,748
	BRF	32.3%	26,784	27,012
Petrochemical Services:
	BRPC	30%	15,574	15,617
	La Porte	50%	4,928	4,950
Total			$ 557,979	$ 519,164

(1) Cameron Highway began deliveries of Gulf of Mexico crude oil production to major refining markets along the Texas Gulf Coast during the first quarter of 2005. (2) We acquired an additional 20% ownership interest in Dixie in January 2005 and an additional 26.1% ownership interest in February 2005. As a result of these acquisitions, Dixie became a consolidated subsidiary.

In connection with obtaining regulatory approval for the GulfTerra Merger, we were required by the FTC to sell our ownership interest in Starfish by March 31, 2005. The $36.6 million carrying value of this investment was classified as "Assets held for sale" on our balance sheet at December 31, 2004. On March 31, 2005, we sold this asset to a third-party for $42.1 million in cash and realized a gain on the sale of $5.5 million.

On occasion, the price we pay to acquire an investment exceeds the carrying value of the underlying historical net assets (i.e., the underlying equity account balances on the books of the investee) that we purchase. These excess cost amounts are a component of our investments in and advances to unconsolidated affiliates. At March 31, 2005, our investments in Promix, La Porte, Neptune, Poseidon, Cameron Highway and Nemo included excess cost. At March 31, 2005, excess cost amounts included in our investments in and advances to unconsolidated affiliates totaled $49.7 million, which was attributed to tangible assets. Amortization of our excess cost amounts attributed to tangible assets was $0.7 million and $0.5 million during the three months ended March 31, 2005 and 2004, respectively.

The following table shows our equity in income of unconsolidated affiliates by business segment for the periods indicated:

		For the Three Months
		Ended March 31,
		2005	2004
Offshore Pipelines & Services		$ 2,975	$ 983
Onshore Natural Gas Pipelines & Services		580	24
NGL Pipelines & Services		4,448	2,911
Petrochemical Services		276	395
Other (1)			10,554
	Total	$ 8,279	$ 14,867

(1) This category represents equity income from GulfTerra GP. In connection with the GulfTerra Merger, GulfTerra GP became a wholly owned consolidated subsidiary on September 30, 2004. We had previously accounted for our 50% ownership interest in GulfTerra GP as an equity method investment from December 15, 2003 through September 29, 2004.

Summarized financial information of unconsolidated affiliates

The following table presents unaudited income statement data for our unconsolidated affiliates, aggregated by business segment, for the periods indicated (on a 100% basis).

	Summarized Income Statement Information for the Three Months Ended
	March 31, 2005			March 31, 2004
		Operating	Net		Operating	Net
	Revenues	Income	Income	Revenues	Income	Income
Offshore Pipelines & Services	$ 366,836	$ 14,464	$ 8,523	$ 14,641	$ 5,806	$ 4,644
Onshore Natural Gas Pipelines & Services	53,354	2,147	1,072	50,920	3,071	1,098
NGL Pipelines & Services	70,031	13,508	13,774	60,184	9,995	9,994
Petrochemical Services	4,095	1,129	1,141	4,641	1,544	1,540

7. INTANGIBLE ASSETS AND GOODWILL

Intangible assets

The following table summarizes our intangible assets (which primarily consist of contracts and customer relationships) at the dates indicated by segment:

			At March 31, 2005		At December 31, 2004
		Gross	Accum.	Carrying	Accum.	Carrying
		Value	Amort.	Value	Amort.	Value
Offshore Pipelines & Services		$ 207,012	$ (13,687)	$ 193,325	$ (6,965)	$ 200,047
Onshore Natural Gas Pipelines & Services		434,150	(16,798)	417,352	(8,344)	425,806
NGL Pipelines & Services		359,237	(60,612)	298,625	(53,666)	303,424
Petrochemical Services		56,532	(5,697)	50,835	(5,208)	51,324
	Total	$ 1,056,931	$ (96,794)	$ 960,137	$ (74,183)	$ 980,601

The following table shows amortization expense associated with our intangible assets for the periods indicated by segment:

		For the Three Months
		Ended March 31,
		2005	2004
Offshore Pipelines & Services		$ 6,722
Onshore Natural Gas Pipelines & Services		8,454
NGL Pipelines & Services		6,946	$ 3,327
Petrochemical Services		489	496
	Total	$ 22,611	$ 3,823

For the remainder of 2005, amortization expense associated with these intangible assets is currently estimated at $63.9 million.

Goodwill

The following table summarizes our goodwill amounts by segment at the dates indicated. Of the $456.7 million of goodwill we have recorded at March 31, 2005, $374.3 million relates to goodwill we recorded in connection with the GulfTerra Merger.

		March 31,	December 31,
		2005	2004
Offshore Pipelines & Services		$ 61,934	$ 62,348
Onshore Natural Gas Pipelines & Services		288,467	290,397
NGL Pipelines & Services		32,603	32,763
Petrochemical Services		73,690	73,690
	Totals	$ 456,694	$ 459,198

8. RELATED PARTY TRANSACTIONS

The following table summarizes our related party transactions for the periods indicated:

		For the Three Months
		Ended March 31,
		2005	2004
Revenues from consolidated operations
	EPCO	$ 284	$ 2,143
	Shell		104,100
	Unconsolidated affiliates	57,909	49,060
	Total	$ 58,193	$ 155,303
Operating costs and expenses
	EPCO	$ 57,044	$ 39,113
	TEPPCO	1,503
	Shell		166,830
	Unconsolidated affiliates	6,568	9,582
	Total	$ 65,115	$ 215,525
Selling, general and administrative expenses
	EPCO	$ 9,251	$ 6,894

Historically, Shell was considered a related party because it owned more than 10% of our limited partner interests and, prior to September 2003, it owned a 30% ownership interest in Enterprise GP. As a result of Shell selling a portion of its limited partner interests in us to a third party in December 2004 and March 2005, Shell now owns less than 10% of our common units. Shell sold its 30% interest in Enterprise GP to an affiliate of EPCO in September 2003. As a result of Shell's reduced equity interest in us and its lack of control of Enterprise, Shell ceased to be considered a related party beginning in the first quarter of 2005.

Relationship with EPCO. We have an extensive and ongoing relationship with EPCO. EPCO is controlled by Dan L. Duncan, who is also a director and Chairman of Enterprise GP, our general partner. In addition, the executive and other officers of Enterprise GP are employees of EPCO, including Robert G. Phillips who is President and Chief Executive Officer and a director of Enterprise GP. The principal business activity of Enterprise GP is to act as our managing partner.

Collectively, EPCO and its affiliates owned a 38.6% equity interest in Enterprise at March 31, 2005, which includes their ownership interest in Enterprise GP. In January 2005, an affiliate of EPCO acquired El Paso’s 9.9% membership interest in Enterprise GP and 13,454,498 of our common units from El Paso for approximately $425 million in cash. As a result of these transactions, EPCO and affiliates own 100% of the membership interests of our general partner and El Paso no longer owns an interest in us or Enterprise GP.

We have no employees. All of our management, administrative and operating functions are performed by employees of EPCO pursuant to the Administrative Services Agreement. We reimburse EPCO for the costs of its employees who perform operating functions for us and for costs related to its other management and administrative employees. We also have entered into an agreement with EPCO to provide trucking services for us for the transportation of NGLs and other products. In addition, we also buy from and sell to EPCO's Canadian affiliate certain NGL products.

We and Enterprise GP are both separate legal entities from EPCO and its other affiliates, with assets and liabilities that are separate from EPCO and its other affiliates. Historically, EPCO depended on cash distributions it received as an equity owner in us to fund most of its other operations and to meet its debt obligations. For the three months ended March 31, 2005 and 2004, EPCO affiliates received $46.8 million and $43.4 million in distributions from us, respectively.

Relationship with TEPPCO. On February 24, 2005, an affiliate of EPCO acquired Texas Eastern Products Pipeline Company, LLC ("TEPPCO GP"), the general partner of TEPPCO Partners, L.P. (“TEPPCO”), and 2,500,000 common units of TEPPCO from Duke Energy Field Services, LLC ("Duke Energy") for approximately $1.2 billion in cash. TEPPCO GP owns a 2% general partner interest in TEPPCO and is the managing partner of

TEPPCO and its subsidiaries. Subsequently, EPCO reconstituted the board of directors of TEPPCO GP and Dr. Ralph Cunningham (a former independent director of Enterprise GP) was named Chairman of TEPPCO GP. Due to EPCO's actions to reconstitute the board of directors of TEPPCO GP and TEPPCO GP's ability to direct the management of TEPPCO, TEPPCO GP and TEPPCO became related parties to EPCO and EPD during the first quarter of 2005.

On March 11, 2005, the Bureau of Competition of the FTC delivered written notice to EPCO’s legal advisor that it was conducting a non-public investigation to determine whether EPCO’s acquisition of TEPPCO GP may tend substantially to lessen competition. No filings were required under the Hart-Scott-Rodino Act in connection with EPCO’s purchase of TEPPCO GP. EPCO and its affiliates, including us, may receive similar inquiries from other regulatory authorities and intend to cooperate fully with any such investigations and inquiries. In response to such FTC investigation or any inquiries EPCO and its affiliates may receive from other regulatory authorities, we may be required to divest certain assets. In the event we are required to divest significant assets, our financial condition could be affected.

9. CAPITAL STRUCTURE

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

Capital accounts, under the Partnership Agreement, are maintained for our general partner and our limited partners. The capital account provisions of our Partnership Agreement incorporate principles established for U.S. Federal income tax purposes and are not comparable to the equity accounts reflected under GAAP in our consolidated financial statements.

Our Partnership Agreement sets forth the calculation to be used in determining the amount and priority of cash distributions that our limited partners and general partner will receive. The Partnership Agreement also contains provisions for the allocation of net earnings and losses to our limited partners and general partner. For purposes of maintaining partner capital accounts, the Partnership Agreement specifies that items of income and loss shall be allocated among the partners in accordance with their respective percentage interests. Normal income and loss allocations according to percentage interests are done only after giving effect to priority earnings allocations in an amount equal to incentive cash distributions allocated 100% to our general partner.

March 2005 universal shelf registration statement. In March 2005, we filed a universal shelf registration statement with the SEC registering the issuance of $4 billion of partnership equity and public debt obligations. In connection with this registration statement, we also registered for resale 35,368,522 common units currently owned by Shell and 5,631,478 common units that had been sold by Shell to Kayne Anderson MLP Investment Company ("Kayne Anderson") in December 2004 and March 2005. We are obligated to register the resale of these common units under a registration rights agreement we executed with Shell in connection with our acquisition of certain of Shell's Gulf Coast midstream energy businesses in September 1999.

Equity offerings. Our Partnership Agreement generally authorizes us to issue an unlimited number of additional limited partner interests and other equity securities for such consideration and on such terms and conditions as may be established by Enterprise GP in its sole discretion (subject, under certain circumstances, to the approval of our unitholders). The following table reflects the number of common units issued and the net proceeds received from each public offering from January 1, 2005 through March 31, 2005:

			Net Proceeds from Sale of Common Units
		Number of	Contributed	Contributed by
Month of		common units	by Limited	General
offering		issued	Partners	Partner	Total
	February 2005	17,250,000	$ 447,758	$ 9,138	$ 456,896
	February 2005	1,516,561	38,248	781	39,029
	Total 2005	18,766,561	$ 486,006	$ 9,919	$ 495,925

Restricted units. At March 31, 2005, we had 501,417 restricted units outstanding. In February 2005, EPCO issued 12,892 time-vested restricted units to key management personnel of EPCO (who work on our behalf) as a means of retaining and compensating them for long-term performance and to increase their ownership interest in Enterprise. The fair value of the restricted units issued in February 2005 at grant date was $0.3 million.

The total unamortized deferred compensation balance at March 31, 2005 for our restricted units outstanding was $10.3 million. We reclassified $0.8 million of such compensation expense to earnings during the three months ended March 31, 2005, which is reflected as a component of general and administrative expenses. Deferred compensation is reflected as a reduction of partners' equity and allocated to our partners in accordance with their respective ownership interests.

Changes in limited partners' equity. The following table details the changes in limited partners' equity since December 31, 2004:

		Limited Partners
			Restricted
		Common	Common
		units	units	Total
Balance, December 31, 2004		$ 5,204,940	$ 12,327	$ 5,217,267
	Net income	93,595	125	93,720
	Operating leases paid by EPCO	516	1	517
	Cash distributions to partners	(147,850)	(197)	(148,047)
	Proceeds from sales of common units	486,006		486,006
	Proceeds from exercise of unit options	5,016		5,016
	Issuance of restricted units, net		257	257
Balance, March 31, 2005		$ 5,642,223	$ 12,513	$ 5,654,736

Distributions. As an incentive, Enterprise GP’s percentage interest in our quarterly cash distributions is increased after certain specified target levels of quarterly distribution rates are met. Enterprise GP’s quarterly incentive distribution thresholds are as follows:

•	2% of quarterly cash distributions up to $0.253 per unit;
•	15% of quarterly cash distributions from $0.253 per unit up to $0.3085 per unit; and
•	25% of quarterly cash distributions that exceed $0.3085 per unit.

On April 15, 2005, the Board of Directors of Enterprise GP announced that our quarterly distribution rate with respect to the first quarter of 2005 would be $0.41 per common unit, or $1.64 on an annualized basis. This distribution will be paid on May 10, 2005, to unitholders of record at the close of business on April 29, 2005.

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

		Limited Partners
			Restricted
		Common	Common	Treasury
		Units	Units	Units
Balance, December 31, 2004		364,297,340	488,525	427,200
	Common units issued in February 2005	1,516,561
	Common units issued in connection with February 2005 offering	17,250,000
	Restricted common units issued in February 2005		12,892
	Common units issued in March 2005	195,000
Balance, March 31, 2005		383,258,901	501,417	427,200

Accumulated other comprehensive income. The following table summarizes the effect of our cash flow hedging financial instruments (see Note 12) on accumulated other comprehensive income since December 31, 2004.

		Interest Rate Fin. Instrs.		Accumulated
			Forward-	Other
	Commodity		Starting	Comprehensive
	Financial	Treasury	Interest	Income
	Instruments	Locks	Rate Swaps	Balance
Balance, December 31, 2004	$ 1,434	$ 4,572	$ 18,548	$ 24,554
Change in fair value of commodity financial instrument	(1,434)			(1,434)
Reclassification of gain on settlement of treasury locks to interest expense		(109)		(109)
Reclassification of gain on settlement of forward-starting swaps to interest expense			(886)	(886)
Balance, March 31, 2005	$ -	$ 4,463	$ 17,662	$ 22,125

During the remainder of 2005, we will reclassify a combined $3.1 million from accumulated other comprehensive income as a reduction in interest expense from our treasury locks and forward-starting interest rate swaps. In addition, we reclassified an approximate $1.4 million gain into income from accumulated other comprehensive income related to a commodity cash flow hedge acquired in the GulfTerra Merger. This gain is primarily due to an increase in fair value from that recorded for the commodity cash flow hedge at September 30, 2004.

10. DEBT OBLIGATIONS

Our debt consisted of the following at the dates indicated:

			March 31,	December 31,
			2005	2004
Operating Partnership debt obligations:
	364-Day Acquisition Credit Facility, variable rate, repaid in February 2005 (1)			$ 242,229
	Multi-Year Revolving Credit Facility, variable rate, due September 2009 (2)		$ 300,000	321,000
	Seminole Notes, 6.67% fixed-rate, due December 2005 (3)		15,000	15,000
	Pascagoula MBFC Loan, 8.70% fixed-rate, due March 2010		54,000	54,000
	Senior Notes A, 8.25% fixed-rate, repaid March 2005			350,000
	Senior Notes B, 7.50% fixed-rate, due February 2011		450,000	450,000
	Senior Notes C, 6.375% fixed-rate, due February 2013		350,000	350,000
	Senior Notes D, 6.875% fixed-rate, due March 2033		500,000	500,000
	Senior Notes E, 4.00% fixed-rate, due October 2007		500,000	500,000
	Senior Notes F, 4.625% fixed-rate, due October 2009		500,000	500,000
	Senior Notes G, 5.60% fixed-rate, due October 2014		650,000	650,000
	Senior Notes H, 6.65% fixed-rate, due October 2034		350,000	350,000
	Senior Notes I, 5.00% fixed-rate, due March 2015		250,000
	Senior Notes J, 5.75% fixed-rate, due March 2035		250,000
	Dixie short-term commercial paper debt obligations		14,000
GulfTerra Senior Notes and Senior Subordinated Notes (3,4)			5,719	6,469
		Total principal amount	4,188,719	4,288,698
Other, including unamortized discounts and premiums and changes in fair value			(31,416)	(7,462)
		Subtotal long-term debt	4,157,303	4,281,236
Less current maturities of debt (5)			(29,000)	(15,000)
		Long-term debt	$ 4,128,303	$ 4,266,236

Standby letters of credit outstanding (6)			$ 135,152	$ 139,052

(1) We used the proceeds from our February 2005 common unit offering to fully repay and terminate the 364-Day Acquisition Credit Facility. For additional information regarding this equity offering, see Note 9. (2) The Multi-Year Revolving Credit Facility has a $750 million borrowing capacity, which is reduced by the amount of standby letters of credit outstanding. (3) Solely as it relates to the assets of our GulfTerra and Seminole subsidiaries, our senior indebtedness is structurally subordinated and ranks junior in right of payment to indebtedness of GulfTerra and Seminole. (4) GulfTerra’s remaining $0.8 million of 6.25% Senior Notes due June 2010 were called and retired in February 2005. (5) In accordance with SFAS No. 6, "Classification of Short-Term Obligations Expected to Be Refinanced," long-term and current maturities of debt at December 31, 2004 reflected (i) our refinancing of Senior Notes A with proceeds from our Senior Notes I and J in March 2005 and (ii) the repayment of our 364-Day Acquisition Credit Facility using proceeds from an equity offering completed in February 2005. (6) Of the $135 million and $139 million standby letters of credit outstanding at March 31, 2005 and December 31, 2004, $115 million is associated with a letter of credit facility we entered into in November 2004 in connection with our Independence Hub capital project, and the remaining amounts were issued under our Multi-Year Revolving Credit Facility.

Parent-Subsidiary guarantor relationships. We act as guarantor of the debt obligations of our Operating Partnership, with the exception of the Seminole Notes, Dixie commercial paper obligations and the senior subordinated notes of GulfTerra. If the Operating Partnership were to default on any debt we guarantee, we would be responsible for full repayment of that obligation. The Seminole Notes are unsecured obligations of Seminole Pipeline Company (of which we own an effective 88.4% of its capital stock). The senior subordinated notes of GulfTerra are unsecured obligations of GulfTerra (of which we own 100% of its limited and general partnership interests).

Senior Notes E, F, G and H. In September 2004, our Operating Partnership priced a private offering of an aggregate of $2 billion in principal amount of senior unsecured notes in a transaction exempt from the registration requirements under the Securities Act of 1933, as amended, and in October 2004, these notes were issued. On January 24, 2005, we filed a registration statement for an offer to exchange these notes for registered debt securities with identical terms. The exchange of notes was completed in March 2005.

Senior Notes I and J. On February 15, 2005, our Operating Partnership sold $500 million in principal amount of senior notes in a Rule 144A private placement offering, comprised of $250 million in principal amount of 10-year senior unsecured notes and $250 million in principal amount of 30-year senior unsecured notes. The 10-year notes ("Senior Notes I") were issued at 99.379% of their principal amount and have annual fixed-rate interest of 5.00% and a maturity date of March 1, 2015. The 30-year notes ("Senior Note J") were issued at 98.691% of their principal amount and have annual fixed-rate interest of 5.75% and a maturity date of March 1, 2035. The Operating Partnership used the net proceeds from the issuance of Senior Notes I and J to repay $350 million of indebtedness outstanding under Senior Notes A which was due on March 15, 2005, and the remaining proceeds for general partnership purposes, including the temporary repayment of indebtedness outstanding under the Multi-Year Revolving Credit Facility.

These fixed-rate notes are unsecured obligations of our Operating Partnership and rank equally with its existing and future unsecured and unsubordinated indebtedness. The Operating Partnership’s borrowings under these notes are non-recourse to Enterprise GP. We have guaranteed repayment of amounts due under these notes through an unsecured and unsubordinated guarantee. These notes were issued under an indenture containing certain covenants, which restrict our ability, with certain exceptions, to incur debt secured by liens and engage in sale and leaseback transactions.

Dixie short-term commercial paper debt obligations. Dixie has short-term commercial paper obligations that are supported by a $28 million senior unsecured revolving credit facility. The credit facility primarily serves as a backup to the Dixie commercial paper program and may also be used for general corporate purposes. At March 31, 2005, Dixie had an aggregate of $14 million in commercial paper debt obligations outstanding and none under its senior unsecured revolving credit facility. The senior unsecured revolving credit facility contains certain restrictive covenants, which Dixie was in compliance with at March 31, 2005. Both the Dixie commercial paper program and the senior unsecured revolving credit facility are non-recourse to Enterprise.

Covenants. We are in compliance with the various covenants of our debt agreements at March 31, 2005 and December 31, 2004.

Information regarding variable interest rates paid. The following table shows the range of interest rates paid and weighted-average interest rate paid on our significant consolidated variable-rate debt obligations during the three months ended March 31, 2005.

		Weighted-
	Range of	average
	interest rates	interest rate
	paid	paid
364-Day Acquisition Credit Facility	3.25% to 3.40%	3.30%
Multi-Year Revolving Credit Facility	3.22% to 5.50%	3.42%

Consolidated debt maturity table. The following table shows scheduled maturities of the principal amounts of our debt obligations for the next 5 years and in total thereafter.

2005	$ 29,000
2007	500,000
2009	800,000
Thereafter	2,859,719
Total scheduled principal payments	$ 4,188,719

Joint venture debt obligations. We have three unconsolidated affiliates with long-term debt obligations. The following table shows (i) our ownership interest in each entity at March 31, 2005, (ii) total long-term debt obligations (including current maturities) of each unconsolidated affiliate at March 31, 2005, on a 100% basis to the joint venture and (iii) the corresponding scheduled maturities of such long-term debt.

	Our		Scheduled Maturities of Long-Term Debt
	Ownership							After
	Interest	Total	2005	2006	2007	2008	2009	2009
Cameron Highway ⁽¹⁾	50.0%	$ 325,000		$ 8,125	$ 32,500	$ 192,375	$ 16,000	$ 76,000
Poseidon	36.0%	104,000				104,000
Evangeline	49.5%	35,650	$ 5,000	5,000	5,000	5,000	5,000	10,650
Total		$ 464,650	$ 5,000	$ 13,125	$ 37,500	$ 301,375	$ 21,000	$ 86,650

(1) The scheduled maturities for Cameron Highway assume that the construction loan will be converted into a term loan by July 2005 and scheduled repayments will begin on December 31, 2006.

In accordance with terms of its credit agreement, Deepwater Gateway had the right to repay the principal amount plus any accrued interest due under its term loan at any time without penalty. During the first quarter of 2005, Deepwater Gateway exercised this right and extinguished its term loan. We and our 50% joint venture partner in Deepwater Gateway, Cal Dive, made equal cash contributions of $72 million to Deepwater Gateway to fund the repayment of the $144 million in principal amount owed under Deepwater Gateway's term loan.

11. SUPPLEMENTAL CASH FLOWS DISCLOSURE

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

		For the Three Months
		Ended March 31,
		2005	2004
Decrease (increase) in:
	Accounts and notes receivable	$ 150,833	$ 53,964
	Inventories	(120,178)	(18,169)
	Prepaid and other current assets	(16,572)	(2,294)
	Long-term receivables	64
	Other assets	10,162	(53)
Increase (decrease) in:
	Accounts payable	(172,437)	(22,713)
	Accrued gas payable	116,962	(34,642)
	Accrued expenses	(19,438)	(9,062)
	Accrued interest	(3,618)	(30,648)
	Other current liabilities	1,159	(4,669)
	Other liabilities	(5,857)	(145)
Net effect of changes in operating accounts		$ (58,920)	$ (68,431)

On certain of our capital projects, third parties are obligated to reimburse us for all or a portion of the capital expenditures associated with such projects. As a result of completing the GulfTerra Merger, the number of such arrangements has increased, particularly for projects involving pipeline construction and production well tie-ins. These reimbursements for the three months ended March 31, 2005 and 2004, were $8.9 million and $0.2 million, respectively, and are reflected as a source of investing cash inflows under the caption "Contributions in aid of construction costs" on our Unaudited Condensed Statements of Consolidated Cash Flows.

Net income for the first quarter of 2005 includes a gain on the sale of assets of $5.4 million (recorded as a reduction in operating costs and expenses), which is primarily related to the sale of our 50% interest in Starfish. In connection with gaining regulatory approval for the GulfTerra Merger, we were required to sell our 50% interest in Starfish by March 31, 2005.

12. FINANCIAL INSTRUMENTS

We are exposed to financial market risks, including changes in commodity prices and interest rates. We may use financial instruments (i.e., futures, forwards, swaps, options and other financial instruments with similar characteristics) to mitigate the risks of certain identifiable and anticipated transactions. In general, the type of risks we attempt to hedge are those related to the variability of future earnings, fair values of certain debt instruments and cash flows resulting from changes in applicable interest rates or commodity prices. As a matter of policy, we do not use financial instruments for speculative (or “trading”) purposes.

Interest rate risk hedging program. Our interest rate exposure results from variable and fixed rate borrowings under debt agreements. We manage a portion of our interest rate exposures by utilizing interest rate swaps and similar arrangements, which allow us to convert a portion of fixed rate debt into variable rate debt or a portion of variable rate debt into fixed rate debt. As summarized in the following table, we had nine interest rate swap agreements outstanding at March 31, 2005 that were accounted for as fair value hedges.

		Number	Period Covered	Termination	Fixed to	Notional
Hedged Fixed Rate Debt		Of Swaps	by Swap	Date of Swap	Variable Rate ⁽¹⁾	Amount
Senior Notes B, 7.50% fixed rate, due Feb. 2011		1	Jan. 2004 to Feb. 2011	Feb. 2011	7.50% to 6.3%	$50 million
Senior Notes C, 6.375% fixed rate, due Feb. 2013		2	Jan. 2004 to Feb. 2013	Feb. 2013	6.375% to 4.9%	$200 million
Senior Notes G, 5.6% fixed rate, due Oct. 2014		6	4th Qtr. 2004 to Oct. 2014	Oct. 2014	5.6% to 3.4%	$600 million

	(1) The variable rate indicated is the all-in variable rate for the current settlement period.

The total fair value of these nine interest rate swaps at March 31, 2005, was a liability of $18.7 million, with an offsetting decrease in the fair value of the underlying debt. At December 31, 2004, the total fair value of these nine interest rate swaps was an asset of $0.5 million, with an offsetting increase in the fair value of the underlying debt. Interest expense for the three months ended March 31, 2005 and 2004 reflects a benefit of $4.6 million and $1.7 million, respectively, from interest rate swap agreements.

During 2004, we entered into two groups of four forward-starting interest rate swap transactions having an aggregate notional amount of $2 billion each in anticipation of our financing activities associated with the closing of the GulfTerra Merger. These interest rate swaps were accounted for as cash flow hedges and were settled during 2004 at a net gain to us of $19.4 million, which will be reclassified from accumulated other comprehensive income to reduce interest expense over the life of the associated debt.

Commodity risk hedging program. The prices of natural gas, NGLs and petrochemical products are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control. In order to manage the risks associated with natural gas and NGLs, we may enter into commodity financial instruments. The primary purpose of our commodity risk management activities is to hedge our exposure to price risks associated with (i) natural gas purchases, (ii) NGL production and inventories, (iii) related firm commitments, (iv) fluctuations in transportation revenues where the underlying fees are based on natural gas index prices and (v) certain anticipated transactions involving either natural gas or NGLs.

At March 31, 2005 and December 31, 2004, we had a limited number of commodity financial instruments in our portfolio, which primarily consisted of natural gas cash flow and fair value hedges. The fair value of our commodity financial instrument portfolio at March 31, 2005 and December 31, 2004 was a liability of $0.5 million and an asset of $0.2 million, respectively. We recorded nominal amounts of earnings from our commodity financial instruments during the three months ended March 31, 2005 and 2004.

13. BUSINESS SEGMENT INFORMATION

Business segments are components of a business about which separate financial information is available. The components are regularly evaluated by the CEO of Enterprise GP in deciding how to allocate resources and in assessing performance. Generally, financial information is required to be reported on the basis that it is used internally for evaluating segment performance and deciding how to allocate resources to segments. Our business

segments are generally organized and managed according to the type of services rendered and products produced and/or sold, as applicable. We have revised our prior segment information in order to conform to the current business segment operations and presentation.

We have segregated our business activities into four reportable business segments: Offshore Pipelines & Services, Onshore Natural Gas Pipelines & Services, NGL Pipelines & Services and Petrochemical Services. The Offshore Pipelines & Services business segment consists of (i) approximately 1,150 miles of offshore natural gas pipelines strategically located to serve production areas in some of the most active drilling and development regions in the Gulf of Mexico, (ii) approximately 800 miles of Gulf of Mexico offshore crude oil pipeline systems and (iii) seven multi-purpose offshore hub platforms located in the Gulf of Mexico.

The Onshore Natural Gas Pipelines & Services business segment consists of approximately 17,200 miles of onshore natural gas pipeline systems that provide for the gathering and transmission of natural gas in Alabama, Colorado, Louisiana, Mississippi, New Mexico and Texas. In addition, this segment includes two salt dome natural gas storage facilities located in Mississippi, which are strategically located to serve the Northeast, Mid-Atlantic and Southeast domestic natural gas markets. This segment also includes leased natural gas storage facilities located in Texas and Louisiana.

The NGL Pipelines & Services business segment includes our (i) natural gas processing business and related NGL marketing activities, (ii) NGL pipelines aggregating approximately 12,775 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 import and export terminaling operations.

The Petrochemical Services business segment includes four propylene fractionation facilities, an isomerization complex and an octane additive production facility. This segment also includes various petrochemical pipeline systems.

The Other non-segment category is presented for financial reporting purposes only to reflect the historical equity earnings we received from GulfTerra GP. We acquired a 50% membership interest in GulfTerra GP on December 15, 2003 in connection with Step One of the GulfTerra Merger. Our investment in GulfTerra GP was accounted for using the equity method until the GulfTerra Merger was completed on September 30, 2004. On that date, GulfTerra GP became a wholly owned consolidated subsidiary of ours. Since the historical equity earnings of GulfTerra GP 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 business segments. Therefore, we have segregated equity earnings from GulfTerra GP from our other segment results to aid in comparability between the periods presented.

Our revenues are derived from a wide customer base. All consolidated revenues were earned in the United States. Most of our plant-based operations are located either along the western Gulf Coast in Texas, Louisiana and Mississippi or in New Mexico. Our natural gas, NGL and oil pipelines and related operations are in a number of regions of the United States including the Gulf of Mexico offshore Texas and Louisiana; the south and southeastern United States (primarily in Texas, Louisiana, Mississippi and Alabama); and certain regions of the central and western United States. Our marketing activities are headquartered in Houston, Texas, at our main office and serve customers in a number of regions in the United States including the Gulf Coast, West Coast and Mid-Continent areas.

We evaluate segment performance based on segment gross operating margin. Gross operating margin (either in total or by individual segment) is an important performance measure of the core profitability of our operations. This measure forms the basis of our internal financial reporting and is used by senior management in deciding how to allocate capital resources among business segments. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating segment results.

extraordinary charges and the cumulative effect of changes in accounting principles. Gross operating margin by segment is calculated by subtracting segment operating costs and expenses (net of the adjustments noted above) from segment revenues, with both segment totals before the elimination of intercompany transactions.

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

We include equity earnings from unconsolidated affiliates in our measurement of segment gross operating margin. Our equity investments with industry partners are a vital component of our business strategy. They are a means by which we conduct our operations to align our interests with those of our customers, which may be a supplier of raw materials or a consumer of finished products. This method of operation also enables us to achieve favorable economies of scale relative to the level of investment and business risk assumed versus what we could accomplish on a stand-alone basis. Many of these businesses perform supporting or complementary roles to our other business operations. For example, we use the Promix NGL fractionator to process a portion of the mixed NGLs extracted by our gas plants. Another example was our use of the Dixie pipeline to transport propane sold to customers through our NGL marketing activities (prior to the consolidation of Dixie’s results with ours beginning in February 2005, see Note 3). See Note 8 for additional information regarding our related party relationships with unconsolidated affiliates.

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

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

		For the Three Months
		Ended March 31,
		2005	2004
Revenues (1)		$ 2,555,522	$ 1,704,890
Less operating costs and expenses (1)		(2,383,644)	(1,621,508)
Add:	Equity in income of unconsolidated affiliates (1)	8,279	14,867
	Depreciation and amortization in operating costs and expenses (2)	99,965	30,520
	Retained lease expense, net in operating expenses allocable to us
	and minority interest (3)	528	2,274
	Loss (gain) on sale of assets in operating costs and expenses (2)	(5,436)	98
Total gross operating margin		$ 275,214	$ 131,141

(1) These amounts are taken from our Unaudited Condensed Statements of Consolidated Operations and Comprehensive Income. (2) These non-cash expenses are taken from the operating activities section of our Unaudited Condensed Statements of Consolidated Cash Flows. (3) These non-cash expenses represent the value of the operating leases contributed by EPCO to us for which EPCO has retained the cash payment obligation (i.e., the “retained leases”). The value of the retained leases contributed directly to us is shown on our Unaudited Condensed Statements of Consolidated Cash Flows under the caption “Operating lease expense paid by EPCO.”

A reconciliation of our measurement of total segment gross operating margin to operating income and income before provision for income taxes, minority interest and the cumulative effect of changes in accounting principles follows:

		For the Three Months
		Ended March 31,
		2005	2004
Total gross operating margin		$ 275,214	$ 131,141
Adjustments to reconcile total gross operating margin
	to operating income:
	Depreciation and amortization in operating costs and expenses	(99,965)	(30,520)
	Retained lease expense, net in operating costs and expenses	(528)	(2,274)
	Gain (loss) on sale of assets in operating costs and expenses	5,436	(98)
	General and administrative costs	(14,693)	(9,466)
Consolidated operating income		165,464	88,783
	Other expense	(52,494)	(32,457)
Income before provision for income taxes, minority interest
	and cumulative effect of changes in accounting principles	$ 112,970	$ 56,326

Information by segment, together with reconciliations to the consolidated totals, is presented in the following table:

			Operating Segments
			Offshore	Onshore	NGL		Non-	Adjustments
			Pipeline	Pipelines	Pipelines	Petrochem.	Segmt.	and	Consolidated
			& Services	& Services	& Services	Services	Other	Eliminations	Totals
Revenues from third parties:
		Three months ended March 31, 2005	$ 29,548	$ 246,934	$ 1,857,454	$ 363,393			$ 2,497,329
		Three months ended March 31, 2004		113,026	1,187,574	248,987			1,549,587

Revenues from related parties:
		Three months ended March 31, 2005	186	56,215	1,762	30			58,193
		Three months ended March 31, 2004		47,964	104,931	2,408			155,303

Intersegment and intrasegment revenues:
		Three months ended March 31, 2005	196	10,017	729,677	54,750		$ (794,640)	-
		Three months ended March 31, 2004		809	447,564	55,311		(503,684)	-

Total revenues:
		Three months ended March 31, 2005	29,930	313,166	2,588,893	418,173		(794,640)	2,555,522
		Three months ended March 31, 2004		161,799	1,740,069	306,706		(503,684)	1,704,890

Equity in income in unconsolidated affiliates:
		Three months ended March 31, 2005	2,975	580	4,448	276			8,279
		Three months ended March 31, 2004	983	24	2,911	395	$ 10,554		14,867

Gross operating margin by individual
	business segment and in total:
		Three months ended March 31, 2005	23,224	79,358	153,304	19,328			275,214
		Three months ended March 31, 2004	982	5,599	89,955	24,051	10,554		131,141

Segment assets:
		At March 31, 2005	645,785	3,744,543	2,907,682	464,634		296,603	8,059,247
		At December 31, 2004	648,181	3,729,650	2,753,934	469,327		230,375	7,831,467

Investments in and advances
	to unconsolidated affiliates:
		At March 31, 2005	394,337	5,157	137,983	20,502			557,979
		At December 31, 2004	319,463	5,251	173,883	20,567			519,164

Intangible Assets:
		At March 31, 2005	193,325	417,352	298,625	50,835			960,137
		At December 31, 2004	200,047	425,806	303,424	51,324			980,601

Goodwill:
		At March 31, 2005	61,934	288,467	32,603	73,690			456,694
		At December 31, 2004	62,348	290,397	32,763	73,690			459,198

14. EARNINGS PER UNIT

Basic earnings per unit is computed by dividing net income or loss allocated to limited partner interests by the weighted-average number of distribution-bearing units (i.e., common and restricted common units) outstanding during a period. The distribution-bearing Class B special units were included in the calculation of basic earnings per unit prior to their conversion to common units in July 2004.

In general, diluted earnings per unit is computed by dividing net income or loss allocated to limited partner interests by the sum of:

•	the weighted-average number of distribution-bearing units outstanding during a period (as used in determining basic earnings per unit);
•	the weighted-average number of performance-based restricted common units outstanding during a period; and
•	the number of incremental common units resulting from the assumed exercise of dilutive unit options outstanding during a period (the “incremental option units”).

Treasury units are not considered to be outstanding units; therefore, they are excluded from the computation of both basic and diluted earnings per unit.

In a period of net operating losses, the performance-based restricted units and incremental option units are excluded from the calculation of diluted earnings per unit due to their antidilutive effect. The dilutive incremental option units are calculated in accordance with the treasury stock method, which assumes that proceeds from the exercise of all in-the-money options at the beginning of each period are used to repurchase common units at an average market value during the period. The amount of common units remaining after the proceeds are exhausted represents the potentially dilutive effect of the securities.

The amount of net income allocated to limited partner interests is derived by subtracting our general partner’s share of our net income from net income. The following table shows the allocation of net income to our general partner for the periods indicated:

	For the Three Months
	Ended March 31,
	2005	2004

Net income	$ 109,256	$ 62,528
Less incentive earnings allocations to Enterprise GP	(13,620)	(6,277)
Net income available after incentive earnings allocation	95,636	56,251
Multiplied by Enterprise GP ownership interest	2.0%	2.0%
Standard earnings allocation to Enterprise GP	$ 1,913	$ 1,125

Incentive earnings allocation to Enterprise GP	$ 13,620	$ 6,277
Standard earnings allocation to Enterprise GP	1,913	1,125
Enterprise GP interest in net income	$ 15,533	$ 7,402

The following tables show our calculation of limited partners’ interest in net income, basic earnings per unit and diluted earnings per unit for the periods indicated:

		For the Three Months
		Ended March 31,
		2005	2004
Income before changes in accounting principles and Enterprise GP interest		$ 109,256	$ 51,747
Cumulative effect of changes in accounting principles			10,781
Net income		109,256	62,528
Enterprise GP interest in net income		(15,533)	(7,402)
Net income available to limited partners		$ 93,723	$ 55,126
BASIC EARNINGS PER UNIT
Numerator
	Income before changes in accounting principles and Enterprise GP interest	$ 109,256	$ 51,747
	Cumulative effect of changes in accounting principles		10,781
	Enterprise GP interest in net income	(15,533)	(7,402)
	Limited partners’ interest in net income	$ 93,723	$ 55,126
Denominator
	Common units	372,956	214,049
	Restricted common units	496
	Class B special units		4,414
	Total	373,452	218,463
Basic earnings per unit
	Income before changes in accounting principles and Enterprise GP interest	$ 0.29	$ 0.24
	Cumulative effect of changes in accounting principles		0.05
	Enterprise GP interest in net income	(0.04)	(0.03)
	Limited partners’ interest in net income	$ 0.25	$ 0.26
DILUTED EARNINGS PER UNIT
Numerator
	Income before changes in accounting principles and Enterprise GP interest	$ 109,256	$ 51,747
	Cumulative effect of changes in accounting principles		10,781
	Enterprise GP interest in net income	(15,533)	(7,402)
	Limited partners’ interest in net income	$ 93,723	$ 55,126
Denominator
	Common units	372,956	214,049
	Restricted common units	496
	Class B special units		4,414
	Performance-based restricted units	54
	Incremental option units	700	497
	Total	374,206	218,960
Diluted earnings per unit
	Income before changes in accounting principles and Enterprise GP interest	$ 0.29	$ 0.24
	Cumulative effect of changes in accounting principles		0.05
	Enterprise GP interest in net income	(0.04)	(0.03)
	Limited partners’ interest in net income	$ 0.25	$ 0.26

15. CONDENSED FINANCIAL INFORMATION OF OPERATING PARTNERSHIP

The Operating Partnership and its subsidiaries conduct substantially all of our business. Currently, we have no independent operations and no material assets outside of those of our wholly owned Operating Partnership. We act as guarantor of all our Operating Partnership’s consolidated debt obligations, with the exception of the Seminole Notes and the remaining amounts outstanding under GulfTerra’s senior subordinated notes. If the Operating Partnership were to default on any debt we guarantee, we would be responsible for full repayment of that obligation. Our guarantee of these debt obligations is full and unconditional. For additional information regarding our consolidated debt obligations, see Note 10.

The number and dollar amounts of reconciling items between our consolidated financial statements and those of our Operating Partnership are insignificant. Historically, the primary reconciling items between the consolidated balance sheet of the Operating Partnership and our consolidated balance sheet were treasury units we owned directly and minority interest. The differences in consolidated net income were primarily dividends recognized by the 1999 Trust (which are eliminated in consolidation) and minority interest.

The following table shows condensed consolidated balance sheet data for the Operating Partnership at the dates indicated:

		March 31,	December 31,
		2005	2004
ASSETS
Current assets		$ 1,398,265	$ 1,425,574
Property, plant and equipment, net		8,059,247	7,831,467
Investments in and advances to unconsolidated affiliates, net		557,979	519,164
Intangible assets, net		960,137	980,601
Goodwill		456,694	459,198
Deferred tax asset		8,915	6,467
Long-term receivables		15,144	14,931
Other assets		39,482	43,208
	Total	$ 11,495,863	$ 11,280,610

LIABILITIES AND PARTNERS' EQUITY
Current liabilities		$ 1,464,474	$ 1,582,911
Long-term debt		4,128,303	4,266,236
Other long-term liabilities		78,195	63,521
Minority interest		85,372	73,858
Partners' equity		5,739,519	5,294,084
	Total	$ 11,495,863	$ 11,280,610

Total Operating Partnership debt obligations guaranteed by us		$ 4,154,000	$ 4,267,229

The following table shows condensed consolidated statements of operations data for the Operating Partnership for the periods indicated:

	For the Three Months
	Ended March 31,
	2005	2004
Revenues	$ 2,555,522	$ 1,704,890
Costs and expenses	2,397,646	1,630,711
Equity in income of unconsolidated affiliates	8,279	14,867
Operating income	166,155	89,046
Other income (expense)	(52,475)	(32,299)
Income before provision for income taxes, minority
interest and changes in accounting principles	113,680	56,747
Provision for income taxes	(1,769)	(1,625)
Income before minority interest and changes in
accounting principles	111,911	55,122
Minority interest	(1,941)	(2,934)
Income before changes in accounting principles	109,970	52,188
Cumulative effect of changes in accounting principles		10,781
Net income	$ 109,970	$ 62,969

16. COMMITMENTS AND CONTINGENCIES

Operating leases. We lease certain property, plant and equipment under noncancelable and cancelable operating leases. Our material agreements consist of operating leases, with original terms ranging from 5 to 24 years, for natural gas and NGL underground storage facilities. We generally have the option to renew these leases,

under the terms of the agreements, for one or more renewal terms ranging from 2 to 10 years. Lease expense is charged to operating costs and expenses on a straight line basis over the period of expected economic benefit. Contingent rental payments are expensed as incurred. Third-party lease and rental expense included in operating income for the three months ended March 31, 2005 and 2004 was approximately $8.7 million and $4.8 million, respectively.

Litigation. We are sometimes named as a defendant in litigation relating to our normal business operations, including litigation related to various federal, state and local regulatory and environmental matters. Although we insure against various business risks, to the extent management believes it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to indemnify us against liabilities arising from future legal proceedings as a result of ordinary business activity. Management is not aware of any significant litigation, pending or threatened, that would have a significant adverse effect on our financial position or results of operations.

We own a facility that historically produced MTBE, a motor gasoline additive that enhances octane and is used in reformulated motor gasoline. We operated the facility, which is located within our Mont Belvieu complex. The production of MTBE was primarily driven by oxygenated fuel programs enacted under the federal Clean Air Act Amendments of 1990. In recent years, MTBE has been detected in water supplies. The major source of ground water contamination appears to be leaks from underground storage tanks. As a result of environmental concerns, several states enacted legislation to ban or significantly limit the use of MTBE in motor gasoline within their jurisdictions. In addition, federal legislation has been drafted to ban MTBE and replace the oxygenate with renewable fuels such as ethanol.

A number of lawsuits have been filed by municipalities and other water suppliers against a number of manufacturers of reformulated gasoline containing MTBE, although generally such suits have not named manufacturers of MTBE as defendants, and there have been no such lawsuits filed against our subsidiary which owns the facility. It is possible, however, that MTBE manufacturers such as our subsidiary could ultimately be added as defendants in such lawsuits or in new lawsuits.

Performance Guaranty. In December 2004, our Independence Hub, LLC subsidiary entered into the Independence Hub Agreement (the "Agreement") with six oil and natural gas producers. The Agreement obligates Independence Hub, LLC (i) to construct an offshore platform production facility to process 850 MMcf/d of natural gas and condensate and (ii) to process certain natural gas and condensate production of the six producers following construction of the platform facility.

In conjunction with the Agreement, our Operating Partnership guaranteed the performance of its Independence Hub, LLC subsidiary under the Agreement up to $397.5 million. In December 2004, 20% of this guaranteed amount was assumed by Cal Dive, our joint venture partner in the Independence Hub project. The remaining $318 million represents our share of the anticipated cost of the platform facility. This amount represents the cap on our Operating Partnership's potential obligation to the six producers for our share of the cost of constructing the platform in the very unlikely scenario where the six producers take over the construction of the platform facility. Our performance guarantee continues until the earlier to occur of (i) all of the guaranteed obligations of Independence Hub, LLC shall have been terminated or expired, or shall have been indefeasibly paid or otherwise performed or discharged in full, (ii) upon mutual written consent of our Operating Partnership and the producers or (iii) mechanical completion of the production facility. We expect that mechanical completion will occur on or about November 1, 2006; therefore, we anticipate that the performance guaranty will exist until at least this forecast date.

In accordance with FIN 45, we recorded the fair value of the performance guaranty using an expected present value approach. Given the remote probability that our Operating Partnership would be required to perform under the guaranty, we have estimated the fair value of the performance guaranty at approximately $1.2 million, which is a component of current and other long-term liabilities on our unaudited condensed consolidated balance sheet at March 31, 2005.

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS.

For the three months ended March 31, 2005 and 2004.

Enterprise Products Partners L.P. is a publicly traded Delaware limited partnership listed on the NYSE symbol “EPD.” Unless the context requires otherwise, references to “we,” “us,” “our,” “the Company” or “Enterprise” are intended to mean the consolidated business and operations of Enterprise Products Partners L.P. Certain abbreviated names, acronyms and other capitalized and industry terms are defined within the glossary following the Table of Contents of our Annual Report on Form 10-K for the year ended December 31, 2004. This glossary is incorporated by reference herein and is filed as Exhibit 99.1 to this quarterly report on Form 10-Q.

The following discussion and analysis should be read in conjunction with our unaudited consolidated financial statements and notes included under Item 1 of this quarterly report on Form 10-Q.

RECENT DEVELOPMENTS

The following summarizes our recent significant developments since December 31, 2004.

•	In January 2005, affiliates of EPCO acquired a 9.9% membership interest in Enterprise GP and 13,454,498 of our common units from El Paso for approximately $425 million in cash. As a result of these transactions, EPCO and its affiliates own 100% of the membership interests of Enterprise GP.

•	In January 2005, we paid El Paso $74.5 million for an indirect 80% equity interest in the 89-mile Indian Springs Gathering System and an indirect 75% equity interest in the Indian Springs natural gas processing facility, both of which are located in East Texas.

•	In January 2005, we purchased an approximate 20% interest in Dixie from ConocoPhillips for $31 million. Additionally, we purchased an approximate 26% interest in Dixie from ChevronTexaco in February 2005 for $40 million.

•	In February 2005, we sold 17,250,000 common units (including the over-allotment amount of 2,250,000 common units which closed on March 11, 2005), which generated net proceeds of approximately $456.9 million.

•	In February 2005, our Operating Partnership sold $500 million in principal amount of senior notes in a private offering, comprised of $250 million in principal amount of our 10-year Senior Notes I and $250 million in principal amount of our 30-year Senior Notes J.

•	In March 2005, we filed a universal shelf registration statement with the SEC registering the issuance of $4 billion of partnership equity and public debt obligations.

•

In April 2005, an affiliate of EPCO, Enterprise GP Holdings L.P., was formed to become the sole member of Enterprise GP and to own 13.5 million of our common units that will be contributed to it by other affiliates of EPCO. In connection with its formation, Enterprise GP Holdings L.P. filed a registration statement on Form S-1 for an initial public offering of 14,875,000 of its common units on April 26, 2005. The completion of this offering, which is expected to occur in mid-year 2005, will result in Enterprise GP Holdings L.P. owning our general partner, and EPCO and its affiliates will own approximately 84% of the equity interests in Enterprise GP Holdings L.P.

•

Cameron Highway began deliveries of Gulf of Mexico crude oil production to major refining markets along the Texas Gulf Coast during the first quarter of 2005. The Cameron Highway Oil Pipeline is designed to gather production from the deepwater areas of the Gulf of Mexico, primarily the South Green Canyon area, for delivery to refineries and terminals in Port Arthur and Texas City, Texas. This pipeline can transport up to 600 MBPD of crude oil production. We own a 50% equity interest in Cameron Highway.

OUR CAPITAL SPENDING

We are committed to the long-term growth and viability of the Company. Part of our business strategy involves expansion through business combinations, growth capital projects and investments in joint ventures. In recent years, major oil and gas companies have sold non-strategic assets in the midstream energy sector in which we operate. We forecast that this trend will continue, and expect independent oil and natural gas companies to consider similar divestitures. Management continues to analyze potential acquisitions, joint ventures and similar transactions with businesses that operate in complementary markets or geographic regions.

We believe that we are positioned to continue to grow through acquisitions that will expand our system of assets and through growth capital projects. The combination of our operations with those of GulfTerra provides us with incremental growth opportunities for both onshore and offshore projects. We currently estimate that our capital spending over the next two to three years could approximate up to $2 billion, primarily for growth projects in the Gulf of Mexico and Western regions of North America. Of this amount, we estimate our total capital spending for property, plant and equipment during 2005 will approximate $970 million, which includes estimated expenditures of $900 million for growth capital projects and acquisitions and approximately $70 million for sustaining capital expenditures, which result from improvements to and major renewals of existing assets.

The ability to execute our growth strategy and complete our projects is dependent upon our access to the capital necessary to fund projects and acquisitions. Our success with capital raising efforts, including the formation of joint ventures to share costs and risks, continues to be the critical factor that determines how much we actually spend. We believe our access to capital resources is sufficient to meet the demands of our current and future operating growth needs, and although we currently intend to make the forecasted expenditures discussed above, we may adjust the timing and amounts of projected expenditures as necessary to adapt to changes in the capital markets.

We estimate our forecasted expenditures based upon our strategic operating and growth plans, which are also dependent upon our ability to provide capital from operating cash flows or otherwise obtain the capital necessary to accomplish our operating and growth objectives. These estimates may change due to factors beyond our control, such as weather related issues, changes in supplier prices or poor economic conditions. Further, estimates may change as a result of decisions made at a later date, which may include acquisitions or decisions to take on additional partners.

For the three months ended March 31, 2005 and 2004, our capital spending for business combinations, property, plant and equipment and our unconsolidated affiliates was $405.4 million and $15.8 million, respectively. The following table summarizes our capital spending by activity for the periods indicated:

			For the Three Months
			Ended March 31,
			2005	2004
Capital spending for business combinations:
	Indirect interests in the Indian Springs natural gas gathering and processing assets		$ 74,855
	Additional ownership interests in Dixie		68,049
	Other business combinations		7,574
		Total capital spending related to business combinations	150,478
Capital spending for property, plant and equipment:
	Growth capital projects		150,738	$ 10,841
	Sustaining capital projects		15,550	4,162
		Total capital spending for property, plant and equipment	166,288	15,003
Capital spending attributable to unconsolidated affiliates:
	Investments in unconsolidated affiliates, excluding advances		88,634	818
		Total capital spending	$ 405,400	$ 15,821

Capital spending for property, plant and equipment as shown in the preceding table, is shown net of contributions in aid of construction costs of $8.9 million and $0.2 million for the three months ended March 31, 2005 and 2004, respectively.

At March 31, 2005, we had approximately $227.3 million in outstanding purchase commitments related to capital projects, the majority of which pertain to pipeline and platform growth projects in the Gulf of Mexico that are expected to be placed in service during 2005 and 2006.

OUR RESULTS OF OPERATIONS

We have four reportable business segments: Offshore Pipelines & Services, Onshore Natural Gas Pipelines & Services, NGL Pipelines & Services and Petrochemical Services. Our business segments are generally organized and managed according to the type of services rendered and products produced and/or sold.

The Offshore Pipelines & Services business segment consists of (i) approximately 1,150 miles of offshore natural gas pipelines strategically located to serve production areas in some of the most active drilling and development regions in the Gulf of Mexico, (ii) approximately 800 miles of Gulf of Mexico offshore crude oil pipeline systems and (iii) seven multi-purpose offshore hub platforms located in the Gulf of Mexico.

The Other non-segment category is presented for financial reporting purposes only to reflect the historical equity earnings we received from GulfTerra GP. We acquired a 50% membership interest in GulfTerra GP on December 15, 2003, in connection with the GulfTerra Merger. Our investment in GulfTerra GP was accounted for using the equity method until the GulfTerra Merger was completed on September 30, 2004. On that date, GulfTerra GP became a wholly owned consolidated subsidiary of ours. Since the historical equity earnings of GulfTerra GP 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 business segments. Therefore, we have segregated equity earnings from GulfTerra GP from our other segment results to aid in comparability between the periods presented.

We evaluate segment performance based on the non-GAAP financial measure of gross operating margin. Gross operating margin (either in total or by individual segment) is an important performance measure of the core profitability of our operations. This measure forms the basis of our internal financial reporting and is used by senior management in deciding how to allocate capital resources among business segments. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating segment results. The GAAP measure most directly comparable to total segment gross operating margin is operating income. Our non-GAAP financial measure of total segment gross operating margin should not be considered as an alternative to GAAP operating income.

We define total (or consolidated) segment gross operating margin as operating income before: (1) depreciation and amortization expense; (2) operating lease expenses for which we do not have the payment obligation; (3) gains and losses on the sale of assets; and (4) general and administrative expenses. Gross operating margin is exclusive of other income and expense transactions, provision for income taxes, minority interest, extraordinary charges and the cumulative effect of changes in accounting principles. Gross operating margin by segment is calculated by subtracting segment operating costs and expenses (net of the adjustments noted above) from segment revenues, with both segment totals before the elimination of intercompany transactions.

We have historically included equity earnings from unconsolidated affiliates in our measurement of segment gross operating margin and operating income. Our equity investments with industry partners are a vital component of our business strategy. They are a means by which we conduct our operations to align our interests with those of our customers, which may be suppliers of raw materials or consumers of finished products. This method of operation also enables us to achieve favorable economies of scale relative to the level of investment and business risk assumed versus what we could accomplish on a stand-alone basis. Many of these businesses perform supporting or complementary roles to our other business operations.

For additional information regarding our business segments, please read Note 13 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.

Selected Price and Volumetric Data

The following table illustrates selected average quarterly industry index prices for natural gas, crude oil, selected NGL and petrochemical products since the beginning of 2004:

								Polymer	Refinery
	Natural				Normal		Natural	Grade	Grade
	Gas,	Crude Oil,	Ethane,	Propane,	Butane,	Isobutane,	Gasoline,	Propylene,	Propylene,
	$/MMBtu	$/barrel	$/gallon	$/gallon	$/gallon	$/gallon	$/gallon	$/pound	$/pound
	(1)	(2)	(1)	(1)	(1)	(1)	(1)	(1)	(1)
2004
1st Quarter	$5.69	$35.25	$0.43	$0.66	$0.76	$0.76	$0.87	$0.29	$0.26
2nd Quarter	$6.00	$38.34	$0.45	$0.65	$0.79	$0.79	$0.92	$0.32	$0.26
3rd Quarter	$5.75	$43.90	$0.52	$0.79	$0.92	$0.92	$1.05	$0.32	$0.27
4th Quarter	$7.07	$48.31	$0.60	$0.85	$1.03	$1.04	$1.15	$0.40	$0.35
Average for Year	$6.13	$41.45	$0.50	$0.74	$0.88	$0.88	$1.00	$0.33	$0.29
2005
1st Quarter	$6.27	$49.68	$0.52	$0.79	$0.98	$1.00	$1.14	$0.45	$0.39

(1) Natural gas, NGL, polymer grade propylene and refinery grade propylene prices represent an average of various commercial index prices including OPIS and CMAI. Natural gas price is representative of Henry-Hub I-FERC. NGL prices are representative of Mont Belvieu Non-TET pricing. Refinery grade propylene represents an average of CMAI spot prices. Polymer-grade propylene represents average CMAI contract pricing. (2) Crude oil price is representative of an index price for West Texas Intermediate.

The following table presents our significant throughput, production and processing volumetric data for the periods indicated (on a net basis, taking into account our ownership interests). In general, the increase in volumes quarter-to-quarter is primarily due to the assets we acquired in connection with the GulfTerra Merger and the South Texas midstream assets. The GulfTerra Merger and the South Texas midstream assets acquisition were completed on September 30, 2004.

		For the Three Months
		Ended March 31,
		2005 ⁽¹⁾	2004 ⁽¹⁾
Offshore Pipelines & Services, net:
	Natural gas transportation volumes (BBtu/d)	1,851	429
	Crude oil transportation volumes (MBPD)	121
	Platform gas treating (Mdth/d)	316
	Platform oil treating (MBPD)	8
Onshore Natural Gas Pipelines & Services, net:
	Natural gas transportation volumes (BBtu/d)	5,746	646
NGL Pipelines & Services, net:
	NGL transportation volumes (MBPD)	1,394	1,368
	NGL fractionation volumes (MBPD)	338	229
	Equity NGL production (MBPD)	100	48
	Fee-based natural gas processing (MMcf/d) ⁽²⁾	2,018	362
Petrochemical Services, net:
	Butane isomerization volumes (MBPD)	66	60
	Propylene fractionation volumes (MBPD)	67	54
	Octane additive production volumes (MBPD)		5
	Petrochemical transportation volumes (MBPD)	74	63
Total, net:
	NGL, crude oil and petrochemical transportation volumes (MBPD)	1,589	1,431
	Natural gas transportation volumes (BBtu/d)	7,597	1,075
	Equivalent transportation volumes (MBPD) ⁽³⁾	3,588	1,714

(1) Volumetric data shown above reflects net operating rates of the underlying assets for the periods in which we owned them. (2) Fee-based natural gas processing volumes increased quarter-to-quarter reflecting amendments to our natural gas processing contract mix that were completed during the first quarter of 2004. (3) Reflects equivalent energy volumes where 3.8 MMBtus of natural gas are equivalent to one barrel of NGLs.

The following table summarizes the key components of our results of operations for the periods indicated:

	For the Three Months
	Ended March 31,
	2005	2004
Revenues	$ 2,555,522	$ 1,704,890
Operating costs and expenses	2,383,644	1,621,508
General and administrative costs	14,693	9,466
Equity in income of unconsolidated affiliates	8,279	14,867
Operating income	165,464	88,783
Interest expense	53,413	32,618
Net income	109,256	62,528

Comparison of Results of Operations for the Three Months Ended March 31, 2005

with Results of Operations for the Three Months Ended March 31, 2004

Revenues for the first quarter of 2005 increased $850.6 million over those recorded during the same period in 2004 primarily due to (i) higher revenues from our NGL and petrochemical marketing activities due to increased sales volumes and prices and (ii) the addition of revenues from businesses acquired or consolidated since March 31, 2004, which primarily include GulfTerra and the South Texas midstream assets. Operating costs and expenses increased $762.1 million quarter-to-quarter primarily due to (i) an increase in volumes purchased including the effects of higher product prices which resulted in an increase in the cost of sales of our NGL and petrochemical marketing activities and (ii) the addition of costs and expenses from businesses acquired or consolidated since March 31, 2004. Operating costs and expenses for the first quarter of 2005 were reduced by a $5.4 million gain on the sale of our investment in Starfish, which was required to gain regulatory approval for the GulfTerra Merger.

General and administrative costs also increased $5.2 million quarter-to-quarter primarily due to businesses acquired since March 31, 2004. Equity earnings from unconsolidated affiliates decreased $6.6 million quarter-to-quarter primarily due to the consolidation of GulfTerra GP resulting from completion of the GulfTerra Merger on September 30, 2004. Collectively, the aforementioned changes in revenues, costs and expenses and equity earnings contributed to a $76.7 million increase in operating income quarter-to-quarter.

The $20.8 million increase in interest expense is primarily due to additional debt we incurred as a result of the GulfTerra Merger and the related issuance of Senior Notes E, F, G and H in October 2004 and Senior Notes I and J in February 2005. Our weighted-average debt principal outstanding was $4.3 billion during the first quarter of 2005 compared to $2.2 billion during the first quarter of 2004.

Net income for the first quarter of 2005 was $109.3 million compared to $62.5 million for the first quarter of 2004. The first quarter of 2004 includes a $10.8 million benefit related to the cumulative effect of changes in accounting principles adopted during 2004. For additional information regarding the cumulative effect of changes in accounting principles we recorded during 2004, please read “Other Items” included within this Item 2.

Our gross operating margin by segment and in total is as follows for the periods indicated:

		For the Three Months
		Ended March 31,
		2005	2004
Gross operating margin by segment:
	Offshore Pipelines & Services	$ 23,224	$ 982
	Onshore Natural Gas Pipelines & Services	79,358	5,599
	NGL Pipelines & Services	153,304	89,955
	Petrochemical Services	19,328	24,051
Other, non-segment			10,554
Total segment gross operating margin		$ 275,214	$ 131,141

For a reconciliation of non-GAAP gross operating margin to GAAP operating income and further to GAAP income before provision for taxes, minority interest and the cumulative effect of changes in accounting principles, please read "Other Items" included within this Item 2.

The following information highlights the significant quarter-to-quarter variances in gross operating margin by business segment. For information regarding transportation, processing and other volumetric data by segment for the three months ended March 31, 2005 and 2004, please see page 33.

Offshore Pipelines & Services. Gross operating margin from this business segment increased $22.2 million quarter-to-quarter primarily due to offshore Gulf of Mexico assets we acquired in connection with the GulfTerra Merger. These assets accounted for $22.7 million of gross operating margin recorded for this segment during the first quarter of 2005.

Onshore Natural Gas Pipelines & Services. Gross operating margin from this business segment increased $73.8 million quarter-to-quarter primarily due to onshore natural gas pipeline and storage assets we acquired in connection with the GulfTerra Merger. These assets accounted for $75.4 million of gross operating margin recorded for this segment during the first quarter of 2005.

NGL Pipelines & Services. Gross operating margin from this business segment increased $63.3 million quarter-to-quarter primarily due to improved processing economics and contributions from assets acquired in connection with the GulfTerra Merger and South Texas midstream assets acquisition. Gross operating margin from natural gas processing assets we have acquired since March 31, 2004 accounted for $49.2 million of the increase in gross operating margin for this segment. Gross operating margin from our NGL marketing activities and Louisiana natural gas processing facilities increased $14.5 million quarter-to-quarter primarily due to higher NGL prices and restructuring of processing contracts, respectively.

Gross operating margin from NGL pipelines and related storage services decreased $3.8 million quarter-to-quarter. Improved gross operating margin from our Mid-America and Seminole pipelines and additional gross operating margin amounts attributable to our acquisition of additional equity interests in Dixie and Tri-States were more than offset by lower returns from our NGL export facility, south Louisiana pipelines and related assets. Gross operating margin from NGL fractionation increased $9.4 million quarter-to-quarter primarily due to NGL fractionation assets we acquired in connection with the GulfTerra Merger. Expenses related to support services classified within this segment increased $5.5 million quarter-to-quarter primarily due to increased business activities related to acquired assets.

One of our objectives for 2005 was to seek relief through filings with the FERC to increase tariffs on our Mid-America and Seminole pipeline systems to recover increased costs of operating the pipelines, principally those costs attributable to fuel and pipeline integrity expenses. On March 1, 2005, the joint tariff rate for Mid-America and Seminole increased, which should result in additional revenues of approximately $10 million per year on a combined basis for these assets. In addition, the FERC allowed an increase in Mid-America’s local tariffs to become effective May 1, 2005, subject to refund and further review. This increase is expected to provide our Mid-America pipeline additional revenues of approximately $12 million per year.

Petrochemical Services. Gross operating margin from this business segment decreased $4.7 million quarter-to-quarter. An increase in gross operating margin from our isomerization and propylene fractionation businesses was more than offset by an $8.5 million operating loss at our octane enhancement facility primarily due lower volumes and start-up expenses related to modifications to the facility to add the capability of producing isooctane. As a result of this construction work, the facility was idle during the first quarter. First production of isooctane from the facility is expected in May 2005.

Other. Gross operating margin from this segment pertains to equity earnings we recorded from GulfTerra GP prior to its consolidation with our financial results upon completion of the GulfTerra Merger on September 30, 2004.

OUR LIQUIDITY AND CAPITAL RESOURCES

Our primary cash requirements, in addition to normal operating expenses and debt service, are for capital expenditures, business acquisitions and distributions to our partners. We expect to fund our short-term needs for such items as operating expenses and sustaining capital expenditures with operating cash flows. Capital expenditures for long-term needs resulting from internal growth projects and business acquisitions are expected to be funded by a variety of sources (either separately or in combination) including cash flows from operating activities, borrowings under commercial bank credit facilities, the issuance of additional partnership equity and public or private placement debt. We expect to fund cash distributions to partners primarily with operating cash flows. Our debt service requirements are expected to be funded by operating cash flows and/or refinancing arrangements.

As noted above, certain of our liquidity and capital resource requirements are fulfilled by borrowings made under debt agreements and/or proceeds from the issuance of additional partnership equity. At March 31, 2005, we had $58 million of unrestricted cash and approximately $430 million of available credit under our Multi-Year Revolving Credit Facility. At March 31, 2005, we had approximately $4.2 billion in principal outstanding under various debt agreements.

As a result of our growth objectives, we expect to access debt and equity capital markets from time-to-time and we believe that additional financing arrangements to support our goals can be obtained on reasonable terms. Furthermore, we believe that maintenance of an investment grade credit rating combined with continued ready access to debt and equity capital at reasonable rates and sufficient trade credit to operate our businesses efficiently provide a solid foundation to meet our long and short-term liquidity and capital resource requirements.

For additional information regarding our growth strategy, please read “Our Capital Spending” included within this Item 2.

Registration Statements and Equity and Debt Offerings

On March 3, 2005, we filed a universal shelf registration statement with the SEC registering the issuance of $4 billion of partnership equity and public debt obligations. In connection with this registration statement, we also registered for resale 35,368,522 common units currently owned by Shell and 5,631,478 common units owned by a third party, Kayne Anderson. Kayne Anderson purchased its unregistered common units from Shell in December 2004 and March 2005. We are obligated to register the resale of these common units under a registration rights agreement we executed with Shell in connection with our acquisition of certain of Shell's Gulf Coast midstream energy businesses in September 1999.

In February 2005, we sold 17,250,000 common units (including the over-allotment amount of 2,250,000 common units which closed on March 11, 2005) under a preexisting registration statement from which we received net proceeds of approximately $456.9 million, including Enterprise GP’s proportionate net capital contribution of $9.1 million. We used the proceeds from this public offering to repay our 364-Day Acquisition Credit Facility, to temporarily reduce indebtedness outstanding under our Multi-Year Revolving Credit Facility and for general partnership purposes.

In February 2005, our Operating Partnership sold $500 million in principal amount of senior notes in a private offering, comprised of $250 million in principal amount of 10-year senior unsecured notes and $250 million in principal amount of 30-year senior unsecured notes. The 10-year notes ("Senior Notes I") were issued at 99.379% of their principal amount and have annual fixed-rate interest of 5.00% and a maturity date of March 1, 2015. The 30-year notes ("Senior Note J") were issued at 98.691% of their principal amount and have annual fixed-rate interest of 5.75% and a maturity date of March 1, 2035. The Operating Partnership used the net proceeds from the issuance of Senior Notes I and J to repay $350 million of indebtedness outstanding under Senior Notes A, which was due on March 15, 2005, and the remaining proceeds for general partnership purposes, including the temporary repayment of indebtedness outstanding under the Multi-Year Revolving Credit Facility.

Comparison of Cash Flows for the Three Months Ended March 31, 2005

with Cash Flows for the Three Months Ended March 31, 2004

The following discussion highlights significant quarter-to-quarter comparisons in consolidated operating, investing and financing cash flows:

		For the Three Months
		Ended March 31,
		2005	2004
Net income		$ 109,256	$ 62,528
Adjustments to reconcile net income to cash flows provided by
	(operating activities before changes in operating accounts:
	Depreciation and amortization in operating costs and expenses	99,965	30,520
	Depreciation and amortization in selling, general and administrative costs	1,922	65
	Amortization in interest expense	(477)	798
	Equity in income of unconsolidated affiliates	(8,279)	(14,867)
	Distributions received from unconsolidated affiliates	21,838	16,932
	(Gain) loss on sale of assets	(5,436)	98
	Cumulative effect of changes in accounting principles		(10,781)
	Changes in fair market value of financial instruments	102	3
	Decrease in restricted cash used for operating activities	15,799	5,825
	Other	4,275	6,915
Cash flow from operating activities before changes in operating accounts		$ 238,965	$ 98,036
	Net effect of changes in operating accounts	(58,920)	(68,431)
Operating activities cash flows		$ 180,045	$ 29,605

Cash flows from operating activities primarily reflect net income adjusted for depreciation, amortization and similar non-cash amounts; equity earnings and cash distributions from unconsolidated affiliates; and changes in operating accounts. The net effect of changes in operating accounts is generally the result of timing of cash receipts from sales and cash payments for purchases and other expenses near the end of each period. In addition, operating cash inflows and outflows related to increases or decreases in inventory are influenced by changes in commodity prices and our marketing activities. Cash flow from operations is primarily based on earnings from our business activities. As a result, these cash flows are exposed to certain risks.

We operate predominantly in the midstream energy sector, which includes gathering, transporting, processing, fractionating and storing natural gas, NGLs and crude oil. In general, we provide services for producers and consumers of natural gas, NGLs and crude oil from the wellhead to the end user. The products that we process, sell or transport are principally used as fuel for residential, agricultural and commercial heating, feedstocks in petrochemical manufacturing and in the production of motor gasoline. Reduced demand for our services or products by industrial customers, whether because of general economic conditions, reduced demand for the end products made with our products or increased competition from other service providers or producers due to pricing differences or other reasons, could have a negative impact on our earnings and thus the availability of cash from operating activities. Other risks include fluctuations in oil, natural gas and NGL prices, competitive practices in the midstream energy industry and the impact of operational and systems risks. For a summary of the risk factors pertinent to our business, please read "Cautionary Statement Regarding Forward-Looking Information and Risk Factors" included within this Item 2.

Operating activities. For the three months ended March 31, 2005 and 2004, cash provided by operating activities was $180 million and $29.6 million, respectively. As shown in the preceding table, cash flow before the net effect of changes in operating accounts was an inflow of $239 million for the first quarter of 2005 compared to $98 million during the first quarter of 2004. We believe that cash flow from operating activities before the net effect of changes in operating accounts is an important measure of our ability to generate core cash flows from our assets and other investments. The $141 million increase in this element of our cash flows is primarily due to cash flows from the assets we acquired in connection with the GulfTerra Merger and the South Texas midstream assets acquisition.

Investing activities. For the three months ended March 31, 2005 and 2004, we used $365 million and $15.8 million, respectively, for investing activities. During the first quarter of 2005, we used $74.9 million to purchase

from El Paso two entities which owned interests in the Indian Springs natural gas gathering and processing assets and $68 million to purchase an additional 46.1% ownership interest in Dixie. Capital expenditures were $175.2 million during the first quarter of 2005 period compared to $15.2 million for the 2004 period. For additional information regarding our capital expenditures, please read "Capital Spending" included within this Item 2. Our investments in and advances to unconsolidated affiliates were $88.6 million during the first quarter of 2005 compared to $0.8 million during the first quarter of 2004. In March 2005, we contributed $72 million to Deepwater Gateway to fund our share of the repayment of its $144 million term loan. In addition, our investing activities cash flows include $42.1 million in proceeds from the sale of our 50% equity interest in Starfish, which was required to gain regulatory approval for the GulfTerra Merger.

Financing activities. For the three months ended March 31, 2005 and 2004, cash provided by financing activities was $218.1 million and $0.5 million, respectively. During the first quarter of 2005, we had net repayments on our debt obligations of $118.8 million compared to net borrowings of $65 million during the first quarter of 2004. In February 2005, we issued an aggregate of $500 million in senior notes, the proceeds of which were used to repay $350 million due under Senior Notes A and to temporarily reduce amounts outstanding under our bank credit facilities. Additionally, we repaid the remaining $242.2 million that was due under our 364-Day Acquisition Credit Facility using proceeds from our February 2005 equity offering.

Cash distributions to partners increased $73.4 million quarter-to-quarter primarily due to an increase in the number of units eligible for distributions and an increase in our declared quarterly distribution rate. We expect that future cash distributions to partners will increase as a result of our periodic issuance of common units under the DRIP and other equity offerings. Net proceeds from the issuance of common units were $501 million during the first quarter of 2005 compared to $23.1 million during the first quarter of 2004. The first quarter of 2005 amounts include our February 2005 equity offering of 17,250,000 (including the over-allotment amount of 2,250,000 common units which closed on March 11, 2005), which generated net proceeds of approximately $456.9 million.

Our Credit Ratings

Our current corporate credit ratings are Baa3 (investment grade) with a stable outlook as rated by Moody’s Investor Services; BB+ (non-investment grade) with a positive outlook as rated by Standard and Poor’s and BBB- (investment grade) with a stable outlook by Fitch ratings.

Our Debt Obligations

The following table summarizes our consolidated debt obligations at the dates indicated.

			March 31,	December 31,
			2005	2004
Operating Partnership debt obligations:
	364-Day Acquisition Credit Facility, variable rate, repaid in February 2005 (1)			$ 242,229
	Multi-Year Revolving Credit Facility, variable rate, due September 2009 (2)		$ 300,000	321,000
	Seminole Notes, 6.67% fixed-rate, due December 2005 (3)		15,000	15,000
	Pascagoula MBFC Loan, 8.70% fixed-rate, due March 2010		54,000	54,000
	Senior Notes A, 8.25% fixed-rate, repaid March 2005			350,000
	Senior Notes B, 7.50% fixed-rate, due February 2011		450,000	450,000
	Senior Notes C, 6.375% fixed-rate, due February 2013		350,000	350,000
	Senior Notes D, 6.875% fixed-rate, due March 2033		500,000	500,000
	Senior Notes E, 4.00% fixed-rate, due October 2007		500,000	500,000
	Senior Notes F, 4.625% fixed-rate, due October 2009		500,000	500,000
	Senior Notes G, 5.60% fixed-rate, due October 2014		650,000	650,000
	Senior Notes H, 6.65% fixed-rate, due October 2034		350,000	350,000
	Senior Notes I, 5.00% fixed-rate, due March 2015		250,000
	Senior Notes J, 5.75% fixed-rate, due March 2035		250,000
	Dixie short-term commercial paper debt obligations		14,000
GulfTerra Senior Notes and Senior Subordinated Notes (3,4)			5,719	6,469
		Total principal amount	4,188,719	4,288,698
Other, including unamortized discounts and premiums and changes in fair value			(31,416)	(7,462)
		Subtotal long-term debt	4,157,303	4,281,236
Less current maturities of debt (5)			(29,000)	(15,000)
		Long-term debt	$ 4,128,303	$ 4,266,236

Standby letters of credit outstanding (6)			$ 135,152	$ 139,052

(1) We used the proceeds from our February 2005 common unit offering to fully repay and terminate the 364-Day Acquisition Credit Facility. For additional information regarding this equity offering, see Note 9 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report. (2) The Multi-Year Revolving Credit Facility has a $750 million borrowing capacity, which is reduced by the amount of standby letters of credit outstanding. (3) Solely as it relates to the assets of our GulfTerra and Seminole subsidiaries, our senior indebtedness is structurally subordinated and ranks junior in right of payment to indebtedness of GulfTerra and Seminole. (4) GulfTerra’s remaining $0.8 million of 6.25% Senior Notes due June 2010 were called and retired in February 2005. (5) In accordance with SFAS No. 6, "Classification of Short-Term Obligations Expected to Be Refinanced," long-term and current maturities of debt at December 31, 2004 reflected (i) our refinancing of Senior Notes A with proceeds from our Senior Notes I and J in March 2005 and (ii) the repayment of our 364-Day Acquisition Credit Facility using proceeds from an equity offering completed in February 2005. (6) Of the $135 million and $139 million standby letters of credit outstanding at March 31, 2005 and December 31, 2004, $115 million is associated with a letter of credit facility we entered into in November 2004 in connection with our Independence Hub capital project, and the remaining amounts were issued under our Multi-Year Revolving Credit Facility.

We have three unconsolidated affiliates with long-term debt obligations. The following table shows our ownership interest in each entity at March 31, 2005 and total long-term debt obligations (including current maturities) of each unconsolidated affiliate at March 31, 2005, on a 100% basis to the joint venture.

	Our
	Ownership
	Interest	Total
Cameron Highway	50.0%	$ 325,000
Poseidon	36.0%	104,000
Evangeline	49.5%	35,650
Total		$ 464,650

For additional information regarding our consolidated debt obligations and those of our unconsolidated affiliates, please read Note 10 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.

OUR CONTRACTUAL OBLIGATIONS

With regards to our material contractual obligations, there have been no significant changes outside of the ordinary course of business since those reported in our annual report on Form 10-K for the year ended December 31, 2004.

RECENT ACCOUNTING DEVELOPMENTS

The accounting standard setting bodies and the SEC have recently issued the following accounting guidance that will or may affect our financial statements:

•	SFAS No. 123(R) “Share-Based Payment” issued by the FASB and the related SAB 107 issued by the SEC;
•	FIN 46(R)-5 “Implicit Variable Interests Under FASB Interpretation No. 46(R), Consolidation of Variable Interest Entities” and,
•	FIN 47 “Accounting for Conditional Asset Retirement Obligations.”

For additional information regarding these recent accounting developments that may affect our future financial statements, please read Note 2 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.

OUR CRITICAL ACCOUNTING PRINCIPLES

In our financial reporting process, we employ methods, estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of our financial statements. These methods, estimates and assumptions also affect the reported amounts of revenues and expenses during the reporting period. Investors should be aware that actual results could differ from these estimates if the underlying assumptions prove to be incorrect.

In general, there have been no significant changes in our critical accounting policies since December 31, 2004. For a detailed discussion of these policies, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Our Critical Accounting Policies” in our annual report on Form 10-K for 2004. The following describes the estimation risk underlying our most significant financial statement items:

Depreciation methods and estimated useful lives of property, plant and equipment. In general, depreciation is the systematic and rational allocation of an asset’s cost, less its residual value (if any), to the periods it benefits. The majority of our property, plant and equipment is depreciated using the straight-line method, which incorporates our assumptions regarding the useful economic lives and residual values of such assets. At the time we place our assets in service, we believe such assumptions are reasonable; however, circumstances may develop that would cause us to change these assumptions, which would change our depreciation amounts on a going forward basis.

At March 31, 2005 and December 31, 2004, the net book value of our property, plant and equipment was $8.1 billion and $7.8 billion, respectively. For additional information regarding our property, plant and equipment, please read Note 5 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.

Measuring recoverability of long-lived assets and equity method investments. In general, long-lived assets (including intangible assets with finite useful lives and property, plant and equipment) are reviewed for impairment whenever events or changes in circumstances indicate that their carrying amount may not be recoverable. Equity

method investments are evaluated for impairment whenever events or changes in circumstances indicate that there is a loss in value of the investment that is an other than temporary decline. Measuring the potential impairment of such assets and investments involves the estimation of future cash flows to be derived from the asset being tested. Our estimates of such cash flows are based on a number of assumptions including anticipated margins and volumes; estimated useful life of the asset or asset group; and salvage values. A significant change in these underlying assumptions could result in our recording an impairment charge. We did not record any impairment charges during the three months ended March 31, 2005 and 2004.

Amortization methods and estimated useful lives of qualifying intangible assets. In general, our intangible asset portfolio consists primarily of the estimated values assigned to certain customer relationships and customer contracts. We amortize the customer relationship values using methods that closely resemble the pattern in which the economic benefits of the underlying oil and natural gas resource bases from which the customers produce are estimated to be consumed or otherwise used. We amortize the customer contract intangible assets over the estimated remaining economic life of the underlying contract. A change in the estimates we use to determine amortization rates of our intangible assets (e.g., oil and natural gas production curves, remaining economic life of the contracts, etc.) could result in a material change in the amortization expense we record and the carrying value of our intangible assets.

At March 31, 2005 and December 31, 2004, the carrying value of our intangible asset portfolio was $960.1 million and $980.6 million. For additional information regarding our intangible assets, please read Note 7 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.

Methods we employ to measure the fair value of goodwill. In general, goodwill is attributable to the excess of the purchase price over the fair value of assets acquired. Goodwill is not amortized. Instead, goodwill is tested for impairment at a reporting unit level annually, and more frequently, if circumstances indicate it is more likely than not that the fair value of goodwill is below its carrying amount. Testing goodwill for impairment involves calculating the fair value of a reporting unit, which in turn is based on our assumptions regarding the future economic prospects of the reporting unit. Our estimates of such prospects (i.e., cash flows) are based on a number of assumptions including anticipated margins and volumes of the underlying assets or asset group. A significant change in these underlying assumptions could result in our recording an impairment charge.

At March 31, 2005 and December 31, 2004, the carrying value of our goodwill was $456.7 million and $459.2 million. For additional information regarding our goodwill, please read Note 7 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.

Our use of estimates for revenues and expenses. Our use of estimates for revenues, as well as our use of estimates for operating costs and other expenses has increased as a result of SEC regulations that require us to submit financial information on increasingly accelerated time frames. Such estimates are necessary due to the timing of compiling actual billing information and receiving third-party data needed to record transactions for financial reporting purposes. If the basis of our estimates proves incorrect, it could result in material adjustments to our results of operations between periods.

Reserves for environmental matters. Each of our business segments is subject to extensive federal, state and local laws and regulations governing environmental quality and pollution control. We accrue reserves for environmental matters when our assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated. Our assessments are based on studies, as well as site surveys, to determine the extent of any environmental damage and the necessary requirements to remediate this damage. Our actual results may differ from our estimates, and our estimates can be, and often are, revised in the future, either negatively or positively, depending upon the outcome or expectations based on the facts surrounding each exposure.

At March 31, 2005 and December 31, 2004, we had a liability for environmental remediation of $21 million, which was derived from a range of reasonable estimates based upon studies and site surveys. In accordance with SFAS No. 5 "Accounting for Contingencies" and FASB Interpretation No. 14, "Reasonable Estimation of the Amount of a Loss," we recorded our best estimate of the costs for these remediation activities.

Natural gas imbalances. Natural gas imbalances result when customers physically deliver a larger or smaller quantity of gas into our pipelines than they take out. We generally value our imbalances using a twelve-month moving average of natural gas prices, which we believe is an appropriate assumption to estimate the value of the imbalances at the time of settlement given that the actual settlement dates are generally not known. Changes in natural gas prices may impact our estimates.

At March 31, 2005 and December 31, 2004, our imbalance receivables were $38.5 million and $56.7 million, respectively, and are reflected as a component of accounts receivable. At March 31, 2005 and December 31, 2004, our imbalance payables were $43.9 million and $59 million, respectively, and are reflected as a component of accrued gas payables.

SUMMARY OF RELATED PARTY TRANSACTIONS

The following is a summary of our related party relationships and transactions. For additional information regarding our current and historical related party relationships, please read Note 8 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.

Collectively, EPCO and its affiliates owned a 38.6% equity interest in Enterprise at March 31, 2005, which includes their ownership interest in Enterprise GP.

For the three months ended March 31, 2005 and 2004, our related party revenues from EPCO and affiliates were $0.3 million and $2.1 million, respectively. Our related party expenses paid to EPCO and affiliates were $66.3 million and $46 million for the three months ended March 31, 2005 and 2004, respectively.

Relationship with TEPPCO. On February 24, 2005, an affiliate of EPCO acquired TEPPCO GP, the general partner of TEPPCO, and 2,500,000 common units of TEPPCO from Duke Energy for approximately $1.2 billion in cash. TEPPCO GP owns a 2% general partner interest in TEPPCO and is the managing partner of TEPPCO and its subsidiaries. Subsequently, EPCO reconstituted the board of directors of TEPPCO GP and Dr. Ralph Cunningham (a former independent director of Enterprise GP) was named Chairman of TEPPCO GP. Due to EPCO's actions to reconstitute the board of directors of TEPPCO GP and TEPPCO GP's ability to direct the management of TEPPCO, TEPPCO GP and TEPPCO became related parties to EPCO and EPD during the first quarter of 2005.

connection with EPCO’s purchase of TEPPCO GP. EPCO and its affiliates, including us, may receive similar inquiries from other regulatory authorities and intend to cooperate fully with any such investigations and inquiries. In response to such FTC investigation or any inquiries EPCO and its affiliates may receive from other regulatory authorities, we may be required to divest certain assets. In the event we are required to divest significant assets, our financial condition could be affected.

We did not have any related party revenues from TEPPCO and affiliates for the three months ended March 31, 2005. Our related party expenses paid to TEPPCO and affiliates were $1.5 million for the three months ended March 31, 2005.

Relationship with unconsolidated affiliates. Our significant related party transactions with unconsolidated affiliates consist of the sale of natural gas to Evangeline, purchase of pipeline transportation services from Dixie (prior to its consolidation with our results beginning in February 2005, see Note 3 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report) and the purchase of NGL storage, transportation and fractionation services from Promix. In addition, we sell natural gas to Promix and process natural gas at VESCO. For the three months ended March 31, 2005 and 2004, our related party revenues from unconsolidated affiliates were $57.9 million and $49.1 million, respectively. Our related party expenses paid to unconsolidated affiliates were $6.6 million and $9.6 million for the three months ended March 31, 2005 and 2004, respectively.

Historical relationship with Shell. Historically, Shell was considered a related party because it owned more than 10% of our limited partner interests and, prior to September 2003, it owned a 30% ownership interest in Enterprise GP. As a result of Shell selling a portion of its limited partner interests in us to a third party in December 2004 and March 2005, Shell now owns less than 10% of our common units. Shell sold its 30% interest in Enterprise GP to an affiliate of EPCO in September 2003. As a result of Shell's reduced equity interest in us and its lack of control of Enterprise, Shell ceased to be considered a related party beginning in the first quarter of 2005. For the months ended March 31, 2004, our related party revenues from Shell and expenses paid to Shell were $104.1 million and $166.8 million, respectively.

OTHER ITEMS

Recent regulatory developments. On May 4, 2005, the FERC adopted a policy statement in Docket No. PL05-5, providing that all entities owning public utility assets—oil and gas pipelines and electric utilities—would be permitted to include an income tax allowance in their cost-of-service rates to reflect the actual or potential income tax liability attributable to their public utility income, regardless of the form of ownership. Any tax pass-through entity seeking an income tax allowance would have to establish that its partners or members have an actual or potential income tax obligation on the entity’s public utility income. The FERC expressed the intent to implement its policy in individual cases as they arise. Subject to that case-specific implementation, the policy appears to provide an opportunity for partnership-owned pipelines to seek allowances based upon their entire income paid to partners, rather than the partial allowance provided under the prior Lakehead approach. However, we have not yet been able to determine the effect, if any, this new FERC policy statement will have on the rates for transportation services on our interstate pipelines we charge or on the rates we will be allowed to charge in the future. We expect the final adoption and implementation by FERC of the policy statement in individual cases will be subject to review by the United States Court of Appeals.

Pipeline integrity costs. Our NGL, petrochemical and natural gas pipelines are subject to pipeline integrity management programs administered by the U.S. Department of Transportation, through its Office of Pipeline Safety. During the first quarter of 2005, we spent approximately $5.4 million to comply with these programs, of which $4.3 million was recorded as an operating expense with the remaining $1.1 million being capitalized. Our net cash outlay for the pipeline integrity program is estimated to be approximately $46.6 million for the remainder of 2005. The forecasted cost for 2005 is net of the value of an indemnification for such expenses that we expect to receive from El Paso.

Non-GAAP reconciliation. A reconciliation of our measurement of total non-GAAP gross operating margin to GAAP operating income and income before provision for income taxes, minority interest and the cumulative effect of changes in accounting principles (as shown on our Unaudited Condensed Statements of Consolidated Operations and Comprehensive Income included under Item 1 of this quarterly report on Form 10-Q) follows:

		For the Three Months
		Ended March 31,
		2005	2004
Total non-GAAP gross operating margin		$ 275,214	$ 131,141
Adjustments to reconcile total non-GAAP gross operating margin
	to GAAP operating income:
	Depreciation and amortization in operating costs and expenses	(99,965)	(30,520)
	Retained lease expense, net in operating costs and expenses	(528)	(2,274)
	Gain (loss) on sale of assets in operating costs and expenses	5,436	(98)
	General and administrative costs	(14,693)	(9,466)
GAAP consolidated operating income		165,464	88,783
	Other expense	(52,494)	(32,457)
GAAP income before provision for income taxes, minority interest
	and cumulative effect of changes in accounting principles	$ 112,970	$ 56,326

EPCO subleases to us certain equipment located at our Mont Belvieu facility and 100 railcars for $1 per year. These subleases (the “retained lease expense” in the previous table) are part of the Administrative Services Agreement that we executed with EPCO in connection with our formation in 1998. EPCO holds these items pursuant to operating leases for which it has retained the corresponding cash lease payment obligation.

Operating costs and expenses (as shown on the Unaudited Condensed Statements of Consolidated Operations and Comprehensive Income included under Item 1 of this quarterly report on Form 10-Q) classify the lease payments being made by EPCO as a non-cash related party operating expense, with the offset to partners’ equity on the Unaudited Condensed Consolidated Balance Sheets recorded as a general contribution to us. Apart from the partnership interests we granted to EPCO at our formation, EPCO does not receive any additional ownership rights as a result of its contribution to us of the retained leases.

Cumulative effect of accounting changes recorded during 2004. The $10.8 million cumulative effect of changes in accounting principles represents the combined impact of changing (i) the method our BEF subsidiary uses to account for its planned major maintenance activities from the accrue-in-advance method to the expense-as-incurred method and (ii) the method we used to account for our investment in VESCO.

Changes in directors of Enterprise GP. On March 22, 2005, Dr. Ralph S. Cunningham and Lee W. Marshall, Sr. resigned from the Board of Directors of our general partner, Enterprise GP. William Barnett was appointed as a new director of Enterprise GP on March 22, 2005.

The Board of Directors of Enterprise GP (the "Board") has determined that Mr. Barnett meets the director independence requirements under the applicable rules and regulations of the SEC and under the NYSE's Audit Committee Additional Requirements. Mr. Barnett serves as a member of the Board's Audit and Conflicts Committee. Mr. Barnett also serves as the Chairman of the Board's Governance Committee.

Following the above changes, the directors of Enterprise GP are Dan L. Duncan, Chairman; O.S. Andras, Vice Chairman; Robert G. Phillips, Chief Executive Officer and President; W. Matt Ralls; Richard S. Snell, and Mr. Barnett. To continue the voting majority of independent directors, Enterprise GP expects to appoint a fourth independent director to its board by the end of the second quarter of 2005. Until such time that a fourth independent director is elected, Mr. Duncan will be a non-voting director and preserve the voting majority of the independent directors.

Mr. Ralls, who has served as a member of the Audit and Conflicts Committee, became Chairman of that committee and continues to serve as a member of the Governance Committee, of which he was previously the Chairman. Mr. Snell became a member of the Audit and Conflicts Committee and continues to serve on the Governance Committee.

For additional information regarding Mr. Barnett and this change in directors of Enterprise GP, please read our Current Report on Form 8-K filed on March 23, 2005.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

AND RISK FACTORS

This quarterly report contains various forward-looking statements and information that are based on our beliefs and those of Enterprise GP, our general partner, as well as assumptions made by us and information currently available to us. When used in this document, words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “intend,” “could,” “believe,” “may” and similar expressions and statements regarding our plans and objectives for future operations, are intended to identify forward-looking statements. Although we and our general partner believe that such expectations reflected in such forward-looking statements are reasonable, neither we nor Enterprise GP can give any assurances that such expectations will prove to be correct. Such statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. You should not put undue reliance on any forward-looking statements. When considering forward-looking statements, please read our summarized “Risk Factors” below.

Risk Factors. An investment in our common units involves risks. 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. Among the key risk factors that may have a direct impact 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;

•	the effects of the combined company’s debt level on its future financial and operating flexibility;

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

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

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

•	terrorist attacks aimed at our facilities;

•	the failure to successfully integrate our operations with those of GulfTerra or any other companies we acquire; and
•	the failure to realize the anticipated cost savings, synergies and other benefits of the merger with GulfTerra.

Enterprise has no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise. For additional information regarding our risk factors, please refer to the section titled “Risk Factors” included under Item 7 of our 2004 annual report on Form 10-K (Commission File No. 1-14323). Other risks involved in our business are discussed under “Quantitative and Qualitative Disclosures about Market Risk” included under Item 3 of this quarterly report on Form 10-Q.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Interest rate risk hedging program. Our interest rate exposure results from variable and fixed rate borrowings under debt agreements. We manage a portion of our interest rate exposures by utilizing interest rate swaps and similar arrangements, which allow us to convert a portion of fixed rate debt into variable rate debt or a portion of variable rate debt into fixed rate debt.

As summarized in the following table, we had nine interest rate swap agreements outstanding at March 31, 2005 that were accounted for as fair value hedges.

		Number	Period Covered	Termination	Fixed to	Notional
Hedged Fixed Rate Debt		Of Swaps	by Swap	Date of Swap	Variable Rate ⁽¹⁾	Amount
Senior Notes B, 7.50% fixed rate, due Feb. 2011		1	Jan. 2004 to Feb. 2011	Feb. 2011	7.50% to 6.3%	$50 million
Senior Notes C, 6.375% fixed rate, due Feb. 2013		2	Jan. 2004 to Feb. 2013	Feb. 2013	6.375% to 4.9%	$200 million
Senior Notes G, 5.6% fixed rate, due Oct. 2014		6	4th Qtr. 2004 to Oct. 2014	Oct. 2014	5.6% to 3.4%	$600 million

	(1) The variable rate indicated is the all-in variable rate for the current settlement period.

The following table shows the effect of hypothetical changes in interest rates on the estimated fair value (“FV”) of our interest rate swap portfolio and the related change in fair value of the underlying debt at April 13, 2005 (dollars in thousands). Income is not affected by changes in the fair value of these swaps; however, these swaps effectively convert the hedged portion of fixed-rate debt to variable-rate debt. As a result, interest expense (and related cash outlays for debt service) will increase or decrease with the change in the periodic “reset” rate associated with the respective swap. Typically, the reset rate is an agreed upon index rate published for the first day of a six-month interest calculation period.

	Resulting	Swap FV	Change in FV of Debt
Scenario	Classification	at 4/13/05	Increase (Decrease)
FV assuming no change in underlying interest rates	Asset (Liability)	$ (10,283)
FV assuming 10% increase in underlying interest rates	Asset (Liability)	(41,673)	$ (31,390)
FV assuming 10% decrease in underlying interest rates	Asset (Liability)	21,107	31,390

our exposure to price risks associated with (i) natural gas purchases, (ii) NGL production and inventories, (iii) related firm commitments, (iv) fluctuations in transportation revenues where the underlying fees are based on natural gas index prices and (v) certain anticipated transactions involving either natural gas or NGLs.

We assess the risk of our commodity financial instrument portfolio using a sensitivity analysis model. The sensitivity analysis applied to this portfolio measures the potential income or loss (i.e., the change in fair value of the portfolio) based upon a hypothetical 10% movement in the underlying quoted market prices of the commodity financial instruments outstanding at the date indicated within the following table. The following table shows the effect of hypothetical price movements on the estimated fair value (“FV”) of this portfolio at April 14, 2005 (dollars in thousands):

		Commodity
	Resulting	Financial Instr.
Scenario	Classification	Portfolio FV
FV assuming no change in underlying commodity prices	Asset (Liability)	$ (194)
FV assuming 10% increase in underlying commodity prices	Asset (Liability)	(522)
FV assuming 10% decrease in underlying commodity prices	Asset (Liability)	135

Effect of financial instruments on Accumulated Other Comprehensive Income. The following table summarizes the effect of our cash flow hedging financial instruments on accumulated other comprehensive income since December 31, 2004.

		Interest Rate Fin. Instrs.		Accumulated
			Forward-	Other
	Commodity		Starting	Comprehensive
	Financial	Treasury	Interest	Income
	Instruments	Locks	Rate Swaps	Balance
Balance, December 31, 2004	$ 1,434	$ 4,572	$ 18,548	$ 24,554
Change in fair value of commodity financial instrument	(1,434)			(1,434)
Reclassification of gain on settlement of treasury locks to interest expense		(109)		(109)
Reclassification of gain on settlement of forward-starting swaps to interest expense			(886)	(886)
Balance, March 31, 2005	$ -	$ 4,463	$ 17,662	$ 22,125

ITEM 4. CONTROLS AND PROCEDURES.

Our management, with the participation of the CEO and CFO of our general partner, has evaluated the effectiveness of our disclosure controls and procedures, including internal controls over financial reporting, as of the end of the period covered by this report. Based on their evaluation, the CEO and CFO of our general partner have concluded that our disclosure controls and procedures, including internal controls over financial reporting, are effective to ensure that material information relating to our partnership is made known to management on a timely basis. Our CEO and CFO noted no material weaknesses in the design or operation of our internal controls over

financial reporting that are likely to adversely affect our ability to record, process, summarize and report financial information. Also, they detected no fraud involving management or employees who have a significant role in our internal controls over financial reporting.

Other than the events discussed under “Merger with GulfTerra and Related Transactions and Dixie Pipeline Company” below, there have been no changes in our internal controls over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) that have not been evaluated by management and no other factors that occurred during our last fiscal quarter that have materially affected or are reasonably likely to materially affect our internal controls over financial reporting.

Collectively, these disclosure controls and procedures are designed to provide us with reasonable assurance that the information required to be disclosed in our periodic reports filed with the SEC is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Our management does not expect that our disclosure controls and procedures will prevent all errors and all fraud. Based on the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been detected.

Merger with GulfTerra and Related Transactions and Dixie Pipeline Company. As presented under Section 9A “Controls and Procedures” of our 2004 annual report on Form 10-K, we completed the GulfTerra Merger and the acquisition of certain South Texas midstream assets from El Paso on September 30, 2004, which on a combined basis met the criteria of being a material acquisition for us. On June 22, 2004, the Office of the Chief Accountant of the SEC issued guidance regarding the reporting of internal controls over financial reporting in connection with a major acquisition. On October 6, 2004, the SEC revised its guidance to include expectations of quarterly reporting updates of new internal controls and the status of the controls regarding any exempted businesses. On October 18, 2004, the Disclosure Committee of Enterprise GP met and voted to recommend the exclusion of GulfTerra and the South Texas midstream assets from the scope of Enterprise’s Sarbanes-Oxley Section 404 Annual Report on Internal Control Over Financial Reporting as of December 31, 2004. A summary of the reasons for this exclusion is found under Section 9A of our 2004 annual report on Form 10-K.

In February 2005, we purchased ChevronTexaco’s 26% ownership interest in Dixie Pipeline Company (“Dixie”). As a result, Dixie became a consolidated subsidiary of Enterprise and our Unaudited Condensed Statement of Consolidated Operations for the three months ended March 31, 2005 includes one month of consolidated results from Dixie. Prior to our purchase of the ChevronTexaco interest, we accounted for our investment in Dixie using the equity method. Our management, with the participation of the Disclosure Committee of Enterprise GP, has evaluated the effectiveness of Dixie’s disclosure controls and procedures as of March 31 2005. Based on this evaluation, the CEO and CFO of our general partner have concluded that Dixie’s disclosure controls and procedures are effective to ensure that material information relating to Dixie’s financial condition and results of operations is made known to us on a timely basis.

PART II. OTHER INFORMATION.

ITEM 1. LEGAL PROCEEDINGS.

See Part I, Item 1, Financial Statements, Note 16, "Litigation," which is incorporated herein by reference.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.

We did not repurchase any of our common units during the three months ended March 31, 2005. As of March 31, 2005, we and our affiliates are authorized to repurchase up to 618,400 common units under the December 1998 common unit repurchase program. Common units repurchased under this publicly announced program are classified as treasury units.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES.

None.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

None.

ITEM 5. OTHER INFORMATION.

None.

ITEM 6. EXHIBITS.

Exhibit No.	Exhibit*
2.1	Purchase and Sale Agreement between Coral Energy, LLC and Enterprise Products Operating L.P. dated September 22, 2000 (incorporated by reference to Exhibit 10.1 to Form 8-K filed September 26, 2000).
2.2	Purchase and Sale Agreement dated January 16, 2002 by and between Diamond-Koch, L.P. and Diamond-Koch III, L.P. and Enterprise Products Texas Operating L.P. (incorporated by reference to Exhibit 10.1 to Form 8-K filed February 8, 2002.)
2.3	Purchase and Sale Agreement dated January 31, 2002 by and between D-K Diamond-Koch, L.L.C., Diamond-Koch, L.P. and Diamond-Koch III, L.P. as Sellers and Enterprise Products Operating L.P. as Buyer (incorporated by reference to Exhibit 10.2 to Form 8-K filed February 8, 2002).
2.4	Purchase Agreement by and between E-Birchtree, LLC and Enterprise Products Operating L.P. dated July 31, 2002 (incorporated by reference to Exhibit 2.2 to Form 8-K filed August 12, 2002).
2.5	Purchase Agreement by and between E-Birchtree, LLC and E-Cypress, LLC dated July 31, 2002 (incorporated by reference to Exhibit 2.1 to Form 8-K filed August 12, 2002).
2.6	Merger Agreement, dated as of December 15, 2003, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products Management LLC, GulfTerra Energy Partners, L.P. and GulfTerra Energy Company, L.L.C. (incorporated by reference to Exhibit 2.1 to Form 8-K filed December 15, 2003).
2.7	Amendment No. 1 to Merger Agreement, dated as of August 31, 2004, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products Management LLC, GulfTerra Energy Partners, L.P. and GulfTerra Energy Company, L.L.C. (incorporated by reference to Exhibit 2.1 to Form 8-K filed September 7, 2004).
2.8	Parent Company Agreement, dated as of December 15, 2003, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products GTM, LLC, El Paso Corporation, Sabine River Investors I, L.L.C., Sabine River Investors II, L.L.C., El Paso EPN Investments, L.L.C. and GulfTerra GP Holding Company (incorporated by reference to Exhibit 2.2 to Form 8-K

	filed December 15, 2003).
2.9	Amendment No. 1 to Parent Company Agreement, dated as of April 19, 2004, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products GTM, LLC, El Paso Corporation, Sabine River Investors I, L.L.C., Sabine River Investors II, L.L.C., El Paso EPN Investments, L.L.C. and GulfTerra GP Holding Company (incorporated by reference to Exhibit 2.1 to the Form 8-K filed April 21, 2004).
2.10	Second Amended and Restated Limited Liability Company Agreement of GulfTerra Energy Company, L.L.C., adopted by GulfTerra GP Holding Company, a Delaware corporation, and Enterprise Products GTM, LLC, a Delaware limited liability company, as of December 15, 2003, (incorporated by reference to Exhibit 2.3 to Form 8-K filed December 15, 2003).
2.11	Amendment No. 1 to Second Amended and Restated Limited Liability Company Agreement of GulfTerra Energy Company, L.L.C. adopted by Enterprise Products GTM, LLC as of September 30, 2004 (incorporated by reference to Exhibit 2.11 to Registration Statement on Form S-4 filed December 27, 2004).
2.12	Purchase and Sale Agreement (Gas Plants), dated as of December 15, 2003, by and between El Paso Corporation, El Paso Field Services Management, Inc., El Paso Transmission, L.L.C., El Paso Field Services Holding Company and Enterprise Products Operating L.P. (incorporated by reference to Exhibit 2.4 to Form 8-K filed December 15, 2003).
3.1	Fourth Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P., dated effective as of October 1, 2004 (incorporated by reference to Exhibit 3.1 to Form 8-K filed October 6, 2004).
3.2	Second Amended and Restated Limited Liability Company Agreement of Enterprise Products GP, LLC, among Duncan Family Interests, Inc., Dan Duncan LLC, and GulfTerra GP Holding Company dated September 30, 2004 (incorporated by reference to Exhibit 3.1 to Form 8-K filed September 30, 2004).
3.3	Application for Admission by Enterprise GP Holdings L.P. as a Substituted Member of Enterprise Products GP, LLC (incorporated by reference to Exhibit 3.1 to Form 8-K filed January 18, 2005).
3.4	Amended and Restated Agreement of Limited Partnership of Enterprise Products Operating L.P. dated as of July 31, 1998 (restated to include all agreements through December 10, 2003)(incorporated by reference to Exhibit 3.3 to Form 10-Q filed August 9, 2004).
4.1	Indenture dated as of March 15, 2000, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and First Union National Bank, as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K filed March 10, 2000).
4.2	First Supplemental Indenture dated as of January 22, 2003, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wachovia Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Registration Statement on Form S-4, Reg. No. 333-102776, filed January 28, 2003).
4.3	Global Note representing $350 million principal amount of 6.375% Series B Senior Notes due 2013 with attached Guarantee (incorporated by reference to Exhibit 4.4 to Registration Statement on Form S-4, Reg. No. 333-102776, filed January 28, 2003).
4.4	Second Supplemental Indenture dated as of February 14, 2003, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wachovia Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 10-K filed March 31, 2003).
4.5	Global Note representing $500 million principal amount of 6.875% Series B Senior Notes due 2033 with attached Guarantee (incorporated by reference to Exhibit 4.8 to Form 10-K filed March 31, 2003).
4.6	Global Note representing $350 million principal amount of 8.25% Senior Notes due 2005 (incorporated by reference to Exhibit 4.2 to Form 8-K filed March 10, 2000).
4.7	Global Notes representing $450 million principal amount of 7.50% Senior Notes due 2011 (incorporated by reference to Exhibit 4.1 to Form 8-K filed January 25, 2001).
4.8	Form of Common Unit certificate (incorporated by reference to Exhibit 4.1 to Registration Statement on Form S-1/A; File No. 333-52537, filed July 21, 1998).
4.9	Contribution Agreement dated September 17, 1999 (incorporated by reference to Exhibit "B" to Schedule 13D filed September 27, 1999 by Tejas Energy, LLC).
4.10	Registration Rights Agreement dated September 17, 1999 (incorporated by reference to Exhibit

	"E" to Schedule 13D filed September 27, 1999 by Tejas Energy, LLC).
4.11	Unitholder Rights Agreement dated September 17, 1999 (incorporated by reference to Exhibit "C" to Schedule 13D filed September 27, 1999 by Tejas Energy, LLC).
4.12	Amendment No. 1, dated September 12, 2003, to Unitholder Rights Agreement dated September 17, 1999 (incorporated by reference to Exhibit 4.1 to Form 8-K filed September 15, 2003).
4.13	Agreement dated as of March 4, 2004 among Enterprise Products Partners L.P., Shell US Gas & Power LLC and Kayne Anderson MLP Investment Company (incorporated by reference to Exhibit 4.31 to Form S-3 Registration Statement, Reg. No. 333-123150, filed March 4, 2004).
4.14	$750 Million Multi-Year Revolving Credit Agreement dated as of August 25, 2004, among Enterprise Products Operating L.P., the Lenders party thereto, Wachovia Bank, National Association, as Administrative Agent, Citibank, N.A. and JPMorgan Chase Bank, as Co-Syndication Agents, Mizuho Corporate Bank, Ltd., SunTrust Bank and The Bank of Nova Scotia, as Co-Documentation Agents, Wachovia Capital Markets, LLC, Citigroup Global Markets Inc. and JPMorgan Chase Securities, Inc., as Joint Lead Arrangers and Joint Book Runners (incorporated by reference to Exhibit 4.1 to Form 8-K filed on August 30, 2004).
4.15	Guaranty Agreement dated as of August 25, 2004, by Enterprise Products Partners L.P. in favor of Wachovia Bank, National Association, as Administrative Agent for the several lenders that are or become parties to the Credit Agreement included as Exhibit 4.1, above (incorporated by reference to Exhibit 4.2 to Form 8-K filed on August 30, 2004).
4.16	$2.25 Billion 364-Day Revolving Credit Agreement dated as of August 25, 2004, among Enterprise Products Operating L.P., the Lenders party thereto, Wachovia Bank, National Association, as Administrative Agent, Citicorp North America, Inc. and Lehman Commercial Paper Inc., as Co-Syndication Agents, JPMorgan Chase Bank, UBS Loan Finance LLC and Morgan Stanley Senior Funding, Inc., as Co-Documentation Agents, Wachovia Capital Markets, LLC, Citigroup Global Markets Inc. and Lehman Brothers Inc., as Joint Lead Arrangers and Joint Book Runners (incorporated by reference to Exhibit 4.3 to Form 8-K filed on August 30, 2004).
4.17	Guaranty Agreement dated as of August 25, 2004, by Enterprise Products Partners L.P. in favor of Wachovia Bank, National Association, as Administrative Agent for the several lenders that are or become parties to the Credit Agreement included as Exhibit 4.3, above (incorporated by reference to Exhibit 4.4 to Form 8-K filed on August 30, 2004).
4.18	Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K filed on October 6, 2004).
4.19	First Supplemental Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Form 8-K filed on October 6, 2004).
4.20	Second Supplemental Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed on October 6, 2004).
4.21	Third Supplemental Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.4 to Form 8-K filed on October 6, 2004).
4.22	Fourth Supplemental Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.5 to Form 8-K filed on October 6, 2004).
4.23	Global Note representing $500 million principal amount of 4.000% Series B Senior Notes due 2007 with attached Guarantee (incorporated by reference to Exhibit 4.14 to Form S-3 Registration Statement Reg. No. 333-123150 filed on March 4, 2004).
4.24	Global Note representing $500 million principal amount of 5.600% Series B Senior Notes due 2014 with attached Guarantee (incorporated by reference to Exhibit 4.17 to Form S-3 Registration Statement Reg. No. 333-123150 filed on March 4, 2004).
4.25	Global Note representing $150 million principal amount of 5.600% Series B Senior Notes due

	2014 with attached Guarantee (incorporated by reference to Exhibit 4.18 to Form S-3 Registration Statement Reg. No. 333-123150 filed on March 4, 2004).
4.26	Global Note representing $350 million principal amount of 6.650% Series B Senior Notes due 2034 with attached Guarantee (incorporated by reference to Exhibit 4.19 to Form S-3 Registration Statement Reg. No. 333-123150 filed on March 4, 2004).
4.27	Global Note representing $500 million principal amount of 4.625% Series B Senior Notes due 2009 with attached Guarantee (incorporated by reference to Exhibit 4.27 to Form 10-K for the year ended December 31, 2004 filed on March 15, 2005).
4.28	Registration Rights Agreement dated as of October 4, 2004, among Enterprise Products Operating L.P., Enterprise Products Partners L.P. and the Initial Purchasers named therein (incorporated by reference to Exhibit 4.17 to Form 8-K filed on October 6, 2004).
4.29	Fifth Supplemental Indenture dated as of March 2, 2005, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Form 8-K filed on March 3, 2005).
4.30	Sixth Supplemental Indenture dated as of March 2, 2005, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed on March 3, 2005).
4.31	Rule 144A Global Note representing $250,000,000 principal amount of 5.00% Series A Senior Notes due 2015 with attached Guarantee (incorporated by reference to Exhibit 4.4 to Form 8-K filed on March 3, 2005).
4.32	Rule 144A Note representing $250,000,000 principal amount of 5.75% Series A Senior Notes due 2035 with attached Guarantee (incorporated by reference to Exhibit 4.5 to Form 8-K filed on March 3, 2005).
4.33	Registration Rights Agreement dated as of March 2, 2005, among Enterprise Products Partners, L.P., Enterprise Products Operating L.P. and the Initial Purchasers named therein (incorporated by reference to Exhibit 4.6 to Form 8-K filed on March 3, 2005).
4.34	Exchange and Registration Rights Agreement, dated as of September 30, 2004, among GulfTerra GP Holding Company, Enterprise Products GP, LLC and Enterprise Products Partners L.P. (incorporated by reference to Exhibit 4.1 to Form 8-K filed on September 30, 2004).
4.35	Performance Guaranty dated as of September 30, 2004, by DFI Delaware Holdings L.P. in favor of GulfTerra GP Holding Company (incorporated by reference to Exhibit 4.2 to Form 8-K filed on September 30, 2004).
4.36	Registration Rights Agreement, dated as of September 30, 2004, between El Paso Corporation and Enterprise Products Partners L.P. (incorporated by reference to Exhibit 4.3 to Form 8-K filed on September 30, 2004).
4.37	Assumption Agreement dated as of September 30, 2004 between Enterprise Products Partners L.P. and GulfTerra Energy Partners, L.P. relating to the assumption by Enterprise of GulfTerra's obligations under the GulfTerra Series F2 Convertible Units (incorporated by reference to Exhibit 4.4 to Form 8-K/A-1 filed on October 5, 2004).
4.38	Statement of Rights, Privileges and Limitations of Series F Convertible Units, included as Annex A to Third Amendment to the Second Amended and Restated Agreement of Limited Partnership of GulfTerra Energy Partners, L.P., dated May 16, 2003 (incorporated by reference to Exhibit 3.B.3 to Current Report on Form 8-K of GulfTerra Energy Partners, L.P., file no. 001-11680, filed with the Commission on May 19, 2003).
4.39	Unitholder Agreement between GulfTerra Energy Partners, L.P. and Fletcher International, Inc. dated May 16, 2003 (incorporated by reference to Exhibit 4.L to Current Report on Form 8-K of GulfTerra Energy Partners, L.P., file no. 001-11680, filed with the Commission on May 19, 2003).
4.40	Indenture dated as of May 17, 2001 among GulfTerra Energy Partners, L.P., GulfTerra Energy Finance Corporation, the Subsidiary Guarantors named therein and the Chase Manhattan Bank, as Trustee (filed as Exhibit 4.1 to GulfTerra’s Registration Statement on Form S-4 filed June 25, 2001, Registration Nos. 333-63800 through 333-63800-20); First Supplemental Indenture dated as of April 18, 2002 (filed as Exhibit 4.E.1 to GulfTerra’s 2002 First Quarter Form 10-Q); Second Supplemental Indenture dated as of April 18, 2002 (filed as Exhibit 4.E.2 to GulfTerra’s 2002 First Quarter Form 10-Q); Third Supplemental Indenture dated as of October 10, 2002 (filed as Exhibit

	4.E.3 to GulfTerra’s 2002 Third Quarter Form 10-Q); Fourth Supplemental Indenture dated as of November 27, 2002 (filed as Exhibit 4.E.1 to GulfTerra’s Current Report on Form 8-K dated March 19, 2003); Fifth Supplemental Indenture dated as of January 1, 2003 (filed as Exhibit 4.E.2 to GulfTerra’s Current Report on Form 8-K dated March 19, 2003); Sixth Supplemental Indenture dated as of June 20, 2003 (filed as Exhibit 4.E.1 to GulfTerra’s 2003 Second Quarter Form 10-Q, file no. 001-11680).
4.41	Seventh Supplemental Indenture dated as of August 17, 2004 (filed as Exhibit 4.E.1 to GulfTerra’s Current Report on Form 8-K filed on August 19, 2004, file no. 001-11680).
4.42	Indenture dated as of November 27, 2002 by and among GulfTerra Energy Partners, L.P., GulfTerra Energy Finance Corporation, the Subsidiary Guarantors named therein and JPMorgan Chase Bank, as Trustee (filed as Exhibit 4.1 to GulfTerra’s Current Report of Form 8-K dated December 11, 2002); First Supplemental Indenture dated as of January 1, 2003 (filed as Exhibit 4.1.1 to GulfTerra’s Current Report on Form 8-K dated March 19, 2003); Second Supplemental Indenture dated as of June 20, 2003 (filed as Exhibit 4.1.1 to GulfTerra’s 2003 Second Quarter Form 10-Q, file no. 001-11680).
4.43	Third Supplemental Indenture dated as of August 17, 2004 (filed as Exhibit 4.1.1 to GulfTerra’s Current Report on Form 8-K filed on August 19, 2004, file no. 001-11680).
4.44	Indenture dated as of March 24, 2003 by and among GulfTerra Energy Partners, L.P., GulfTerra Energy Finance Corporation, the Subsidiary Guarantors named therein and JPMorgan Chase Bank, as Trustee dated as of March 24, 2003 (filed as Exhibit 4.K to GulfTerra’s Quarterly Report on Form 10-Q dated May 15, 2003); First Supplemental Indenture dated as of June 30, 2003 (filed as Exhibit 4.K.1 to GulfTerra’s 2003 Second Quarter Form 10-Q, file no. 001-11680).
4.45	Second Supplemental Indenture dated as of August 17, 2004 (filed as Exhibit 4.K.1 to GulfTerra’s Current Report on Form 8-K filed on August 19, 2004, file no. 001-11680).
4.46	Indenture dated as of July 3, 2003, by and among GulfTerra Energy Partners, L.P., GulfTerra Energy Finance Corporation, the Subsidiary Guarantors named therein and Wells Fargo Bank, National Association, as Trustee (Filed as Exhibit 4.L to GulfTerra’s 2003 Second Quarter Form 10-Q, file no. 001-11680).
4.47	First Supplemental Indenture dated as of August 17, 2004 (filed as Exhibit 4.K.1 to GulfTerra’s Current Report on Form 8-K filed on August 19, 2004, file no. 001-11680).
10.1	Transportation Contract between Enterprise Products Operating L.P. and Enterprise Transportation Company dated June 1, 1998 (incorporated by reference to Exhibit 10.3 to Registration Statement Form S-1/A filed July 8, 1998).
10.2	Partnership Agreement among Sun BEF, Inc., Liquid Energy Fuels Corporation and Enterprise Products Company dated May 1, 1992 (incorporated by reference to Exhibit 10.5 to Registration Statement on Form S-1 filed May 13, 1998).
10.3	Propylene Facility and Pipeline Agreement between Enterprise Petrochemical Company and Hercules Incorporated dated December 13, 1978 (incorporated by reference to Exhibit 10.9 to Registration Statement on Form S-l filed May 13, 1998).
10.4	Restated Operating Agreement for the Mont Belvieu Fractionation Facilities Chambers County, Texas among Enterprise Products Company, Texaco Producing Inc., El Paso Hydrocarbons Company and Champlin Petroleum Company dated July 17, 1985 (incorporated by reference to Exhibit 10.10 to Registration Statement on Form S-l/A filed July 8, 1998).
10.5	Amendment to Propylene Facility and Pipeline Agreement and Propylene Sales Agreement between HIMONT U.S.A., Inc. and Enterprise Products Company dated January 1, 1993 (incorporated by reference to Exhibit 10.12 to Registration Statement on Form S-l/A filed July 8, 1998).
10.6	Amendment to Propylene Facility and Pipeline Agreement and Propylene Sales Agreement between HIMONT U.S.A., Inc. and Enterprise Products Company dated January 1, 1995 (incorporated by reference to Exhibit 10.13 to Registration Statement on Form S-l/A filed July 8, 1998).
10.7	Seventh Amendment to Conveyance of Gas Processing Rights, dated as of April 1, 2004 among Enterprise Gas Processing, LLC, Shell Oil Company, Shell Exploration & Production Company, Shell Offshore Inc., Shell Consolidated Energy Resources Inc., Shell Land & Energy Company, Shell Frontier Oil & Gas Inc. and Shell Gulf of Mexico Inc. (incorporated by reference to Exhibit 10.1 to Form 8-K filed April 26, 2004).

10.8 ***	Enterprise Products 1998 Long-Term Incentive Plan, amended and restated as of April 8, 2004 (incorporated by reference to Appendix B to Notice of Written Consent dated April 22, 2004, filed April 22, 2004).
10.9 ***	Form of Option Grant Award under 1998 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.3 to Form S-8 Registration Statement, Reg. No. 333-115633, filed May 19, 2004).
10.10***	Form of Restricted Unit Grant under the Enterprise Products 1998 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.3 to Form S-8 Registration Statement, Reg. No. 333-115633, filed May 19, 2004).
10.11***	Letter Agreement dated September 30, 2004, among Enterprise Products Partners L.P., GulfTerra Energy Partners, L.P. and Bart Heijermans (incorporated by reference to Exhibit 10.1 to Form 8-K/A-2 filed on October 18, 2004).
10.12***	1998 Omnibus Compensation Plan of GulfTerra Energy Partners, L.P., Amended and Restated as of January 1, 1999 (incorporated by reference to Exhibit 10.9 to Form 10-K for the year ended December 31, 1998 of GulfTerra Energy Partners, L.P., file no. 001-11680); Amendment No. 1, dated as of December 1, 1999 (incorporated by reference to Exhibit 10.8.1 to Form 10-Q for the quarter ended June 30, 2000 of GulfTerra Energy Partners, L.P., file no. 001-116800); Amendment No. 2 dated as of May 15, 2003 (incorporated by reference to Exhibit 10.M.1 to Form 10-Q for the quarter ended June 30, 2003 of GulfTerra Energy Partners, L.P., file no. 001-11680).
10.13	Second Amended and Restated Administrative Services Agreement by and among EPCO, Inc., Enterprise Products Partners L.P., Enterprise Products Operating L.P., Enterprise Products GP, LLC and Enterprise Products OLPGP, Inc., dated effective as of October 1, 2004 (incorporated by reference to Exhibit 10.1 to Form 8-K filed October 27, 2004).
18.1	Letter regarding Change in Accounting Principles dated May 4, 2004 (incorporated by reference to Exhibit 18.1 to Form 10-Q filed May 10, 2004).
31.1#	Sarbanes-Oxley Section 302 certification of Robert G. Phillips for Enterprise Products Partners L.P. for the March 31, 2005 quarterly report on Form 10-Q.
31.2#	Sarbanes-Oxley Section 302 certification of Michael A. Creel for Enterprise Products Partners L.P. for the March 31, 2005 quarterly report on Form 10-Q .
32.1#	Section 1350 certification of Robert G. Phillips for the March 31, 2005 quarterly report on Form 10-Q.
32.2#	Section 1350 certification of Michael A. Creel for the March 31, 2005 quarterly report on Form 10-Q.
99.1#	Glossary following the Table of Contents of Form 10-K for the year ended December 31, 2004.

*	With respect to any exhibits incorporated by reference to any Exchange Act filings, the Commission file number for Enterprise Products Partners L.P. is 1-14323.
***	Identifies management contract and compensatory plan arrangements.
#	Filed with this report.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this quarterly report on Form 10-Q to be signed on its behalf by the undersigned thereunto duly authorized, in the City of Houston, State of Texas on May 10, 2005.

ENTERPRISE PRODUCTS PARTNERS L.P.
(A Delaware Limited Partnership)

By:	Enterprise Products GP, LLC,
	as General Partner

By:	___/s/ Michael J. Knesek_____________________
Name:		Michael J. Knesek
Title:		Senior Vice President, Controller
		and Principal Accounting Officer
		of the General Partner