UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2006

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 (State or Other Jurisdiction of Incorporation or Organization)	76-0568219 (I.R.S. Employer Identification No.)
2727 North Loop West, Houston, Texas (Address of Principal Executive Offices)	77008 (Zip Code)

(713) 880-6500
(Registrant’s Telephone Number, Including Area Code)

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 þ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Large accelerated filer þ Accelerated filer o Non-accelerated filer o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o No þ

There were 408,699,837 common units of Enterprise Products Partners L.P. outstanding at May 1, 2006. These common units trade on the New York Stock Exchange under the ticker 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		2
Unaudited Condensed Statements of Consolidated Operations and Comprehensive Income		3
Unaudited Condensed Statements of Consolidated Cash Flows		4
Unaudited Condensed Statements of Consolidated Partners’ Equity		5
Notes to Unaudited Condensed Consolidated Financial Statements:
1. Partnership Organization and Basis of Financial Statement Presentation		6
2. General Accounting Policies and Related Matters		7
3. Accounting for Equity Awards		8
4. Financial Instruments		10
5. Inventories		11
6. Property, Plant and Equipment		12
7. Investments in and Advances to Unconsolidated Affiliates		13
8. Business Combinations and Other Acquisitions		14
9. Intangible Assets and Goodwill		15
10. Debt Obligations		16
11. Partners’ Equity		18
12. Business Segments		20
13. Related Party Transactions		24
14. Earnings per Unit		26
15. Commitments and Contingencies		28
16. Significant Risks and Uncertainties — Hurricanes		29
17. Supplemental Cash Flow Information		30
18. Condensed Financial Information of Operating Partnership		30
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		32
Item 3. Quantitative and Qualitative Disclosures about Market Risk		49
Item 4. Controls and Procedures		51
PART II. OTHER INFORMATION
Item 1. Legal Proceedings		52
Item 1A. Risk Factors		52
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		52
Item 3. Defaults upon Senior Securities		52
Item 4. Submission of Matters to a Vote of Security Holders		52
Item 5. Other Information		52
Item 6. Exhibits		52
Signatures		58
Certification of Robert G. Phillips Pursuant to Section 302
Certification of Michael A. Creel Pursuant to Section 302
Certification of Robert G. Phillips Pursuant to Section 1350
Certification of Michael A. Creel Pursuant to Section 1350

1

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,
	2006		2005
ASSETS
Current assets
Cash and cash equivalents	$	34,991	$	42,098
Restricted cash		5,907		14,952
Accounts and notes receivable — trade, net of allowance for doubtful accounts of $20,585 at March 31, 2006 and $25,849 at December 31, 2005		1,088,121		1,448,026
Accounts receivable — related parties		11,696		6,557
Inventories		255,415		339,606
Prepaid and other current assets		107,774		120,208
Total current assets		1,503,904		1,971,447
Property, plant and equipment, net		8,825,047		8,689,024
Investments in and advances to unconsolidated affiliates		463,532		471,921
Intangible assets, net of accumulated amortization of $184,309 at March 31, 2006 and $163,121 at December 31, 2005		930,069		913,626
Goodwill		494,033		494,033
Deferred tax asset		4,821		3,606
Other assets		97,099		47,359
Total assets	$	12,318,505	$	12,591,016
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accounts payable — trade	$	199,245	$	265,699
Accounts payable — related parties		4,507		23,367
Accrued gas payables		1,197,878		1,372,837
Accrued expenses		27,727		30,294
Accrued interest		71,233		71,193
Other current liabilities		132,962		126,881
Total current liabilities		1,633,552		1,890,271
Long-term debt		4,396,315		4,833,781
Other long-term liabilities		113,093		84,486
Minority interest		115,196		103,169
Commitments and contingencies
Partners’ equity
Limited partners
Common units (407,959,188 units outstanding at March 31, 2006 and 389,109,564 units outstanding at December 31, 2005)		5,916,557		5,542,700
Restricted common units (740,649 units outstanding at March 31, 2006 and 751,604 units outstanding at December 31, 2005)		4,671		18,638
General partner		120,839		113,496
Accumulated other comprehensive income		18,282		19,072
Deferred compensation				(14,597	)
Total partners’ equity		6,060,349		5,679,309
Total liabilities and partners’ equity	$	12,318,505	$	12,591,016

See Notes to Unaudited Condensed Consolidated Financial Statements

2

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,
	2006			2005
REVENUES
Third parties	$	3,159,999		$	2,497,329
Related parties		90,075			58,193
Total		3,250,074			2,555,522
COST AND EXPENSES
Operating costs and expenses
Third parties		2,945,220			2,318,073
Related parties		101,643			65,571
Total operating costs and expenses		3,046,863			2,383,644
General and administrative costs
Third parties		2,732			5,018
Related parties		11,008			9,675
Total general and administrative costs		13,740			14,693
Total costs and expenses		3,060,603			2,398,337
EQUITY IN INCOME OF UNCONSOLIDATED AFFILIATES		4,029			8,279
OPERATING INCOME		193,500			165,464
OTHER INCOME (EXPENSE)
Interest expense		(58,077	)		(53,413	)
Other, net		1,969			919
Other expense		(56,108	)		(52,494	)
INCOME BEFORE PROVISION FOR INCOME TAXES, MINORITY INTEREST AND CHANGE IN ACCOUNTING PRINCIPLE		137,392			112,970
Provision for income taxes		(2,892	)		(1,769	)
INCOME BEFORE MINORITY INTEREST AND CHANGE IN ACCOUNTING PRINCIPLE		134,500			111,201
Minority interest		(2,198	)		(1,945	)
INCOME BEFORE CHANGE IN ACCOUNTING PRINCIPLE		132,302			109,256
Cumulative effect of change in accounting principle (see Note 3)		1,475
NET INCOME		133,777			109,256
Amortization of cash flow financing hedges		(1,041	)		(995	)
Change in fair value of commodity hedges		251			(1,434	)
COMPREHENSIVE INCOME	$	132,987		$	106,827
ALLOCATION OF NET INCOME:
Limited partners’ interest in net income	$	112,369		$	93,723
General partner interest in net income	$	21,408		$	15,533
EARNINGS PER UNIT: (see Note 14)
Basic income per unit before change in accounting principle	$	0.28		$	0.25
Basic income per unit	$	0.28		$	0.25
Diluted income per unit before change in accounting principle	$	0.28		$	0.25
Diluted income per unit	$	0.28		$	0.25

See Notes to Unaudited Condensed Consolidated Financial Statements

3

ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Dollars in thousands)

	For the Three Months
	Ended March 31,
	2006			2005
OPERATING ACTIVITIES
Net income	$	133,777		$	109,256
Adjustments to reconcile net income to cash flows provided from operating activities:
Depreciation, amortization and accretion in operating costs and expenses		104,816			99,965
Depreciation and amortization in general and administrative costs		1,501			1,922
Amortization in interest expense		250			(477	)
Equity in income of unconsolidated affiliates		(4,029	)		(8,279	)
Distributions received from unconsolidated affiliates		8,253			21,838
Cumulative effect of change in accounting principle		(1,475	)
Operating lease expense paid by EPCO, Inc.		528			528
Minority interest		2,198			1,945
Gain on sale of assets		(61	)		(5,436	)
Deferred income tax expense		1,487			1,802
Changes in fair market value of financial instruments		(53	)		102
Net effect of changes in operating accounts (see Note 17)		247,084			(58,920	)
Net cash provided from operating activities		494,276			164,246
INVESTING ACTIVITIES
Capital expenditures		(278,698	)		(175,230	)
Contributions in aid of construction costs		12,180			8,942
Proceeds from sale of assets		75			42,158
Decrease in restricted cash		9,045			15,799
Cash used for business combinations and asset purchases		(38,100	)		(150,478	)
Acquisition of intangible asset					(1,750	)
Advances to Jonah affiliate (see Note 13)		(53,549	)
Investments in unconsolidated affiliates		(7,979	)		(80,569	)
Advances (to) from unconsolidated affiliates		8,381			(8,065	)
Cash used in investing activities		(348,645	)		(349,193	)
FINANCING ACTIVITIES
Borrowings under debt agreements		510,000			1,382,175
Repayments of debt		(920,000	)		(1,500,979	)
Debt issuance costs					(4,425	)
Distributions paid to partners		(193,543	)		(164,692	)
Distributions paid to minority interests		(1,495	)		(1,330	)
Contributions from minority interests		11,372			6,327
Net proceeds from issuance of common units		440,928			501,045
Cash provided by (used in) financing activities		(152,738	)		218,121
NET CHANGE IN CASH AND CASH EQUIVALENTS		(7,107	)		33,174
CASH AND CASH EQUIVALENTS, JANUARY 1		42,098			24,556
CASH AND CASH EQUIVALENTS, MARCH 31	$	34,991		$	57,730

See Notes to Unaudited Condensed Consolidated Financial Statements

4

ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED PARTNERS’ EQUITY

(See Note 11 for Unit History and Detail of Changes in Limited Partners’ Equity)

(Dollars in thousands)

										Accumulated
										Other
	Limited			General			Deferred			Comprehensive
	Partners			Partner			Compensation			Income			Total
Balance, December 31, 2005	$	5,561,338		$	113,496		$	(14,597	)	$	19,072		$	5,679,309
Net income		112,369			21,408									133,777
Operating leases paid by EPCO, Inc.		517			11									528
Cash distributions to partners		(170,564	)		(22,595	)								(193,159	)
Unit option reimbursements to EPCO, Inc.		(376	)		(8	)								(384	)
Net proceeds from sales of common units		431,391			8,804									440,195
Proceeds from exercise of unit options		718			15									733
Change in accounting method for equity awards (see Note 3)		(15,814	)		(322	)		14,597						(1,539	)
Amortization of equity awards		1,649			30									1,679
Change in fair value of commodity hedges											251			251
Interest rate hedging financial instruments recorded as cash flow hedges:
— Amortization of gain as component of interest expense											(1,041	)		(1,041	)
Balance, March 31, 2006	$	5,921,228		$	120,839		$	—		$	18,282		$	6,060,349

See Notes to Unaudited Condensed Consolidated Financial Statements

5

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. Partnership Organization and Basis of Financial Statement Presentation

Partnership Organization and Formation

     Enterprise Products Partners L.P. is a publicly traded Delaware limited partnership, the common units of which are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “EPD.” Unless the context requires otherwise, references to “we,” “us,” “our,” or “Enterprise Products Partners” are intended to mean the consolidated business and operations of Enterprise Products Partners L.P. and its subsidiaries.

     We were formed in April 1998 to own and operate certain natural gas liquids (“NGLs”) related businesses of EPCO, Inc. (“EPCO”). 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 Products GP”). Enterprise Products GP is owned 100% by Enterprise GP Holdings L.P. (“Enterprise GP Holdings”), a publicly traded affiliate, the common units of which are listed on the NYSE under the ticker symbol “EPE.” The general partner of Enterprise GP Holdings is EPE Holdings, LLC (“EPE Holdings”), a wholly owned subsidiary of Dan Duncan LLC, the membership interests of which is owned by Dan L. Duncan. We, Enterprise Products GP, Enterprise GP Holdings, EPE Holdings and Dan Duncan LLC are affiliates and under common control of Dan L. Duncan, the Chairman and controlling shareholder of EPCO.

     References to “TEPPCO” mean TEPPCO Partners, L.P., which is a related party affiliate to us. References to “TEPPCO GP” refer to the general partner of TEPPCO, which is wholly owned by a private company subsidiary of EPCO.

Basis of Presentation of Consolidated Financial Statements

     Our results of operations for the three months ended March 31, 2006 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.

     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 18 for condensed consolidated financial information of our Operating Partnership.

     In our opinion, 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 generally accepted accounting principles in the United States of America (“GAAP”) have been condensed or omitted pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). These unaudited financial statements should be read in conjunction with our annual report on Form 10-K for the year ended December 31, 2005 (Commission File No. 1-14323).

6

2. General Accounting Policies and Related Matters

Use of estimates

     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.

New accounting pronouncements

     Emerging Issues Task Force (“EITF”) 04-13, “Accounting for Purchases and Sale of Inventory With the Same Counterparty.” This accounting guidance requires that two or more inventory transactions with the same counterparty should be viewed as a single nonmonetary transaction, if the transactions were entered into in contemplation of one another. Exchanges of inventory between entities in the same line of business should be accounted for at fair value or recorded at carrying amounts, depending on the classification of such inventory. This guidance was effective during the first quarter of 2006, and our adoption of this guidance had no impact on our financial position, results of operations or cash flows.

Financial statements — change in accounting principle and reclassifications

     In January 2006, we adopted the provisions of Statement of Financial Accounting Standards (“SFAS”) 123(R), “Share-Based Payment,” which resulted in us recording a cumulative effect of accounting change of $1.5 million. For additional information regarding our adoption of SFAS 123(R), see Note 3.

     Certain reclassifications have been made to the prior year’s financial statements to conform to the current year presentation. During the second quarter of 2005, we changed the classification of changes in restricted cash in our Unaudited Condensed Statements of Consolidated Cash Flows to present such changes as an investing activity. We previously presented such changes as an operating activity. In the accompanying Unaudited Condensed Statements of Consolidated Cash Flows for the three months ended March 31, 2005, we reclassified the change in restricted cash to be consistent with our current presentation. This reclassification resulted in a $15.8 million decrease to cash flows used in investing activities and a corresponding decrease to cash provided from operating activities from the amounts previously presented for the three months ended March 31, 2005.

Accounting for employee benefit plans

     Dixie Pipeline Company (“Dixie”), a consolidated subsidiary, directly employs the personnel that operate its pipeline system and certain of these employees are eligible to participate in Dixie’s defined contribution plan and pension and postretirement benefit plans. Due to the immaterial nature of Dixie’s employee benefit plans to our consolidated financial position, results of operations and cash flows, our discussion is limited to the following:

     Defined contribution plan. Dixie contributed nominal amounts to its company-sponsored defined contribution plan during the three months ended March 31, 2006 and 2005.

     Pension and postretirement benefit plans. Dixie’s net pension benefit costs were $0.2 million and $0.1 million for the three months ended March 31, 2006 and 2005, respectively. Dixie’s net postretirement benefit costs were nominal for the three months ended March 31, 2006 and 2005. During the remainder of 2006, Dixie expects to contribute approximately $0.3 million to its postretirement benefit plan and between $2 million and $4.4 million to its pension plan.

7

3. Accounting for Equity Awards

     Effective January 1, 2006, we began to account for our equity awards using the provisions of SFAS 123(R). Historically, our equity awards were accounted for using the intrinsic value method described in Accounting Principles Board Opinion (“APB”) 25, “Accounting for Stock Issued to Employees.” SFAS 123(R) requires us to recognize compensation expense related to our equity awards based on the fair value of the award at the grant date. The fair value of an equity award is estimated using the Black-Scholes option pricing model. Under SFAS 123(R), the fair value of an award is amortized to earnings on a straight-line basis over the requisite service or vesting period.

     Upon our adoption of SFAS 123(R), we recognized a cumulative effect of change in accounting principle of $1.5 million (a benefit) based on SFAS 123(R)’s requirement to recognize compensation expense based upon the grant date fair value of an equity award and the application of an estimated forfeiture rate to unvested awards. In addition, previously recognized deferred compensation of $14.6 million related to nonvested (or restricted) common units was reversed on January 1, 2006.

     Prior to our adoption of SFAS 123(R), we did not recognize any compensation expense related to unit options; however, compensation expense was recognized in connection with awards granted by EPE Unit L.P. (the “Employee Partnership”) and the issuance of nonvested units. The effects of applying SFAS 123(R) during the first quarter of 2006 did not have a material effect on net income or basic and diluted earnings per unit.

     Since we adopted SFAS 123(R) using the modified prospective method, we have not restated the financial statements of prior periods. The following table shows the pro forma effects on our earnings for the three months ended March 31, 2005 as if the fair value method of SFAS 123, “Accounting for Stock-Based Compensation” had been used instead of the intrinsic-value method of APB 25. The only equity awards outstanding during the three months ended March 31, 2005 were unit options and nonvested units.

Reported net income	$	109,256
Additional unit option-based compensation expense estimated using fair value-based method		(177	)
Pro forma net income	$	109,079
Basic and diluted earnings per unit:
As reported and pro forma	$	0.25

Unit options

     Under EPCO’s 1998 Long-Term Incentive Plan (the “1998 Plan”), non-qualified incentive options to purchase a fixed number of our common units may be granted to EPCO’s key employees who perform management, administrative or operational functions for us. Generally, the exercise price of each option granted is equivalent to the market price of the underlying equity at the date of grant. In addition, options granted under the 1998 Plan have a weighted-average vesting period of four years and remain exercisable for ten years from the date of grant.

     EPCO purchases common units to fund its obligations under the 1998 Plan at fair value either in the open market or from us. When employees exercise unit options, we reimburse EPCO for the cash difference between the strike price paid by the employee and the actual purchase price paid by EPCO for the units issued to the employee.

     The fair value of each unit option is estimated on the date of grant using the Black-Scholes option pricing model, which incorporates various assumptions including (i) expected life of the options of seven years, (ii) risk-free interest rates ranging from 3.8% to 4.2%, (iii) expected distribution yield on our common units ranging from 8.8% to 9.2%, and (iv) expected unit price volatility on our common units ranging from 20% to 29%. In general, our assumption of expected life represents the period of time that options granted are expected to be outstanding based on an analysis of historical activity. Our selection of the risk-free interest rate is based on published yields for U.S. government securities with comparable

8

terms. The expected distribution yield and unit price volatility on our units is estimated based upon several factors, which include an analysis of our historical unit price volatility and distribution yield over a period equal to the expected life of the option granted.

     The information in the following table shows unit option activity under the 1998 Plan.

						Weighted-
						average
				Weighted-		remaining		Aggregate
	Number of			average strike		contractual		Intrinsic
	Units			price		term (in years)		Value (1)
Outstanding at December 31, 2005		2,082,000		$	22.16
Exercised		(29,000	)	$	12.88
Outstanding at March 31, 2006		2,053,000		$	22.29		7.56	$	3,655
Exercisable at March 31, 2006		698,000		$	19.45		5.34	$	3,655

(1) Aggregate intrinsic value reflects fully vested unit options at March 31, 2006.

     The total intrinsic value of unit options exercised during the first quarter of 2006 was $0.3 million. We recognized $0.1 million of compensation expense associated with unit options during the first quarter of 2006. As of March 31, 2006, we expect to incur $1.1 million of unrecognized compensation cost related to nonvested unit options over a weighted-average period of approximately three years. During the first quarter of 2006, we received cash of $0.7 million from unit option exercises, and our option-related reimbursements to EPCO were $0.4 million.

Nonvested units

     Under the 1998 Plan, we can issue nonvested (i.e., restricted) common units to key employees of EPCO and directors of our general partner. The 1998 Plan provides for the issuance of 3,000,000 restricted common units, of which 2,186,264 remain authorized for issuance at March 31, 2006.

     In general, our restricted unit awards entitle recipients to acquire the underlying common units (at no cost to them) once the defined vesting period expires, subject to certain forfeiture provisions. The restrictions on the nonvested units generally lapse four years from the date of grant. Compensation expense is recognized on a straight-line basis over the vesting period. The grant date fair value of nonvested units is estimated on the date of grant based on the market price of our common units.

     The following table provides a summary of our nonvested units in total at December 31, 2005 and changes during the first quarter of 2006.

				Weighted-
	Number of			average grant
	Units			date fair value
Nonvested at December 31, 2005		751,604		$	24.49
Granted		17,500		$	24.95
Vested		(2,434	)	$	25.90
Forfeited		(26,021	)	$	23.90
Nonvested at March 31, 2006		740,649		$	24.52

     The total fair value of restricted units that vested during the first quarter of 2006 was $0.1 million. During the first quarter of 2006, we recognized $0.7 million of compensation expense associated with nonvested units. As of March 31, 2006, we expect to incur $9.3 million of unrecognized compensation cost, related to nonvested units issued to EPCO employees that work on our behalf, over a weighted-average period of approximately 2 years.

9

Employee Partnership

     In connection with the initial public offering of Enterprise GP Holdings in August 2005, the Employee Partnership was formed to serve as an incentive arrangement for certain employees of EPCO through a “profits interest” in the Employee Partnership. At inception, the Employee Partnership used $51 million in contributions it received from an affiliate of EPCO (which was admitted as the Class A limited partner of the Employee Partnership) to purchase 1,821,428 units of Enterprise GP Holdings in August 2005. Certain EPCO employees, including all of EPE Holdings’ and Enterprise Products GP’s executive officers other than Dan L. Duncan, have been issued Class B limited partner interests without any capital contribution and admitted as Class B limited partners of the Employee Partnership.

     As described in its partnership agreement, the Employee Partnership will be liquidated the earlier of (i) August 2010 or (ii) a change in control of Enterprise GP Holdings or its general partner. Upon liquidation of the Employee Partnership, units having a fair market value equal to the Class A limited partner’s capital base will be distributed to the Class A limited partner, plus any Class A preferred return for the quarter in which liquidation occurs. Any remaining units will be distributed to the Class B limited partners as a residual profits interest in the Employee Partnership as an award.

     Prior to our adoption of SFAS 123(R), the estimated value of the profits interest was accounted for similar to a stock appreciation right. Upon our adoption of SFAS 123(R), we began recognizing compensation expense based upon the estimated grant date fair value of the Class B partnership equity awards.

     The fair value of the Class B partnership equity awards was estimated on the date of grant using the Black-Scholes option pricing model, which incorporates various assumptions. We used the following assumptions to estimate the fair value of these equity awards: (i) expected life of award of five years; (ii) risk-free interest rate of 4.1%; (iii) expected dividend yield on units of Enterprise GP Holdings of 3% and (iv) expected Enterprise GP Holdings unit price volatility of 30%. In general, the assumptions used in the Black-Scholes option pricing model to estimate the fair value of the Class B partnership equity awards are similar to those used to estimate the fair value of Enterprise Products Partners’ unit options.

     During the first quarter of 2006, we recognized $0.6 of compensation expense associated with profits interests. At March 31, 2006, there was $10.7 million of total unrecognized compensation cost related to profits interests, which is expected to be recognized on a straight-line basis through the third quarter of 2010.

4. 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.

10

     As summarized in the following table, we had eleven interest rate swap agreements outstanding at March 31, 2006 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 8.15%	$  50 million
Senior Notes C, 6.375% fixed rate, due Feb. 2013		2	Jan. 2004 to Feb. 2013	Feb. 2013	6.375% to 6.69%	$200 million
Senior Notes G, 5.6% fixed rate, due Oct. 2014		6	4th Qtr. 2004 to Oct. 2014	Oct. 2014	5.6% to 5.27%	$600 million
Senior Notes K, 4.95% fixed rate, due June 2010		2	Aug. 2005 to June 2010	June 2010	4.95% to 4.99%	$200 million

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

     The total fair value of these eleven interest rate swaps at March 31, 2006 and December 31, 2005, was a liability of $46.8 million and $19.2 million, respectively, with an offsetting decrease in the fair value of the underlying debt. Interest expense for the three months ended March 31, 2006 and 2005 reflects a $0.2 million and $4.6 million benefit from these swap agreements, respectively.

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, 2006 and December 31, 2005, we had a limited number of commodity financial instruments in our portfolio, which primarily consisted of economic hedges. The fair value of our commodity financial instrument portfolio at March 31, 2006 and December 31, 2005 was an asset of $1.1 million and a liability of $0.1 million, respectively. We recorded nominal amounts of earnings from our commodity financial instruments during the three months ended March 31, 2006 and 2005.

5. Inventories

     Our inventory amounts were as follows at the dates indicated:

	March 31,		December 31,
	2006		2005
Working inventory	$	237,783	$	279,237
Forward-sales inventory		17,632		60,369
Inventory	$	255,415	$	339,606

     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 and natural gas 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, include cost of sales related to inventories. For the three months ended March 31, 2006 and 2005, such consolidated cost of sales amounts were $2.7 billion and $2.1 billion, respectively.

     Due to fluctuating commodity prices in the NGL, natural gas and petrochemical industry, we 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

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expenses in the period they are recognized. For the three months ended March 31, 2006 and 2005, we recognized $11.6 million and $9.6 million, respectively, of such adjustments.

6. 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			2006		2005
Plants and pipelines (1)		5-35	(5)	$	8,361,372	$	8,209,580
Underground and other storage facilities (2)		5-35	(6)		563,174		549,923
Platforms and facilities (3)		23-31			161,807		161,807
Transportation equipment (4)		3-10			21,197		24,939
Land					38,550		38,757
Construction in progress					912,940		854,595
Total					10,059,040		9,839,601
Less accumulated depreciation					1,233,993		1,150,577
Property, plant and equipment, net				$	8,825,047	$	8,689,024

(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, 2006 and 2005 was $83.5 million and $78.9 million, respectively. Capitalized interest on our construction projects for the three months ended March 31, 2006 and 2005 was $9.2 million and $4.4 million, respectively.

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7. 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 12. 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,
	2006			2006		2005
NGL Pipelines & Services:
Venice Energy Services Company, LLC (“VESCO”)		13.1	%	$	36,195	$	39,689
K/D/S Promix LLC (“Promix”)		50	%		57,816		65,103
Baton Rouge Fractionators LLC (“BRF”)		32.3	%		25,696		25,584
Onshore Natural Gas Pipelines & Services:
Evangeline (1)		49.5	%		3,679		3,151
Coyote Gas Treating, LLC (“Coyote”)		50	%		1,191		1,493
Offshore Pipelines & Services:
Poseidon Oil Pipeline Company, L.L.C. (“Poseidon”)		36	%		62,537		62,918
Cameron Highway Oil Pipeline Company (“Cameron Highway”)		50	%		62,081		58,207
Deepwater Gateway, L.L.C. (“Deepwater Gateway”)		50	%		114,840		115,477
Neptune Pipeline Company, L.L.C. (“Neptune”)		25.67	%		67,549		68,085
Nemo Gathering Company, LLC (“Nemo”)		33.92	%		12,465		12,157
Petrochemical Services:
Baton Rouge Propylene Concentrator, LLC (“BRPC”)		30	%		14,588		15,212
La Porte (2)		50	%		4,895		4,845
Total				$	463,532	$	471,921

(1)	Refers to our ownership interests in Evangeline Gas Pipeline Company, L.P. and Evangeline Gas Corp., collectively.
(2)	Refers to our ownership interests in La Porte Pipeline Company, L.P. and La Porte GP, LLC, collectively.

     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, 2006, our investments in Promix, La Porte, Neptune, Poseidon, Cameron Highway and Nemo included excess cost. At March 31, 2006, excess cost amounts included in our investments in and advances to unconsolidated affiliates totaled $47.6 million, which was attributed to tangible assets. Amortization of our excess cost amounts attributed to tangible assets was $0.5 million and $0.7 million during the three months ended March 31, 2006 and 2005, 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,
	2006			2005
NGL Pipelines & Services	$	1,518		$	4,448
Onshore Natural Gas Pipelines & Services		602			580
Offshore Pipelines & Services		1,934			2,975
Petrochemical Services		(25	)		276
Total	$	4,029		$	8,279

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Summarized financial information of unconsolidated affiliates

     The following table presents unaudited income statement data for our current 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, 2006								March 31, 2005
			Operating			Net					Operating		Net
	Revenues		Income (Loss)			Income (Loss)			Revenues		Income		Income
NGL Pipelines & Services (1)	$	20,286	$	(22,125	)	$	(21,678	)	$	69,964	$	13,773	$	14,039
Onshore Natural Gas Pipelines & Services		82,342		2,342			1,192			53,354		2,147		1,072
Offshore Pipelines & Services		31,696		10,930			3,680			30,364		14,910		8,903
Petrochemical Services		3,868		186			210			4,095		1,129		1,141

(1) The decrease in earnings generated by the unconsolidated affiliates within our NGL Pipelines & Services segment is primarily attributable to losses incurred by VESCO due to the effects of Hurricane Katrina.

8. Business Combinations and Other Acquisitions

     In January 2006, we announced our intent to purchase (i) the Pioneer natural gas processing plant located in Opal, Wyoming and (ii) certain natural gas processing rights related to the Jonah and Pinedale fields in the Greater Green River Basin in Wyoming from TEPPCO. We completed this acquisition in March 2006 at a cost of $38.1 million.

     Our acquisition of the Pioneer natural gas processing plant and associated natural gas processing rights was accounted for under the purchase method of accounting and, accordingly, the cost has been allocated to the assets acquired based on estimated preliminary fair values as follows:

Property, plant and equipment, net	$	469
Intangible assets		37,631
Total assets acquired	$	38,100
Total consideration given	$	38,100

     Management independently developed the fair value estimates for our acquisition of the Pioneer natural gas processing plant and associated natural gas processing rights using recognized business valuation techniques. Upon completion of this acquisition, we commenced construction to increase capacity at the existing Pioneer natural gas processing plant, and we have started work on our announced Pioneer cryogenic natural gas processing facility. Upon completion of our Pioneer cryogenic natural gas processing facility, we will have the capacity to process expected volumes of natural gas from the Jonah and Pinedale fields under the rights that we purchased from an affiliate of TEPPCO. See Note 9 for information regarding the intangible assets recorded in connection with this acquisition.

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9. Intangible Assets and Goodwill

Identifiable Intangible assets

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

	At March 31, 2006							At December 31, 2005
	Gross		Accum.			Carrying		Accum.			Carrying
	Value		Amort.			Value		Amort.			Value
NGL Pipelines & Services (1)	$	392,894	$	(85,882	)	$	307,012	$	(79,485	)	$	275,778
Onshore Natural Gas Pipelines & Services		457,798		(52,413	)		405,385		(43,955	)		413,843
Offshore Pipelines & Services		207,012		(38,314	)		168,698		(32,480	)		174,532
Petrochemical Services		56,674		(7,700	)		48,974		(7,201	)		49,473
Total	$	1,114,378	$	(184,309	)	$	930,069	$	(163,121	)	$	913,626

(1) During the three months ended March 31, 2006, we recorded an additional $37.6 million of intangible assets due to our acquisition of the Pioneer natural gas processing plant and associated natural gas processing rights. The value we assigned to these processing rights will be amortized to earnings using methods that closely resemble the pattern in which the economic benefits of the underlying natural gas resource bases from which the customers produce are estimated to be consumed or otherwise used. Our estimate of the useful life of each resource base is based on a number of factors, including third-party reserve estimates, the economic viability of production and exploration activities and other industry factors.

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

	For the Three Months
	Ended March 31,
	2006		2005
NGL Pipelines & Services	$	6,361	$	6,427
Onshore Natural Gas Pipelines & Services		8,458		8,973
Offshore Pipelines & Services		5,834		6,722
Petrochemical Services		499		489
Total	$	21,152	$	22,611

          For the remainder of 2006, amortization expense associated with our intangible assets is currently estimated at $61.3 million.

Goodwill

          The following table summarizes our goodwill amounts by segment at March 31, 2006 and December 31, 2005. Of the $494 million of goodwill we have recorded, $387.1 million relates to goodwill we recorded in connection with the merger of GulfTerra Energy Partners, L.P. (“GulfTerra”) with a wholly owned subsidiary of ours in September 2004 (the “GulfTerra Merger”).

NGL Pipelines & Services	$	54,960
Onshore Natural Gas Pipelines & Services		282,997
Offshore Pipelines & Services		82,386
Petrochemical Services	73,690
Totals	$	494,033

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10. Debt Obligations

          Our consolidated debt consisted of the following at the dates indicated:

	March 31,			December 31,
	2006			2005
Operating Partnership debt obligations:
Multi-Year Revolving Credit Facility, variable rate, due October 2010	$	80,000		$	490,000
Pascagoula MBFC Loan, 8.70% fixed-rate, due March 2010		54,000			54,000
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			250,000
Senior Notes J, 5.75% fixed-rate, due March 2035		250,000			250,000
Senior Notes K, 4.950% fixed-rate, due June 2010		500,000			500,000
Dixie Revolving Credit Facility, variable rate, due June 2007		17,000			17,000
Debt obligations assumed from GulfTerra		5,068			5,068
Total principal amount		4,456,068			4,866,068
Other, including unamortized discounts and premiums and changes in fair value (1)		(59,753	)		(32,287	)
Long-term debt	$	4,396,315		$	4,833,781
Standby letters of credit outstanding	$	47,888		$	33,129

(1) The March 31, 2006 amount includes $45.8 million related to fair value hedges and $13.9 million in net unamortized discounts. The December 31, 2005 amount includes $18.2 million related to fair value hedges and $14.1 million in net unamortized discounts.

Parent-Subsidiary guarantor relationships

          At March 31, 2006, we act as guarantor of the debt obligations of our Operating Partnership, with the exception of the Dixie revolving credit facility and senior subordinated notes assumed from GulfTerra. If the Operating Partnership were to default on any debt we guarantee, we would be responsible for full repayment of that obligation.

Operating Partnership debt obligations

          There have been no significant changes in the terms of our Operating Partnership’s debt obligations since those reported in our annual report on Form 10-K for the year ended December 31, 2005.

          We generated net proceeds of $430 million in March 2006 in connection with the sale of 18,400,000 of our common units in an underwritten equity offering. Subsequently, this amount was contributed to the Operating Partnership, which, in turn, used this amount to temporarily reduce debt outstanding under its Multi-Year Revolving Credit Facility.

Covenants

          We were in compliance with the covenants of our consolidated debt agreements at March 31, 2006 and December 31, 2005.

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Information regarding variable interest rates paid

          The following table shows the range of interest rates paid and weighted-average interest rate paid on our consolidated variable-rate debt obligations during the first quarter of 2006.

	Range of	Weighted-average
	interest rates	interest rate
	paid	paid
Multi-Year Revolving Credit Facility	4.87% to 7.50%		5.08	%
Dixie Revolving Credit Facility	4.67% to 5.07%		4.84	%

Consolidated debt maturity table

          The following table presents scheduled maturities of debt principal amounts over the next five years and in total thereafter. No amounts are currently due in 2006 or 2008.

2007	$	517,000
2009		500,000
2010		639,068
Thereafter		2,800,000
Total scheduled principal payments	$	4,456,068

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, 2006, (ii) total debt of each unconsolidated affiliate at March 31, 2006 (on a 100% basis to the joint venture) and (iii) the corresponding scheduled maturities of such debt.

	Our					Scheduled Maturities of Debt
	Ownership															After
	Interest			Total		2006		2007		2008		2009		2010		2010
Cameron Highway		50.0	%	$	415,000					$	25,000	$	25,000	$	50,000	$	315,000
Poseidon		36.0	%		95,000						95,000
Evangeline		49.5	%		30,650	$	5,000	$	5,000		5,000		5,000		10,650
Total				$	540,650	$	5,000	$	5,000	$	125,000	$	30,000	$	60,650	$	315,000

          The credit agreements of our joint ventures contain various affirmative and negative covenants, including financial covenants. Our joint ventures were in compliance with all such covenants at March 31, 2006.

          Amendment of Cameron Highway debt. In March 2006, Cameron Highway amended the note purchase agreement governing its senior secured notes to primarily address the effect of reduced deliveries of crude oil to Cameron Highway resulting from production delays caused by the lingering effects of Hurricanes Katrina and Rita. In general, this amendment modified certain financial covenants in light of production forecasts. In addition, the amendment increased the letters of credit required to be issued by our Operating Partnership and an affiliate of our joint venture partner from $18.4 million each to $36.8 million each.

          Also, the amendment specifies that Cameron Highway cannot make distributions to its partners during the period beginning March 30, 2006 and ending on the earlier of (i) December 31, 2007 or (ii) the date on which Cameron Highway’s debt service coverage ratios are not less than 1.5 to 1 for three consecutive fiscal quarters. In order for Cameron Highway to resume paying distributions to its partners, no default or event of default can be present or continuing at the date Cameron Highway desires to start paying such distributions.

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11. Partners’ Equity

          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 Fifth Amended and Restated Agreement of Limited Partnership (together with all amendments thereto, the “Partnership Agreement”). We are managed by our general partner, Enterprise Products GP.

Capital accounts

          In accordance with our Partnership Agreement, capital accounts 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.

Equity offerings and registration statements

          In general, the Partnership Agreement 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 Products 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 during the first quarter of 2006:

			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 2006		418,190	$	9,972	$	203	$	10,175
March 2006		18,400,000		421,419		8,601		430,020
		18,818,190	$	431,391	$	8,804	$	440,195

          We have a universal shelf registration statement on file with the SEC registering the issuance of up to $4 billion of equity and debt securities. After taking into account the past issuance of securities under this universal registration statement, we can issue approximately $3 billion of additional securities under this registration statement as of March 31, 2006.

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Summary of limited partner transactions

          The following table details the changes in limited partners’ equity since December 31, 2005:

	Limited Partners
				Restricted
	Common			Common
	units			units			Total
Balance, December 31, 2005	$	5,542,700		$	18,638		$	5,561,338
Net income		112,156			213			112,369
Operating leases paid by EPCO		516			1			517
Cash distributions to partners		(170,235	)		(329	)		(170,564	)
Unit option reimbursements to EPCO		(376	)					(376	)
Net proceeds from sales of common units		431,391						431,391
Proceeds from exercise of unit options		718						718
Change in accounting method for equity awards (see Note 3)		(896	)		(14,918	)		(15,814	)
Amortization of equity awards		583			1,066			1,649
Balance, March 31, 2006	$	5,916,557		$	4,671		$	5,921,228

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
	Units		Units
Balance, December 31, 2005		389,109,564		751,604
Common units issued in February 2006		418,190
Common units issued in February 2006 in connection with unit options		29,000
Restricted common units issued in February 2006				17,500
Vesting of restricted units in February 2006		2,434		(2,434	)
Common units issued in connection with March 2006 offering		18,400,000
Forfeiture of restricted units in March 2006				(26,021	)
Balance, March 31, 2006		407,959,188		740,649

Distributions

          As an incentive, Enterprise Products GP’s percentage interest in our quarterly cash distributions is increased after certain specified target levels of quarterly distribution rates are met. Enterprise Products 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 17, 2006, we announced that our quarterly distribution rate with respect to the first quarter of 2006 would be $0.445 per common unit, or $1.78 on an annualized basis. This distribution will be paid on May 10, 2006, to unitholders of record at the close of business on April 28, 2006.

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Accumulated other comprehensive income

          The following table summarizes transactions affecting our accumulated other comprehensive income since December 31, 2005.

			Interest Rate Fin. Instrs.						Accumulated
						Forward-			Other
	Commodity					Starting			Comprehensive
	Financial		Treasury			Interest			Income
	Instruments		Locks			Rate Swaps			Balance
Balance, December 31, 2005			$	4,127		$	14,945		$	19,072
Change in fair value of commodity financial instruments	$	251								251
Reclassification of gain on settlement of interest rate financial instruments				(116	)		(925	)		(1,041	)
Balance, March 31, 2006	$	251	$	4,011		$	14,020		$	18,282

          During the remainder of 2006, we will reclassify a combined $3.2 million from accumulated other comprehensive income as a reduction in interest expense from our treasury locks and forward-starting interest rate swaps.

12. Business Segments

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

          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: (i) depreciation, amortization and accretion expense; (ii) operating lease expenses for which we do not have the payment obligation; (iii) gains and losses on the sale of assets; and (iv) 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 intersegment and intrasegment transactions.

          Segment revenues and operating costs 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.

          Historically, we have 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-

20

alone basis. Many of these businesses perform supporting or complementary roles to our other business operations.

          Our integrated midstream energy asset system (including the midstream energy assets of our equity method investees) provides services to producers and consumers of natural gas, NGLs and petrochemicals. Our asset system has multiple entry points. In general, hydrocarbons can enter our asset system through a number of ways, including an offshore natural gas or crude oil pipeline, an offshore platform, a natural gas processing plant, an NGL gathering pipeline, an NGL fractionator, an NGL storage facility, an NGL transportation or distribution pipeline or an onshore natural gas pipeline. At each link along this asset system, we earn revenues based on volume or an ownership of products such as NGLs.

          Many of our equity investees are present within our integrated midstream asset system. For example, we have ownership interests in several offshore natural gas and crude oil pipelines. Other examples include our use of the Promix NGL fractionator to process NGLs extracted by our gas plants. The NGLs received from Promix then can be sold in our NGL marketing activities. Given the integral nature of our equity investees to our operations, we believe treatment of earnings from our equity method investees as a component of gross operating margin and operating income is appropriate.

          Our consolidated revenues were earned in the United States and derived from a wide customer base. Currently, our plant-based operations are located primarily in Texas, Louisiana, Mississippi and New Mexico. Our natural gas, NGL and crude oil pipelines 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 and serve customers in a number of regions of the United States including the Gulf Coast, West Coast and Mid-Continent areas.

          Consolidated property, plant and equipment and investments in and advances to unconsolidated affiliates are allocated to each segment on the basis of each asset’s or investment’s principal operations. The principal reconciling item between consolidated property, plant and equipment and the total value of segment assets is construction-in-progress. Segment assets represent the net carrying value of facilities and projects that contribute to the gross operating margin of a particular segment. Since assets under construction generally do not contribute to segment gross operating margin, such assets are excluded from segment asset 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.

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

	For the Three Months
	Ended March 31,
	2006			2005
Revenues (1)	$	3,250,074		$	2,555,522
Less: Operating costs and expenses (1)		(3,046,863	)		(2,383,644	)
Add:  Equity in income of unconsolidated affiliates (1)		4,029			8,279
Depreciation, amortization and accretion in operating costs and expenses (2)		104,816			99,965
Operating lease expense paid by EPCO (2)		528			528
Gain on sale of assets in operating costs and expenses (2)		(61	)		(5,436	)
Total segment gross operating margin	$	312,523		$	275,214

(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.

          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 change in accounting principle follows:

	For the Three Months
	Ended March 31,
	2006			2005
Total segment gross operating margin	$	312,523		$	275,214
Adjustments to reconcile total segment gross operating margin to operating income:
Depreciation, amortization and accretion in operating costs and expenses		(104,816	)		(99,965	)
Operating lease expense paid by EPCO		(528	)		(528	)
Gain on sale of assets in operating costs and expenses		61			5,436
General and administrative costs		(13,740	)		(14,693	)
Consolidated operating income		193,500			165,464
Other expense		(56,108	)		(52,494	)
Income before provision for income taxes, minority interest and cumulative effect of change in accounting principle	$	137,392		$	112,970

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

	Operating Segments
	NGL		Onshore		Offshore					Adjustments
	Pipelines		Pipelines		Pipelines		Petrochemical			and			Consolidated
	& Services		& Services		& Services		Services			Eliminations			Totals
Revenues from third parties:
Three months ended March 31, 2006	$	2,338,696	$	413,001	$	22,352	$	385,950					$	3,159,999
Three months ended March 31, 2005		1,857,454		246,934		29,548		363,393						2,497,329
Revenues from related parties:
Three months ended March 31, 2006		6,948		82,955		172								90,075
Three months ended March 31, 2005		1,762		56,215		186		30						58,193
Intersegment and intrasegment revenues:
Three months ended March 31, 2006		896,245		28,141		313		82,817		$	(1,007,516	)		—
Three months ended March 31, 2005		729,677		10,017		196		54,750			(794,640	)		—
Total revenues:
Three months ended March 31, 2006		3,241,889		524,097		22,837		468,767			(1,007,516	)		3,250,074
Three months ended March 31, 2005		2,588,893		313,166		29,930		418,173			(794,640	)		2,555,522
Equity in income in unconsolidated affiliates:
Three months ended March 31, 2006		1,518		602		1,934		(25	)					4,029
Three months ended March 31, 2005		4,448		580		2,975		276						8,279
Gross operating margin by individual business segment and in total:
Three months ended March 31, 2006		170,950		96,803		17,252		27,518						312,523
Three months ended March 31, 2005		153,304		79,358		23,224		19,328						275,214
Segment assets:
At March 31, 2006		3,091,345		3,575,775		740,252		504,735			912,940			8,825,047
At December 31, 2005		3,075,048		3,622,318		632,222		504,841			854,595			8,689,024
Investments in and advances to unconsolidated affiliates (see Note 7):
At March 31, 2006		119,707		4,870		319,472		19,483						463,532
At December 31, 2005		130,376		4,644		316,844		20,057						471,921
Intangible Assets (see Note 9):
At March 31, 2006		307,012		405,385		168,698		48,974						930,069
At December 31, 2005		275,778		413,843		174,532		49,473						913,626
Goodwill (see Note 9):
At March 31, 2006		54,960		282,997		82,386		73,690						494,033
At December 31, 2005		54,960		282,997		82,386		73,690						494,033

          Revenues from the marketing of NGL products within the NGL Pipelines & Services business segment accounted for 67% of total consolidated revenues for the three months ended March 31, 2006 and 2005. Revenues from the marketing of petrochemical products within the Petrochemical Services segment accounted for 11% and 13% of total consolidated revenues for the three months ended March 31, 2006 and 2005, respectively. Revenues from the transportation, sale and storage of natural gas using onshore assets accounted for 15% and 12% of total consolidated revenues for the three months ended March 31, 2006 and 2005, respectively.

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13. Related Party Transactions

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

	For the Three Months
	Ended March 31,
	2006		2005
Revenues from consolidated operations
EPCO and affiliates	$	5,632	$	284
Unconsolidated affiliates		84,443		57,909
Total	$	90,075	$	58,193
Operating costs and expenses
EPCO and affiliates	$	94,957	$	59,003
Unconsolidated affiliates		6,686		6,568
Total	$	101,643	$	65,571
General and administrative expenses
EPCO and affiliates	$	11,008	$	9,675

Relationship with EPCO and affiliates

          General. We have an extensive and ongoing relationship with EPCO and its affiliates, which include the following significant entities:

§	EPCO and its private company subsidiaries;
§	Enterprise Products GP, our sole general partner;
§	Enterprise GP Holdings, which owns and controls our general partner;
§	the Employee Partnership; and
§	TEPPCO and its general partner (“TEPPCO GP”), which are controlled by affiliates of EPCO.

          Unless noted otherwise, our agreements with EPCO are not the result of arm’s length transactions. As a result, we cannot provide assurance that the terms and provisions of such agreements are at least as favorable to us as we could have obtained from unaffiliated third parties.

          EPCO is a private company controlled by Dan L. Duncan, who is also a director and Chairman of Enterprise Products GP, our general partner. At March 31, 2006, EPCO and its affiliates beneficially owned 144,313,193 (or 34.6%) of our outstanding common units. In addition, at March 31, 2006, EPCO and its affiliates owned 86.6% of Enterprise GP Holdings, including 100% of EPE Holdings.

          The principal business activity of Enterprise Products GP is to act as our managing partner. The executive officers and certain of the directors of Enterprise Products GP and Enterprise GP Holdings are employees of EPCO. Enterprise Products GP received $22.6 million and $16.6 million of cash distributions from us in connection with its general partner interest during the three months ended March 31, 2006 and 2005, respectively. The foregoing distributions for the three months ended March 31, 2006 and 2005, include $19.1 million and $13.6 million of incentive distributions, respectively.

          We and Enterprise Products GP are both separate legal entities apart from EPCO and its other affiliates, with assets and liabilities that are separate from those of EPCO and its other affiliates. EPCO depends on the cash distributions it receives from us, Enterprise GP Holdings and other investments to fund its other operations and to meet its debt obligations. EPCO and its affiliates received $73.1 million and $52.1 million in cash distributions from us during the three months ended March 31, 2006 and 2005, respectively, in connection with its limited and general partnership interests in us.

          The ownership interests in us that are owned or controlled by EPCO and its affiliates, other than Enterprise GP Holdings, Dan Duncan LLC and certain trusts affiliated with Dan L. Duncan, are pledged as security under the credit facility of an EPCO affiliate. EPCO’s credit facility contains customary and other

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events of default relating to EPCO and certain affiliates, including Enterprise GP Holdings, us and TEPPCO.

          We have entered into an agreement with an affiliate of EPCO to provide trucking services to us for the transportation of NGLs and other products. In addition, we have purchased from and sold certain NGL products to another affiliate of EPCO at market-related prices in the normal course of business. We also lease office space in various buildings from affiliates of EPCO related to our corporate headquarters in Houston, Texas. The rental rates in these lease agreements approximate market rates.

          Relationship with TEPPCO. We received $5.5 million from TEPPCO during the three months ended March 31, 2006 from the sale of hydrocarbon products. During the three months ended March 31, 2006 and 2005, we paid TEPPCO $4.4 million and $1.5 million, respectively, for NGL pipeline transportation and storage services.

          In January 2006, we announced our intent to purchase (i) the Pioneer natural gas processing plant located in Opal, Wyoming and (ii) certain natural gas processing rights related to the Jonah and Pinedale fields in the Greater Green River Basin in Wyoming from TEPPCO. We completed this acquisition in March 2006 at a cost of $38.1 million. This transaction was reviewed and approved by the Audit and Conflicts Committee of the board of directors of our general partner and the general partner of TEPPCO, and a fairness opinion was rendered by an independent third-party. TEPPCO will have no continued involvement in the contracts or in the operations of the Pioneer facility. In addition, the unaudited pro forma financial impact of this transaction is not significant.

          In February 2006, we and TEPPCO entered into a letter of intent related to the formation of a joint venture to expand TEPPCO’s Jonah Gas Gathering System (“the Jonah system”) located in the Green River Basin in southwestern Wyoming. The proposed expansion of the Jonah system would increase the natural gas gathering and transportation capacity of the Jonah system from 1.5 Bcf/d to 2.0 Bcf/d. The letter of intent stipulates that we will be responsible for all construction-related activities related to the expansion of the Jonah system, including advancing of all funds necessary to plan, engineer and construct the project. We estimate that total funds needed for this project will approximate $200 million and that the expansion assets will be placed in service in late 2006. The amounts we advance to complete the expansion of the Jonah system will constitute a subscription for an equity interest in the proposed joint venture. TEPPCO has the option to return to us up to 100% of the amounts we advance (i.e., the subscription amounts). If TEPPCO returns any portion of the subscription to us, the relative interests of us and TEPPCO in the new joint venture would be adjusted accordingly. The proposed joint venture arrangement will terminate without liability to either party if TEPPCO returns 100% of the advances we make in connection with the expansion project, including carrying costs and expenses. Our expenditures associated with this project were $55.3 million during the first quarter of 2006, of which $53.5 million has been paid. Other assets on our Unaudited Condensed Consolidated Balance Sheet at March 31, 2006 include the $55.3 million of expenditures related to this project.

          Administrative Services Agreement. We have no employees. All of our management, administrative and operating functions are performed by employees of EPCO pursuant to an administrative services agreement (“ASA”). We and our general partner, Enterprise GP Holdings and its general partner, and TEPPCO and its general partner are parties to the ASA. 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.

Relationships with unconsolidated affiliates

          Our significant related party transactions with unconsolidated affiliates consist of the sale of natural gas to Evangeline 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.

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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 (excluding restricted units) outstanding during a period. Diluted earnings per unit is computed by dividing net income or loss allocated to limited partner interests by the sum of (i) the weighted-average number of distribution-bearing units outstanding during a period (as used in determining basic earnings per unit); (ii) the weighted-average number of time-vested and performance-based restricted common units outstanding during a period; and (iii) the number of incremental common units resulting from the assumed exercise of dilutive unit options outstanding during a period (the “incremental option units”).

          In a period of net operating losses, the 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 end 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 or loss allocated to limited partner interests is net of our general partner’s share of such earnings. The following table shows the allocation of net income to our general partner for the periods indicated:

	For the Three Months
	Ended March 31,
	2006			2005
Net income	$	133,777		$	109,256
Less incentive earnings allocations to Enterprise Products GP		(19,115	)		(13,620	)
Net income available after incentive earnings allocation		114,662			95,636
Multiplied by Enterprise Products GP ownership interest		2.0	%		2.0	%
Standard earnings allocation to Enterprise Products GP	$	2,293		$	1,913
Incentive earnings allocation to Enterprise Products GP	$	19,115		$	13,620
Standard earnings allocation to Enterprise Products GP		2,293			1,913
Enterprise Products GP interest in net income	$	21,408		$	15,533

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          The following table presents our calculation of basic and diluted earnings per unit for the periods shown:

	For the Three Months
	Ended March 31,
	2006			2005
Income before change in accounting principle and Enterprise Products GP interest	$	132,302		$	109,256
Cumulative effect of change in accounting principle		1,475
Net income		133,777			109,256
Enterprise Products GP interest in net income		(21,408	)		(15,533	)
Net income available to limited partners	$	112,369		$	93,723
BASIC EARNINGS PER UNIT
Numerator
Income before change in accounting principle and Enterprise Products GP interest	$	132,302		$	109,256
Cumulative effect of change in accounting principle		1,475
Enterprise Products GP interest in net income		(21,408	)		(15,533	)
Limited partners’ interest in net income	$	112,369		$	93,723
Denominator
Common units		395,293			372,956
Basic earnings per unit
Income before change in accounting principle and Enterprise Products GP interest	$	0.33		$	0.29
Cumulative effect of change in accounting principle		*
Enterprise Products GP interest in net income		(0.05	)		(0.04	)
Limited partners’ interest in net income	$	0.28		$	0.25
DILUTED EARNINGS PER UNIT
Numerator
Income before change in accounting principle and Enterprise Products GP interest	$	132,302		$	109,256
Cumulative effect of change in accounting principle		1,475
Enterprise Products GP interest in net income		(21,408	)		(15,533	)
Limited partners’ interest in net income	$	112,369		$	93,723
Denominator
Common units		395,293			372,956
Time-vested restricted units		755			496
Performance-based restricted units		27			54
Incremental option units		248			700
Total		396,323			374,206
Diluted earnings per unit
Income before change in accounting principle and Enterprise Products GP interest	$	0.33		$	0.29
Cumulative effect of change in accounting principle		*
Enterprise Products GP interest in net income		(0.05	)		(0.04	)
Limited partners’ interest in net income	$	0.28		$	0.25

* Amount is negligible

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15. Commitments and Contingencies

Litigation

          On occasion, we are named as a defendant in litigation relating to our normal business activities, including regulatory and environmental matters. Although we insure against various business risks to the extent we believe 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 our ordinary business activities. We are not aware of any significant litigation, pending or threatened, that may have a significant adverse effect on our financial position, cash flows or results of operations.

          A number of lawsuits have been filed by municipalities and other water suppliers against various manufacturers of reformulated gasoline containing methyl tertiary butyl ether (“MTBE”). In general, such suits have not named manufacturers of MTBE as defendants, and there have been no such lawsuits filed against our subsidiary that owns an octane-additive production 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.

          We acquired the remaining ownership interests in our octane-additive production facility from affiliates of Devon Energy Corporation (“Devon,” which sold us its 33.3% interest in 2003) and Sunoco, Inc. (“Sun,” which sold us a 33.3% interest in 2004). Devon and Sun have indemnified us for any liability (including liabilities described above) that is in respect of periods prior to the date we purchased such interests. There are no dollar limits or deductibles associated with the indemnities we received from Sun and Devon with respect to potential claims linked to the period of time they held ownership interests in our octane-additive production facility.

Operating leases

          We lease certain property, plant and equipment under noncancelable and cancelable operating leases. Our significant lease agreements involve (i) the lease of underground caverns for the storage of natural gas and NGLs, (ii) leased office space with an affiliate of EPCO, and (iii) land held pursuant to right-of-way agreements. In general, our material lease agreements have original terms that range from 14 to 20 years and include renewal options that could extend the agreements for up to an additional 20 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. Lease and rental expense included in operating income was $9.7 million and $9.2 million for the three months ended March 31, 2006 and 2005, respectively.

          There have been no material changes in our operating lease commitments since December 31, 2005, except for the renewal of our Wilson natural gas storage facility lease. During the first quarter of 2006, we exercised our right to renew the Wilson lease for an additional 20-year period. Our rental payments under the renewal agreement are at a fixed rate. Under the renewal agreement, we have the option to purchase the Wilson natural gas storage facility at either December 31, 2024 for $61 million or January 25, 2028 for $55 million. In addition, the lessor, at its election, may cause us to purchase the facility for $65 million at the end of any calendar quarter beginning on March 31, 2008 and extending through December 31, 2023. After adjusting for the renewal, the incremental future minimum lease payments associated with our lease of the Wilson natural gas storage facility are as follows: $4.1 million, 2008; $5.5 million, 2009; $5.5 million, 2010; and $94.9 million thereafter.

Performance guaranty

          In December 2004, a subsidiary of the Operating Partnership entered into the Independence Hub Agreement (the “Agreement”) with six oil and natural gas producers. The Agreement, as amended, obligates the subsidiary (i) to construct an offshore platform production facility to process 1 Bcf/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.

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          In conjunction with the Agreement, our Operating Partnership guaranteed the performance of its subsidiary under the Agreement up to $426 million. In December 2004, 20% of this guaranteed amount was assumed by Helix Energy Solutions Group, Inc. (formerly known as Cal Dive International, Inc.), our joint venture partner in the Independence Hub project. The remaining $341 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 the cost of constructing the platform under the remote scenario where the six producers take over the construction of the platform facility. This performance guarantee continues until the earlier to occur of (i) all of the guaranteed obligations of the subsidiary shall have been terminated, paid or otherwise discharged in full, (ii) upon mutual written consent of our Operating Partnership and the producers or (iii) mechanical completion of the production facility. We currently expect that mechanical completion of the platform will occur in January 2007; therefore, we anticipate that the performance guaranty will exist until at least this future period.

          In accordance with FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others,” 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 this guaranty, we have estimated the fair value of the performance guaranty at approximately $1.2 million, which is a component of other current liabilities on our Unaudited Condensed Consolidated Balance Sheet at March 31, 2006.

16. Significant Risks and Uncertainties — Hurricanes

          The following is a discussion of the general status of insurance claims related to significant storm events that affected our assets in 2004 and 2005. To the extent we include any estimate regarding the dollar value of damages, please be aware that a change in our estimates may occur as additional information becomes available to us.

          Hurricane Ivan insurance claims. Our final purchase price allocation for the GulfTerra Merger included a $26.2 million receivable for insurance claims related to expenditures to repair property damage to certain GulfTerra assets caused by Hurricane Ivan, which struck the U.S. Gulf Coast in September 2004 prior to the GulfTerra Merger. During the first quarter of 2006, we received cash reimbursements from insurance carriers totaling $24.1 million related to these property damage claims, and we expect to recover the remaining $2.1 million by mid-2006. If the final recovery of funds is different than the amount previously expended, we will recognize an income impact at that time.

          In addition, we have submitted business interruption insurance claims for our estimated losses caused by Hurricane Ivan. During the first quarter of 2006, we received claim proceeds of $10.2 million, , and in April 2006 we received an additional $2 million. To the extent we receive cash proceeds from business interruption claims, they are recorded as a gain in our statements of consolidated operations and comprehensive income in the period of receipt.

          Hurricanes Katrina and Rita insurance claims. Hurricanes Katrina and Rita, both significant storms, affected certain of our Gulf Coast assets in August and September of 2005, respectively. Inspection and evaluation of property damage to our facilities is a continuing effort. To the extent that insurance proceeds from property damage claims do not cover our expenditures (in excess of the $5 million of insurance deductibles we expensed during the third quarter of 2005), such shortfall will be charged to earnings when realized. We have recorded $37.2 million of estimated recoveries from property damage claims based on amounts expended through March 31, 2006.

          In addition, we expect to file business interruption claims for losses related to these hurricanes. To the extent we receive cash proceeds from such business interruption claims, they will be recorded as a gain in our statements of consolidated operations and comprehensive income in the period of receipt.

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17. Supplemental Cash Flow Information

          We prepare our statements of consolidated cash flows using the indirect method. The indirect method derives net cash flows from operating activities by adjusting net income to remove (i) the effects of all deferrals of past operating cash receipts and payments, such as changes during the period in inventory, deferred income and the like, (ii) the effects of all accruals of expected future operating cash receipts and cash payments, such as changes during the period in receivables and payables, and (iii) the effects of all items classified as investing or financing cash flows, such as gains or losses on sale of assets or gains or losses from the extinguishment of debt.

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

	For the Three Months
	Ended March 31,
	2006			2005
Decrease (increase) in:
Accounts and notes receivable	$	355,049		$	150,833
Inventories		84,191			(120,178	)
Prepaid and other current assets		12,482			(16,572	)
Other assets		7,866			10,226
Increase (decrease) in:
Accounts payable		(85,314	)		(172,437	)
Accrued gas payable		(174,960	)		116,962
Accrued expenses		44,029			(19,438	)
Accrued interest		40			(3,618	)
Other current liabilities		2,615			1,159
Other long-term liabilities		1,086			(5,857	)
Net effect of changes in operating accounts	$	247,084		$	(58,920	)

          Third parties may be obligated to reimburse us for all or a portion of project expenditures on certain of our capital projects. The majority of such arrangements are associated with projects related to pipeline construction and production well tie-ins. We received $12.2 million and $8.9 million as contributions in aid of our construction costs during the three months ended March 31, 2006 and 2005, respectively.

18. Condensed Financial Information of Operating Partnership

          The Operating Partnership conducts substantially all of our business. Currently, we have no independent operations and no material assets outside those of our Operating Partnership.

          At March 31, 2006, we act as guarantor of the debt obligations of our Operating Partnership, with the exception of the Dixie revolving credit facility and senior subordinated notes assumed from GulfTerra. If the Operating Partnership were to default on any debt we guarantee, we would be responsible for full repayment of that obligation. For additional information regarding our consolidated debt obligations, see Note 10.

          The reconciling items between our consolidated financial statements and those of our Operating Partnership are insignificant.

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

	March 31,		December 31,
	2006		2005
ASSETS
Current assets	$	1,501,713	$	1,960,015
Property, plant and equipment, net		8,825,047		8,689,024
Investments in and advances to unconsolidated affiliates, net		463,532		471,921
Intangible assets, net		930,069		913,626
Goodwill		494,033		494,033
Deferred tax asset		4,821		3,606
Other assets		92,281		39,014
Total	$	12,311,496	$	12,571,239
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	$	1,648,242	$	1,894,227
Long-term debt		4,396,315		4,833,781
Other long-term liabilities		113,093		84,486
Minority interest		118,187		106,159
Partners’ equity		6,035,659		5,652,586
Total	$	12,311,496	$	12,571,239
Total Operating Partnership debt obligations guaranteed by us	$	4,434,000	$	4,844,000

          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,
	2006			2005
Revenues	$	3,250,074		$	2,555,522
Costs and expenses		3,058,646			2,397,646
Equity in income of unconsolidated affiliates		4,029			8,279
Operating income		195,457			166,155
Other income (expense)		(56,512	)		(52,475	)
Income before provision for income taxes, minority interest and change in accounting principle		138,945			113,680
Provision for income taxes		(2,892	)		(1,769	)
Income before minority interest and change in accounting principle		136,053			111,911
Minority interest		(2,199	)		(1,941	)
Income before change in accounting principle		133,854			109,970
Cumulative effect of change in accounting principle		1,475
Net income	$	135,329		$	109,970

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

For the three months ended March 31, 2006 and 2005.

          Enterprise Products Partners L.P. is a publicly traded Delaware limited partnership, the common units of which are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “EPD.” Unless the context requires otherwise, references to “we,” “us,” “our,” or “Enterprise Products Partners” are intended to mean the consolidated business and operations of Enterprise Products Partners L.P. and its subsidiaries.

          We are a North American midstream energy company that provides a wide range of services to producers and consumers of natural gas, natural gas liquids (“NGLs”), and crude oil. In addition, we are an industry leader in the development of pipeline and other midstream assets in the continental United States and Gulf of Mexico. 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 Products GP”). Enterprise Products GP is owned 100% by Enterprise GP Holdings L.P. (“Enterprise GP Holdings”), a publicly traded affiliate, the common units of which are listed on the NYSE under the ticker symbol “EPE.” We, Enterprise Products GP and Enterprise GP Holdings are affiliates and under common control of Dan L. Duncan, the Chairman and controlling shareholder of EPCO, Inc. (“EPCO”).

          This quarterly report contains various forward-looking statements and information based on our beliefs and those of Enterprise Products GP, our general partner, as well as assumptions made by us and information currently available to us. Please read the section titled “Cautionary Statement Regarding Forward-Looking Information” included within this Item 2.

          As generally used in the energy industry and in this document, the identified terms have the following meanings:

/ d	= per day
BBtus	= billion British thermal units
Bcf	= billion cubic feet
MBPD	= thousand barrels per day
Mdth	= thousand dekatherms
MMBbls	= million barrels
MMBtus	= million British thermal units
MMcf	= million cubic feet
Mcf	= thousand cubic feet
TBtu	= trillion British thermal units

          In addition, references to “TEPPCO” mean TEPPCO Partners, L.P., which is a related party affiliate to us. References to “TEPPCO GP” refer to the general partner of TEPPCO, which is wholly owned by a private company subsidiary of EPCO.

          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 and with our annual report on Form 10-K for the year ended December 31, 2005 (Commission File No. 1-14323).

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RECENT DEVELOPMENTS

          In general, our outlook for 2006 remains the same as that discussed in our annual report on Form 10-K for 2005. The following summarizes our significant developments during the first four months of 2006.

§	In March 2006, we sold 18,400,000 common units (including the over-allotment amount of 2,400,000 common units), which generated net proceeds of approximately $430 million.
§	In March 2006, we announced plans to expand our petrochemical assets located in southeast Texas at a cost of $205 million. In addition, we purchased the Pioneer natural gas processing plant and certain natural gas processing rights from TEPPCO for $38.1 million in March 2006.
§	In April 2006, we announced plans to expand our Houston Ship Channel NGL import and export facility and related pipeline and other assets to accommodate expected increases in volumes. This expansion project is expected to cost $40 million and be completed in the second quarter of 2007. For additional information regarding our growth capital spending, please read “Capital Spending” included within this Item 2.

CAPITAL SPENDING

          We are committed to the long-term growth and viability of Enterprise Products Partners. Part of our business strategy involves expansion through business combinations, growth capital projects and investments in joint ventures. Leveraging off of our existing assets, we have developed a significant portfolio of growth capital projects. Supported by long-term production dedications and fee-based contracts, we believe that we are positioned to continue to grow our system of assets through the construction of new facilities and to capitalize on expected future production increases from such areas as the Piceance Basin of western Colorado, the Greater Green River Basin in Wyoming, and the deepwater Gulf of Mexico.

          Management continues to analyze potential acquisitions, joint ventures and similar transactions with businesses that operate in complementary markets or geographic regions. 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.

          We estimate that our consolidated capital spending for the remainder of 2006 (i.e., the second, third and fourth quarters) will approximate $1.5 billion, which includes estimated expenditures of approximately $1.4 billion for growth capital projects and acquisitions and the remainder for sustaining capital expenditures.

          Our forecast of consolidated capital expenditures is based on our strategic operating and growth plans, which are dependent upon our ability to generate the required funds from either operating cash flows or from other means. Our capital expenditures forecast may change due to factors beyond our control, such as weather related issues, changes in supplier prices or adverse economic conditions. Furthermore, our forecast may change as a result of decisions made by management at a later date, which may include acquisitions or decisions to take on additional partners.

          Our success in raising capital, including the formation of joint ventures to share costs and risks, continues to be the principal factor that determines how much we can 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 in response to changes in capital markets.

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          The following table summarizes our capital spending by activity for the periods indicated (dollars in thousands):

	For the Three Months
	Ended March 31,
	2006		2005
Capital spending for business combinations and asset purchases:
Pioneer natural gas processing plant and associated processing rights purchased from TEPPCO	$	38,100
Indirect interests in the Indian Springs natural gas gathering and processing assets			$	74,855
Additional ownership interests in Dixie Pipeline Company (“Dixie”)				68,049
Other business combinations				7,574
Total		38,100		150,478
Capital spending for property, plant and equipment:
Growth capital projects		236,508		150,738
Sustaining capital projects		30,010		15,550
Total		266,518		166,288
Capital spending attributable to unconsolidated affiliates:
Investments in and advances to unconsolidated affiliates		402		88,634
Total capital spending	$	305,020	$	405,400

          Our capital spending for growth capital projects (as presented in the preceding table) are net of amounts we received from third parties as contributions in aid of our construction costs. Such contributions were $12.2 million and $8.9 million for the three months ended March 31, 2006 and 2005, respectively. On certain of our capital projects, third parties are obligated to reimburse us for all or a portion of project expenditures. The majority of such arrangements are associated with projects related to pipeline construction and production well tie-ins.

          At March 31, 2006, we had $245.4 million in outstanding purchase commitments, which primarily relate to growth capital projects in the Rocky Mountains and offshore Gulf of Mexico that are expected to be placed in service in 2006 and 2007.

Significant Recently Announced Growth Capital Projects

          The following summarizes our significant growth capital projects initiated during the first four months of 2006.

          Piceance Basin Gas Processing Project. In January 2006, we announced the execution of a minimum 15-year natural gas processing agreement with an affiliate of the EnCana Corporation (“EnCana”). Under that agreement, we will have the right to process up to 1.3 Bcf/d of EnCana’s natural gas production from the Piceance Basin area of western Colorado. To accommodate this production, we have begun construction of the Meeker natural gas processing facility in Rio Blanco County, Colorado. In addition, we will construct a 50-mile NGL pipeline that will connect our Meeker facility with our Mid-America Pipeline System. The Meeker natural gas processing plant, which will provide us with 750 MMcf/d of natural gas processing capacity and the ability to recover up to 35 MBPD of NGLs, is expected to be placed in service in mid-2007 at a cost of $285 million. We are currently working to secure production dedications from additional producers, which may lead to an expansion of the Meeker facility.

          Wyoming Gas Processing Projects. In January 2006, we announced our intent to purchase from an affiliate of TEPPCO the Pioneer natural gas processing plant located in Opal, Wyoming and the rights of TEPPCO and its affiliates to process natural gas originating from the Jonah and Pinedale fields in the Greater Green River Basin in Wyoming. We completed this acquisition in March 2006 at a cost of $38.1 million and commenced construction to increase the processing capacity of the Pioneer plant from 275 MMcf/d to 550 MMcf/d at an additional expected cost of $21 million. We expect this expansion to be competed in mid-2006. This transaction was reviewed and approved by the Audit and Conflicts Committee of the board of directors of our general partner and the general partner of TEPPCO, and a fairness opinion

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was rendered by an independent third-party. TEPPCO will have no continued involvement in the contracts or in the operations of the Pioneer facility.

          In addition, to handle future production growth in the region, we will construct a new natural gas processing plant with a capacity of 650 MMcf/d adjacent to the Pioneer plant. We expect our new natural gas processing plant to be placed in service by mid-2007 at an expected cost of $230 million.

          Jonah Expansion. In February 2006, we and TEPPCO, entered into a letter of intent related to the formation of a joint venture to expand TEPPCO’s Jonah Gas Gathering System (“the Jonah system”) located in the Green River Basin in southwestern Wyoming. The proposed expansion of the Jonah system would increase the natural gas gathering and transportation capacity of the Jonah system from 1.5 Bcf/d to 2.0 Bcf/d.

          The letter of intent stipulates that we will be responsible for all activities related to the construction of the expansion of the Jonah system, including the advance of all expenditures necessary to plan, engineer and construct the expansion project. We estimate that total funds needed for this project will approximate $200 million and that the expansion assets will be placed in service in late 2006.

          The amounts we advance to complete the expansion of the Jonah system will constitute a subscription for an equity interest in the proposed joint venture. TEPPCO has the option to return to us up to 100% of the amounts we advance (i.e., the subscription amounts). If TEPPCO returns any portion of the subscription to us, the relative interests of us and TEPPCO in the new joint venture would be adjusted accordingly. The proposed joint venture arrangement will terminate without liability to either party if TEPPCO returns 100% of the advances we make in connection with the expansion project, including carrying costs and expenses. Our expenditures associated with this project were $55.3 million during the first quarter of 2006, of which $53.5 million has been paid.

          Expansion of Mont Belvieu Petrochemical Assets. In March 2006, we announced an expansion of petrochemical assets in Mont Belvieu and southeast Texas. This expansion project includes (i) the construction of a new propylene fractionator at our Mont Belvieu complex, which will increase our propylene/propane fractionation capacity by approximately 15 MBPD and (ii) the expansion of two refinery grade propylene gathering pipelines which will add 50 MBPD of gathering capacity into Mont Belvieu. These projects are expected to be operational by late 2007 and are expected to cost $205 million.

          Expansion of Houston Ship Channel Import and Export Facility. In April 2006, we announced an expansion of our NGL import and export terminal located on the Houston Ship Channel. This expansion project will increase offloading capability of our import facility from a maximum peak operating rate of 240 MBPD to 480 MBPD and the maximum loading rate of our export facility from 140 MBPD to 160 MBPD. As part of this expansion project, we will increase the transportation and processing capacities of certain of our assets that serve the terminal in order to accommodate the expected increase in import volumes. This expansion project is expected to cost $40 million and be completed in the second quarter of 2007.

Pipeline Integrity Costs

          Our NGL, petrochemical and natural gas pipelines are subject to pipeline safety programs administered by the U.S. Department of Transportation, through its Office of Pipeline Safety. During the first quarter of 2006, we spent approximately $18.6 million to comply with these programs, of which $5.9 million was recorded as an operating expense and the remaining $12.7 million was capitalized. We spent approximately $5.4 million to comply with these programs during the first quarter of 2005, of which $4.3 million was recorded as an operating expense and the remaining $1.1 million was capitalized.

          We expect our net cash outlay for pipeline integrity program expenditures to approximate $50.9 million for the remainder 2006. Our forecast is net of certain costs we expect to recover from El Paso in connection with an indemnification agreement. We recovered $13.8 million from El Paso related to our 2005 expenditures in May 2006 and expect to recover $2.1 million related to our first quarter 2006

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expenditures, which leaves a remainder of $34.3 million reimbursable by El Paso for 2006 and 2007 pipeline integrity costs.

RESULTS OF OPERATIONS

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

          We evaluate segment performance based on the non-generally accepted accounting principle (“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 financial measure calculated using accounting principles generally accepted in the United States of America (“GAAP”) 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: (i) depreciation, amortization and accretion expense; (ii) operating lease expenses for which we do not have the payment obligation; (iii) gains and losses on the sale of assets; and (iv) 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 intersegment and intrasegment transactions.

          Historically, we have 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 12 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.

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Selected Price and Volumetric Data

     The following table presents selected average quarterly industry index prices for natural gas, crude oil and selected NGL and petrochemical products since the beginning of 2005:

															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)
2005
1st Quarter	$	6.27	$	49.68	$	0.52	$	0.79	$	0.98	$	1.00	$	1.14	$	0.45	$	0.39
2nd Quarter	$	6.74	$	53.09	$	0.52	$	0.82	$	0.98	$	1.01	$	1.16	$	0.37	$	0.30
3rd Quarter	$	8.53	$	63.08	$	0.69	$	0.97	$	1.14	$	1.26	$	1.36	$	0.37	$	0.33
4th Quarter	$	13.00	$	60.03	$	0.76	$	1.06	$	1.27	$	1.34	$	1.36	$	0.50	$	0.44
Average for Year	$	8.64	$	56.47	$	0.62	$	0.91	$	1.09	$	1.15	$	1.26	$	0.42	$	0.37
2006
1st Quarter	$	9.01	$	63.35	$	0.57	$	0.94	$	1.20	$	1.27	$	1.38	$	0.45	$	0.40

(1)

Natural gas, NGL, polymer grade propylene and refinery grade propylene prices represent an average of various commercial index prices including Oil Price Information Service (“OPIS”) and Chemical Market Associates, Inc. (“CMAI”). The 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 average throughput, production and processing volumetric data. These statistics are reported on a net basis, taking into account our ownership interests, and reflect the periods in which we owned an interest in such operations.

	For the Three Months
	Ended March 31,
	2006		2005
NGL Pipelines & Services, net:
NGL transportation volumes (MBPD)		1,421		1,410
NGL fractionation volumes (MBPD)		255		338
Equity NGL production (MBPD)(1)		58		85
Fee-based natural gas processing (MMcf/d)		1,807		2,018
Onshore Natural Gas Pipelines & Services, net:
Natural gas transportation volumes (BBtus/d)		6,052		5,746
Offshore Pipelines & Services, net:
Natural gas transportation volumes (BBtus/d)		1,476		1,851
Crude oil transportation volumes (MBPD)		113		126
Platform gas processing (Mcf/d)		157		316
Platform oil processing (MBPD)		7		8
Petrochemical Services, net:
Butane isomerization volumes (MBPD)		84		66
Propylene fractionation volumes (MBPD)		52		54
Octane additive production volumes (MBPD)		4
Petrochemical transportation volumes (MBPD)		63		74
Total, net:
NGL, crude oil and petrochemical transportation volumes (MBPD)		1,597		1,610
Natural gas transportation volumes (BBtus/d)		7,528		7,597
Equivalent transportation volumes (MBPD)(2)		3,578		3,609

(1)	Volumes for the first quarter of 2005 have been revised to incorporate refined asset-level definitions of equity NGL production volumes.
(2)	Reflects equivalent energy volumes where 3.8 MMBtus of natural gas are equivalent to one barrel of NGLs.

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Comparison of Results of Operations

          The following table summarizes the key components of our results of operations for the periods indicated (dollars in thousands):

	For the Three Months
	Ended March 31,
	2006		2005
Revenues	$	3,250,074	$	2,555,522
Operating costs and expenses		3,046,863		2,383,644
General and administrative costs		13,740		14,693
Equity in income of unconsolidated affiliates		4,029		8,279
Operating income		193,500		165,464
Interest expense		58,077		53,413
Net income		133,777		109,256

          Revenues from the marketing of NGL products within the NGL Pipelines & Services business segment accounted for 67% of total consolidated revenues for the three months ended March 31, 2006 and 2005. Revenues from the marketing of petrochemical products within the Petrochemical Services segment accounted for 11% and 13% of total consolidated revenues for the three months ended March 31, 2006 and 2005, respectively. Revenues from the transportation, sale and storage of natural gas using onshore assets accounted for 15% and 12% of total consolidated revenues for the three months ended March 31, 2006 and 2005, respectively.

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

	For the Three Months
	Ended March 31,
	2006		2005
Gross operating margin by segment:
NGL Pipelines & Services	$	170,950	$	153,304
Onshore Natural Gas Pipelines & Services		96,803		79,358
Offshore Pipelines & Services		17,252		23,224
Petrochemical Services		27,518		19,328
Total segment gross operating margin	$	312,523	$	275,214

          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 cumulative effect of change in accounting principle, please read “Other Items” included within this Item 2.

          Comparison of Three Months Ended March 31, 2006 with Three Months Ended March 31, 2005

          Revenues for the first quarter of 2006 increased $694.6 million over those recorded during the first quarter of 2005. The trend in consolidated revenues can be attributed to (i) a $489.2 million increase in revenues from our NGL and petrochemical marketing activities resulting from an increase in sales volumes and energy commodity prices in the first quarter of 2006 relative to the same period in 2005 and (ii) a $151.5 million increase in revenues from the sale of natural gas attributable to higher sales volumes and prices quarter-to-quarter.

          Consolidated operating costs and expenses increased $663.2 million quarter-to-quarter primarily due to higher energy commodity prices, which resulted in a $574.4 million increase in the cost of sales of natural gas, NGLs and petrochemical products. General and administrative costs decreased $1 million quarter-to-quarter.

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          Changes in our revenues and costs and expenses period-to-period are explained in part by changes in energy commodity prices. The weighted-average indicative market price for NGLs was 94 cents per gallon (“CPG”) during the first quarter of 2006 versus 80 CPG during the same period in 2005 – a quarter-to-quarter increase of 18%. Our determination of the weighted-average indicative market price for NGLs is based on U.S. Gulf Coast prices for such products at Mont Belvieu, which is the primary industry hub for domestic NGL production. The market price of natural gas (as measured at Henry Hub) averaged $9.01 per MMBtu during the first quarter of 2006 versus $6.27 per MMBtu during the 2005 period. For historical energy commodity pricing information, please see the table on page 37.

          Equity earnings from unconsolidated affiliates decreased $4.3 million quarter-to-quarter primarily due to (i) the consolidation of our investment in the Dixie Pipeline Company in February 2005, (ii) facility down-time and repair costs at our VESCO plant in the first quarter of 2006 caused by damage inflicted by Hurricane Katrina, and (iii) reduced earnings from Cameron Highway Oil Pipeline Company (“Cameron Highway”). Collectively, the aforementioned changes in revenues, costs and expenses and equity earnings contributed to a $28 million increase in operating income quarter-to-quarter.

          Interest expense increased $4.7 million quarter-to-quarter primarily due to an increase in interest rates and debt outstanding.

          As a result of items noted in the previous paragraphs, net income increased $24.5 million to $133.8 million for the first quarter of 2006 compared to $109.3 million for the first quarter of 2005. Net income for the first quarter of 2006 includes a non-cash benefit of $1.5 million related to the cumulative effect of a change in accounting principle resulting from our adoption of Statement of Financial Accounting Standards (“SFAS”) 123(R) on January 1, 2006.. For additional information regarding this cumulative effect adjustment, please read Note 3 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.

          All of our major onshore and offshore facilities affected by last year’s hurricanes have returned to service. We are at varying stages of the insurance claims process with respect to Hurricanes Katrina and Rita. Our results of operations for the first quarter of 2006 include $10.2 million from the settlement and collection of business interruption insurance claims from Hurricane Ivan, which struck the U.S. Gulf Coast in September 2004. We expect to receive additional insurance recoveries from claims related to Hurricanes Ivan, Katrina and Rita in 2006 and 2007. For additional information regarding our insurance claims related to these storm events, please read “Results of Operations – Significant Risks and Uncertainties – Hurricanes” included within this Item 2.

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

          NGL Pipelines & Services. Gross operating margin from this business segment was $170.9 million for the first quarter of 2006 compared to $153.3 million for the first quarter of 2005. The $17.6 million increase in gross operating margin is primarily due to improved results from our NGL pipelines and related services. Gross operating margin from our NGL pipelines and related services increased $18.4 million quarter-to-quarter due to a variety of reasons, including (i) a $10.1 million increase attributable to higher pipeline throughput, NGL storage and export volumes and (ii) the addition of $6.4 million of gross operating margin from acquired or consolidated assets, particularly that generated by Dixie NGL Pipeline.

          Gross operating margin from natural gas processing and related NGL marketing activities increased $1.3 million quarter-to-quarter. Gross operating margin from NGL fractionation decreased $2.1 million quarter-to-quarter primarily due to lower fractionation volumes and higher energy costs. Our Louisiana NGL fractionators, particularly Norco, suffered a reduction of processing volumes due to the effects of Hurricane Katrina. Our Norco NGL fractionator returned to normal operating rates in the second quarter of 2006.

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          Gross operating margin from this business segment for the first quarter of 2006 also includes $8.3 million of income resulting from business interruption insurance recoveries attributable to Hurricane Ivan. These recoveries relate to our South Louisiana assets that were affected by this storm in 2004.

          Onshore Natural Gas Pipelines & Services. Gross operating margin for this business segment was $96.8 million for the first quarter of 2006 versus $79.4 million for the first quarter of 2005. Onshore natural gas transportation volumes increased to 6.1 TBtu/d during the first quarter of 2006 from 5.7 TBtu/d during same quarter in 2005. The $17.4 million increase in gross operating margin quarter-to-quarter is primarily due to (i) a $9.2 million increase from our Texas Intrastate System, Permian Basin System and Petal natural gas storage facility attributable to an increase in volumes and (ii) a $6 million increase from our Acadian Gas System and San Juan Gathering System, both of which benefited from higher natural gas prices during the first quarter of 2006 relative to the first quarter of 2005. As a measure of operating activity of our San Juan Gathering System, we completed 109 production well tie-ins during the first quarter of 2006.

          Offshore Pipelines & Services. Gross operating margin from this business segment was $17.3 million for the first quarter of 2006 compared to $23.2 million for the first quarter of 2005. The $5.9 million decrease in gross operating margin quarter-to-quarter is primarily due to the effects of facility down-time and lower processing and transportation volumes caused by Hurricanes Katrina and Rita, the impacts of which were partially offset by $1.9 million of Hurricane Ivan business interruption insurance recoveries recorded in the first quarter of 2006. Also, gross operating margin from this business segment includes $1.2 million from our recently completed Constitution Oil and Natural Gas Pipelines, which were finished ahead of schedule and placed in service during the first quarter of 2006. Additionally, our Phoenix Gathering System returned to service in April 2006 and is expected to return to pre-hurricane transportation rates during the second quarter of 2006. This system was shut-in as a result of damage inflicted by Hurricane Rita on certain downstream pipelines owned by third parties.

          Petrochemical Services. Gross operating margin from this business segment was $27.5 million for the first quarter of 2006 versus $19.3 million for the first quarter of 2005. Gross operating margin from propylene fractionation increased $5.7 million quarter-to-quarter primarily due to higher petrochemical marketing sales margins. Gross operating margin from butane isomerization increased $4.6 million quarter-to-quarter largely due to increased demand for motor gasoline additives. Gross operating margin from octane enhancement decreased $2.1 million quarter-to-quarter as a result of facility downtime and costs resulting from a scheduled maintenance outage during the first quarter of 2006.

Significant Risks and Uncertainties – Hurricanes

          The following is a discussion of the general status of insurance claims related to significant storm events that affected our assets in 2004 and 2005. To the extent we include any estimate regarding the dollar value of damages, please be aware that a change in our estimates may occur as additional information becomes available to us.

          Hurricane Ivan insurance claims. Our final purchase price allocation related to the merger of GulfTerra Energy Partners, L.P. (“GulfTerra”) with a wholly owned subsidiary of Enterprise Products Partners in September 2004 (the “GulfTerra Merger”) included a $26.2 million receivable for insurance claims related to expenditures to repair property damage to certain GulfTerra assets caused by Hurricane Ivan, which struck the U.S. Gulf Coast prior to the GulfTerra Merger. During the first quarter of 2006, we received cash reimbursements from insurance carriers totaling $24.1 million related to these property damage claims, and we expect to recover the remaining $2.1 million by mid-2006. If the final recovery of funds is different than the amount previously expended, we will recognize an income impact at that time.

          In addition, we have submitted business interruption insurance claims for our estimated losses caused by Hurricane Ivan. During the first quarter of 2006, we received claim proceeds of $10.2 million, and in April 2006 we received an additional $2 million. We expect to receive additional receipts of approximately $5.5 million during the second quarter of 2006. To the extent we receive cash proceeds

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from business interruption claims, they are recorded as a gain in our statements of consolidated operations and comprehensive income in the period of receipt.

          Hurricanes Katrina and Rita insurance claims. Hurricanes Katrina and Rita, both significant storms, affected certain of our Gulf Coast assets in August and September of 2005, respectively. Inspection and evaluation of property damage to our facilities is a continuing effort. To the extent that insurance proceeds from property damage claims do not cover our expenditures (in excess of the $5 million of insurance deductibles we expensed during the third quarter of 2005), such shortfall will be charged to earnings when realized. We have recorded $37.2 million of estimated recoveries from property damage claims based on amounts expended through March 31, 2006.

          In addition, we expect to file business interruption claims for losses related to these hurricanes. To the extent we receive cash proceeds from such business interruption claims, they will be recorded as a gain in our statements of consolidated operations and comprehensive income in the period of receipt.

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 and short-term revolving credit arrangements. 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 and the issuance of additional equity and debt securities. 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.

          At March 31, 2006, we had $35 million of unrestricted cash on hand and approximately $1.1 billion of available credit under our Operating Partnership’s Multi-Year Revolving Credit Facility. In total, we had approximately $4.5 billion in principal outstanding under various consolidated debt obligations at March 31, 2006.

          As a result of our growth objectives, we expect to access debt and equity capital markets from time-to-time and we believe that financing arrangements to support our growth activities 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 “Capital Spending” included within this Item 2.

Credit Ratings

          At May 1, 2006, the credit ratings of our Operating Partnership’s debt securities were Baa3 with a stable outlook as rated by Moody’s Investor Services; BBB- with a stable outlook as rated by Fitch Ratings; and BB+ with a stable outlook as rated by Standard and Poor’s.

Registration Statements and Equity Offerings

          From time-to-time, we issue equity or debt securities to assist us in meeting our liquidity and capital spending requirements. We have a universal shelf registration statement on file with the U.S. Securities and Exchange Commission (“SEC”) registering the issuance of up to $4 billion of equity and debt securities. After taking into account the past issuance of securities under this universal registration statement, we can issue approximately $3 billion of additional securities under this registration statement as of May 1, 2006.

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          In March 2006, we sold 18,400,000 common units (including an over-allotment amount of 2,400,000 common units) to the public at an offering price of $23.90 per unit. Net proceeds from this offering, including Enterprise Products GP’s proportionate net capital contribution of $8.6 million, were approximately $430 million after deducting applicable underwriting discounts, commissions and estimated offering expenses of $18.3 million. The net proceeds from this offering, including Enterprise Products GP’s proportionate net capital contribution, were used to temporarily reduce indebtedness outstanding under our Operating Partnership’s Multi-Year Revolving Credit Facility.

Debt Obligations

          For detailed 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. The following table summarizes our consolidated debt obligations at the dates indicated (dollars in thousands):

	March 31,			December 31,
	2006			2005
Operating Partnership debt obligations:(1)
Multi-Year Revolving Credit Facility, variable rate, due October 2010(2)	$	80,000		$	490,000
Pascagoula MBFC Loan, 8.70% fixed-rate, due March 2010		54,000			54,000
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			250,000
Senior Notes J, 5.75% fixed-rate, due March 2035		250,000			250,000
Senior Notes K, 4.950% fixed-rate, due June 2010		500,000			500,000
Dixie Revolving Credit Facility, variable rate, due June 2007		17,000			17,000
Debt obligations assumed from GulfTerra		5,068			5,068
Total principal amount		4,456,068			4,866,068
Other, including unamortized discounts and premiums and changes in fair value(3)		(59,753	)		(32,287	)
Long-term debt	$	4,396,315		$	4,833,781
Standby letters of credit outstanding	$	47,888		$	33,129

(1)	There have been no significant changes in the terms of our Operating Partnership’s debt obligations since those reported in our annual report on Form 10-K for the year ended December 31, 2005.
(2)	We generated net proceeds of $430 million in March 2006 in connection with the sale of 18,400,000 of our common units in an underwritten equity offering. Subsequently, this amount was contributed to the Operating Partnership, which, in turn, used this amount to temporarily reduce debt outstanding under its Multi-Year Revolving Credit Facility.
(3)	The March 31, 2006 amount includes $45.8 million related to fair value hedges and $13.9 million in net unamortized discounts. The December 31, 2005 amount includes $18.2 million related to fair value hedges and $14.1 million in net unamortized discounts. For additional information regarding our fair value hedges, please read Item 3 of this quarterly report.

          The following table summarizes the debt obligations of our unconsolidated affiliates (on a 100% basis to the joint venture) at March 31, 2006 and our ownership interest in each entity on that date (dollars in thousands):

	Our
	Ownership
	Interest			Total
Cameron Highway		50.0	%	$	415,000
Poseidon Oil Pipeline Company, L.L.C. (“Poseidon”)		36.0	%		95,000
Evangeline Gas Pipeline Company, L.P.		49.5	%		30,650
Total				$	540,650

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          In March 2006, Cameron Highway amended the note purchase agreement governing its senior secured notes to primarily address the effect of reduced deliveries of crude oil to Cameron Highway resulting from production delays caused by the lingering effects of Hurricanes Katrina and Rita. In general, this amendment modified certain financial covenants in light of production forecasts. In addition, the amendment increased the letters of credit required to be issued by our Operating Partnership and an affiliate of our joint venture partner from $18.4 million each to $36.8 million each.

Cash Flows from Operating, Investing and Financing Activities

          The following table summarizes our cash flows from operating, investing and financing activities for the periods indicated (dollars in thousands). For information regarding the individual components of our cash flow amounts, please see the Unaudited Condensed Statements of Consolidated Cash Flows included under Item 1 of this quarterly report.

	For the Three Months
	Ended March 31,
	2006			2005
Net cash provided from operating activities	$	494,276		$	164,246
Net cash used in investing activities		348,645			349,193
Net cash provided by (used in) financing activities		(152,738	)		218,121

          The following information highlights the significant quarter-to-quarter variances in our cash flow amounts:

          Comparison of Three Months Ended March 31, 2006 with Three Months Ended March 31, 2005

          Operating activities. Net cash provided from operating activities was $494.3 million in the first quarter of 2006 compared to $164.2 million in the first quarter of 2005. The $330.1 million quarter-to-quarter increase in net cash provided from operating activities is primarily due to:

§

Net income adjusted for all non-cash items and the net effects of changes in operating accounts increased $343.6 million quarter-to-quarter primarily due to (i) reductions in the level of inventory and (ii) the timing of cash collections during the periods.

§

Distributions received from unconsolidated affiliates decreased by $13.6 million quarter-to-quarter primarily due to (i) a decrease in distributions from VESCO resulting from facility down-time and repair costs in the first quarter of 2006 caused by damage inflicted by Hurricane Katrina and (ii) our receipt of a special distribution from Deepwater Gateway, L.L.C. (“Deepwater Gateway”) in March 2005 in connection with the repayment of its term loan.

          Investing activities. Cash used in investing activities was $348.6 million in the first quarter of 2006 compared to $349.2 million in the first quarter of 2005. Expenditures for growth and sustaining capital projects (net of contributions in aid of construction costs) increased $100.2 million quarter-to-quarter primarily due to cash payments associated with our projects in the Rocky Mountains and Gulf of Mexico. In addition, during the first quarter of 2006 we spent $53.5 million in connection with our Jonah expansion project. Our cash outlays for asset purchases and business combinations were $38.1 million in the first quarter of 2006 versus $150.5 million in the first quarter of 2005. For additional information related to our capital spending program, please read “Capital Spending” included within this Item 2.

          Our investments in unconsolidated affiliates decreased from $80.6 million in the first quarter of 2005 to $8 million in the first quarter of 2006. In March 2005, we contributed $72 million to Deepwater Gateway to fund our share of the repayment of its term loan.

          Cash inflows related to investing activities for the first quarter of 2005 includes a $42.1 million cash receipt from the sale of our investment in Starfish Pipeline Company, LLC (“Starfish”). The sale of

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our Starfish investment was required by the Federal Trade Commission in order to gain its approval for the GulfTerra Merger.

          Financing activities. Cash used in financing activities was $152.7 million in the first quarter of 2006 compared to cash provided by operating activities of $218.1 million in the first quarter of 2005. We had net repayments under our debt agreements of $410 million during the first quarter of 2006 versus net repayments of $118.8 million during the first quarter of 2005. We used $430 million of net proceeds from our March 2006 equity offering to reduce debt outstanding under our Operating Partnership’s Multi-Year Revolving Credit Facility during the first quarter of 2006.

          In February 2005, our Operating Partnership issued an aggregate of $500 million in senior notes, the proceeds of which were used to repay $350 million due under its Senior Notes A and to temporarily reduce amounts outstanding under its other bank credit facilities. Also during the first quarter of 2005, the Operating Partnership repaid $242.2 million then outstanding under its 364-Day Acquisition Credit Facility (which was used to finance elements of the GulfTerra Merger) using proceeds generated from our February 2005 equity offering.

          Net proceeds from the issuance of limited partner interests were $440.9 million in the first quarter of 2006 compared to $501 million in the first quarter of 2005. We issued 18,818,190 common units during the first quarter of 2006 and 18,766,561 common units during the first quarter of 2005. Net proceeds from underwritten equity offerings were $430 million during the first quarter of 2006 reflecting the sale of 18,400,000 units and $456.7 million during the first quarter of 2005 reflecting the sale of 17,250,000 units. We used net proceeds from these underwritten offerings to reduce debt, including the temporary repayment of indebtedness under bank credit facilities. Our distribution reinvestment program and related plan generated net proceeds of $10.2 million in the first quarter of 2006 and $39 million in the first quarter of 2005. We used net proceeds from these offerings for general partnership purposes.

          Cash distributions to partners increased from $164.7 million in the first quarter of 2005 to $193.5 million in the first quarter of 2006 primarily due to an increase in our common units outstanding and our quarterly cash distribution rates. Cash contributions from minority interests were $11.4 million in the first quarter of 2006 compared to $6.3 million in the first quarter of 2005. These amounts represent contributions from our joint venture partner in the Independence Hub project.

CONTRACTUAL OBLIGATIONS

          Since December 31, 2005, scheduled maturities of long-term debt decreased $410 million primarily due to the application of net proceeds generated by our equity offering in March 2006 to temporarily reduce debt outstanding under our Operating Partnership’s Multi-Year Revolving Credit Facility. For additional information regarding our debt obligations, please read Note 10 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report. Also, we renewed our lease of the Wilson natural gas storage facility for an additional 20-year period during the first quarter of 2006. For additional information regarding our commitments under this significant lease, please read Note 15 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.

          Other than the two items noted in the previous paragraph, there have been no significant changes with regard to our material contractual obligations (outside of the ordinary course of business) since those reported in our annual report on Form 10-K for the year ended December 31, 2005.

OFF-BALANCE SHEET ARRANGEMENTS

          In March 2006, Cameron Highway amended the note purchase agreement governing its senior secured notes to primarily address the effect of reduced deliveries of crude oil to Cameron Highway resulting from production delays caused by the lingering effects of Hurricanes Katrina and Rita. In general, this amendment modified certain financial covenants in light of production forecasts. In addition, the

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amendment increased the letters of credit required to be issued by our Operating Partnership and an affiliate of our joint venture partner from $18.4 million each to $36.8 million each.

          In May 2006, Poseidon amended its revolving credit facility, which, among other things, decreased the availability to $150 million from $170 million and extended the maturity date from January 2008 to May 2011.

          Other than the amendments discussed above, there have been no significant changes with regard to our off-balance sheet arrangements since those reported in our annual report on Form 10-K for the year ended December 31, 2005.

RECENT ACCOUNTING DEVELOPMENTS

          During the first quarter of 2006, we adopted the provisions of Emerging Issues Task Force (“EITF”) 04-13, “Accounting for Purchases and Sale of Inventory With the Same Counterparty.” Our adoption of this guidance had no impact on our financial position, results of operations or cash flows. For additional information regarding EITF 04-13, please read Note 2 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.

CRITICAL ACCOUNTING POLICIES

          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, 2005. For a detailed discussion of these policies, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies” in our annual report on Form 10-K for 2005. 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 results in depreciation expense being incurred evenly over the life of the assets. Our estimate of depreciation incorporates assumptions regarding the useful economic lives and residual values of our 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, 2006 and December 31, 2005, the net book value of our property, plant and equipment was $8.8 billion and $8.7 billion, respectively. For additional information regarding our property, plant and equipment, please read Note 6 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 possible loss in value for the investment other than a 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

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estimates of such cash flows are based on a number of assumptions including anticipated margins and volumes; estimated useful life of asset or asset group; and salvage values. A significant change in these underlying assumptions could result in our recording an impairment charge.

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, 2006 and December 31, 2005, the carrying value of our intangible asset portfolio was $930.1 million and $913.6 million, respectively. For additional information regarding our intangible assets, please read Note 9 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

          Goodwill represents the excess of the purchase prices we paid for certain businesses over their respective fair values and is primarily comprised of $387.1 million associated with the GulfTerra Merger. We do not amortize goodwill; however, we test our goodwill (at the reporting unit level) for impairment during the second quarter of each fiscal year, and more frequently, if circumstances indicate it is more likely than not that the fair value of goodwill is below its carrying amount. Our goodwill testing involves the determination of a reporting unit’s fair value, which is predicated 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, 2006 and December 31, 2005, the carrying value of our goodwill was $494 million. For additional information regarding our goodwill, please read Note 9 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.

Our revenue recognition policies and use of estimates for revenues and expenses

          Our use of certain estimates for revenues and operating costs and other expenses has increased as a result of SEC regulations that require us to submit financial information on 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 to be substantially incorrect, it could result in material adjustments in results of operations between periods.

Reserves for environmental matters

          Each of our business segments is subject to federal, state and local laws and regulations governing environmental quality and pollution control. Such laws and regulations may, in certain instances, require us to remediate current or former operating sites where specified substances have been released or disposed of. 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. Future environmental developments, such as increasingly strict

46

environmental laws and additional claims for damages to property, employees and other persons resulting from current or past operations, could result in substantial additional costs beyond our current reserves.

     At March 31, 2006 and December 31, 2005, 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 5 “Accounting for Contingencies” and Financial Accounting Standards Board Interpretation (“FIN”) 14, “Reasonable Estimation of the Amount of a Loss,” we recorded our best estimate of these remediation activities.

Natural gas imbalances

     Natural gas imbalances result when customers physically deliver a larger or smaller quantity of natural gas into our pipelines than they take out. In general, we value such imbalances using a twelve-month moving average of natural gas prices, which we believe is reasonable given that the actual settlement dates for such imbalances are generally not known. As a result, significant changes in natural gas prices between reporting periods may impact our estimates.

     At March 31, 2006 and December 31, 2005, our imbalance receivables were $82 million and $89.4 million, respectively, and are reflected as a component of accounts receivable. At March 31, 2006 and December 31, 2005, our imbalance payables were $66.6 million and $80.5 million, respectively, and are reflected as a component of accrued gas payables.

SUMMARY OF RELATED PARTY TRANSACTIONS

     In accordance with SFAS 57, “Related Party Disclosures,” we have identified our material related party revenues and costs and expenses. The following table summarizes our related party transactions for the periods indicated (dollars in thousands).

	For the Three Months
	Ended March 31,
	2006		2005
Revenues from consolidated operations
EPCO and affiliates	$	5,632	$	284
Unconsolidated affiliates		84,443		57,909
Total	$	90,075	$	58,193
Operating costs and expenses
EPCO and affiliates	$	94,957	$	59,003
Unconsolidated affiliates		6,686		6,568
Total	$	101,643	$	65,571
General and administrative expenses
EPCO and affiliates	$	11,008	$	9,675

     For additional information regarding our related party transactions identified in accordance with GAAP, please read Note 13 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.

     We have an extensive and ongoing relationship with EPCO and its affiliates, including TEPPCO. Our revenues from EPCO and affiliates are primarily associated with sales of NGL products. Our expenses with EPCO are primarily due to (i) reimbursements we pay EPCO in connection with an administrative services agreement and (ii) purchases of NGL products. TEPPCO is an affiliate of ours due to the common control relationship of both entities.

     Many of our unconsolidated affiliates perform supporting or complementary roles to our consolidated business operations. The majority of our revenues from unconsolidated affiliates relate to natural gas sales to a Louisiana affiliate. The majority of our expenses with unconsolidated affiliates

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pertain to payments we make to K/D/S Promix, LLC for NGL transportation, storage and fractionation services.

     At March 31, 2006, other assets includes $55.3 million related to our Jonah expansion project with TEPPCO. For additional information, see Note 13 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.

OTHER ITEMS

Non-GAAP reconciliation

     The following table presents a reconciliation 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 change in accounting principle (dollars in thousands):

	For the Three Months
	Ended March 31,
	2006			2005
Total non-GAAP gross operating margin	$	312,523		$	275,214
Adjustments to reconcile total non-GAAP gross operating margin to GAAP operating income:
Depreciation, amortization and accretion in operating costs and expenses		(104,816	)		(99,965	)
Operating lease expense paid by EPCO		(528	)		(528	)
Gain on sale of assets in operating costs and expenses		61			5,436
General and administrative costs		(13,740	)		(14,693	)
GAAP consolidated operating income		193,500			165,464
Other expense		(56,108	)		(52,494	)
GAAP income before provision for income taxes, minority interest and cumulative effect of change in accounting principle	$	137,392		$	112,970

     EPCO subleases to us certain equipment located at our Mont Belvieu facility and 100 railcars for $1 per year (the “retained leases”). These subleases are part of an administrative services agreement between EPCO and us that was executed in connection with our formation in 1998. EPCO holds this equipment pursuant to operating leases for which it has retained the corresponding cash lease payment obligation. We record the full value of such lease payments made by EPCO as a non-cash related party operating expense, with the offset to partners’ equity recorded as a general contribution to our partnership. 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 of the retained leases to us.

Cumulative effect of change in accounting principle

     Net income for the first quarter of 2006 includes a non-cash benefit of $1.5 million related to the cumulative effect of a change in accounting principle resulting from our adoption of SFAS 123(R) on January 1, 2006. For additional information regarding this cumulative effect adjustment, please read Note 3 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.

Financial statement reclassifications

     Certain reclassifications have been made to the prior year’s financial statements to conform to the current year presentation. During the second quarter of 2005, we changed the classification of changes in restricted cash in our Unaudited Condensed Statements of Consolidated Cash Flows to present such changes as an investing activity. We previously presented such changes as an operating activity. In the accompanying Unaudited Condensed Statements of Consolidated Cash Flows for the three months ended March 31, 2005, we reclassified the change in restricted cash to be consistent with our current presentation. This reclassification resulted in a $15.8 million decrease to cash flows used in investing activities and a

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corresponding decrease to cash provided from operating activities from the amounts previously presented for the three months ended March 31, 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 Products 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 Products GP can give any assurance 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 see Part II, Item 1A, “Risk Factors,” included within this quarterly report on Form 10-Q.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

     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 eleven interest rate swap agreements outstanding at March 31, 2006 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 8.15%	$  50 million
Senior Notes C, 6.375% fixed rate, due Feb. 2013		2	Jan. 2004 to Feb. 2013	Feb. 2013	6.375% to 6.69%	$200 million
Senior Notes G, 5.6% fixed rate, due Oct. 2014		6	4th Qtr. 2004 to Oct. 2014	Oct. 2014	5.6% to 5.27%	$600 million
Senior Notes K, 4.95% fixed rate, due June 2010		2	Aug. 2005 to June 2010	June 2010	4.95% to 4.99%	$200 million

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

     The total fair value of these eleven interest rate swaps at March 31, 2006 and December 31, 2005, was a liability of $46.8 million and $19.2 million, respectively, with an offsetting decrease in the fair value of the underlying debt. Interest expense for the three months ended March 31, 2006 and 2005 reflects a $0.2 million and $4.6 million benefit from these swap agreements, respectively.

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     The following tables show the effect of hypothetical price movements on the estimated fair value (“FV”) of our interest rate swap portfolio and the related change in fair value of the underlying debt at the dates indicated (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 the six-month interest calculation period.

	Resulting	Swap Fair Value at
Scenario	Classification	March 31, 2006			April 27, 2006
FV assuming no change in underlying interest rates	Asset (Liability)	$	(46,798	)	$	(55,816	)
FV assuming 10% increase in underlying interest rates	Asset (Liability)		(79,617	)		(88,125	)
FV assuming 10% decrease in underlying interest rates	Asset (Liability)		(13,980	)		(23,507	)

     The change in fair value of our interest rate swaps since December 31, 2005 is primarily due to an increase in interest rates.

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, 2006 and December 31, 2005, we had a limited number of commodity financial instruments in our portfolio, which primarily consisted of economic hedges. The fair value of our commodity financial instrument portfolio at March 31, 2006 and December 31, 2005 was an asset of $1.1 million and a liability of $0.1 million, respectively. We recorded nominal amounts of earnings from our commodity financial instruments during the three months ended March 31, 2006 and 2005.

     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 dates indicated within the following table. The following table shows the effect of hypothetical price movements on the estimated fair value of this portfolio at the dates indicated (dollars in thousands):

	Resulting	Commodity Financial Instrument Portfolio FV
Scenario	Classification	March 31, 2006			April 27, 2006
FV assuming no change in underlying commodity prices	Asset (Liability)	$	1,079		$	(3,561	)
FV assuming 10% increase in underlying commodity prices	Asset (Liability)		(4,028	)		(3,987	)
FV assuming 10% decrease in underlying commodity prices	Asset (Liability)		6,186			(3,135	)

     The change in fair value of our commodity risk hedging portfolio from March 31, 2006 to April 27, 2006 is primarily due to an increase in natural gas prices.

50

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, 2005.

			Interest Rate Fin. Instrs.						Accumulated
						Forward-			Other
	Commodity					Starting			Comprehensive
	Financial		Treasury			Interest			Income
	Instruments		Locks			Rate Swaps			Balance
Balance, December 31, 2005			$	4,127		$	14,945		$	19,072
Change in fair value of commodity financial instruments	$	251								251
Reclassification of gain on settlement of interest rate financial instruments				(116	)		(925	)		(1,041	)
Balance, March 31, 2006	$	251	$	4,011		$	14,020		$	18,282

     During the remainder of 2006, we will reclassify a combined $3.2 million from accumulated other comprehensive income as a reduction in interest expense from our treasury locks and forward-starting interest rate swaps.

Item 4. Controls and Procedures.

     Our management, with the participation of the chief executive officer (“CEO”) and chief financial officer (“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.

     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.

     The certifications of our general partner’s CEO and CFO required under Sections 302 and 906 of the Sarbanes-Oxley Act of 2002 have been included as exhibits to this quarterly report on Form 10-Q.

51

PART II. OTHER INFORMATION.

Item 1. Legal Proceedings.

     See Part I, Item 1, Financial Statements, Note 15, “Litigation,” which is incorporated herein by reference.

Item 1A. Risk Factors.

     In general, there have been no significant changes in our risk factors since December 31, 2005. For a detailed discussion of our risk factors, please read, Item 1A “Risk Factors,” in our annual report on Form 10-K for 2005.

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, 2006. As of March 31, 2006, we and our affiliates are authorized to repurchase up to 618,400 common units under the December 1998 common unit repurchase program.

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
Number	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

52

Exhibit
Number	Exhibit*
	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 Registration Statement, Reg. No. 333-121665, 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	Fifth Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P., dated effective as of August 8, 2005 (incorporated by reference to Exhibit 3.1 to Form 8-K filed August 10, 2005).
3.2	Third Amended and Restated Limited Liability Company Agreement of Enterprise Products GP, LLC, dated as of August 29, 2005 (incorporated by reference to Exhibit 3.1 to Form 8-K filed September 1, 2005).
3.3	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 3.1 to Form 8-K filed July 1, 2005).
3.4	Certificate of Incorporation of Enterprise Products OLPGP, Inc., dated December 3, 2003 (incorporated by reference to Exhibit 3.5 to Form S-4 Registration Statement, Reg. No. 333-121665, filed December 27, 2004).
3.5	Bylaws of Enterprise Products OLPGP, Inc., dated December 8, 2003 (incorporated by reference to Exhibit 3.6 to Form S-4 Registration Statement, Reg. No. 333-121665, filed December 27, 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 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).

53

Exhibit
Number	Exhibit*
4.7	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).
4.8	Contribution Agreement dated September 17, 1999 (incorporated by reference to Exhibit “B” to Schedule 13D filed September 27, 1999 by Tejas Energy, LLC).
4.9	Registration Rights Agreement dated September 17, 1999 (incorporated by reference to Exhibit “E” to Schedule 13D filed September 27, 1999 by Tejas Energy, LLC).
4.10	Unitholder Rights Agreement dated September 17, 1999 (incorporated by reference to Exhibit “C” to Schedule 13D filed September 27, 1999 by Tejas Energy, LLC).
4.11	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).
4.12	Agreement dated as of March 4, 2005 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, 2005).
4.13	$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, and Mizuho Corporate Bank, Ltd., SunTrust Bank and The Bank of Nova Scotia, as Co-Documentation Agents (incorporated by reference to Exhibit 4.1 to Form 8-K filed on August 30, 2004).
4.14	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 4.13, above (incorporated by reference to Exhibit 4.2 to Form 8-K filed on August 30, 2004).
4.15	First Amendment dated October 5, 2005, to 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, and Mizuho Corporate Bank, Ltd., SunTrust Bank and The Bank of Nova Scotia, as Co-Documentation Agents (incorporated by reference to Exhibit 4.3 to Form 8-K filed on October 7, 2005).
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 4.16, 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

54

Exhibit
Number	Exhibit*
	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, 2005).
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, 2005).
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, 2005).
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, 2005).
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	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).
4.29	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).
4.30	Global Note representing $250,000,000 principal amount of 5.00% Series B Senior Notes due 2015 with attached Guarantee (incorporated by reference to Exhibit 4.31 to Form 10-Q filed on November 4, 2005).
4.31	Global Note representing $250,000,000 principal amount of 5.75% Series B Senior Notes due 2035 with attached Guarantee (incorporated by reference to Exhibit 4.32 to Form 10-Q filed on November 4, 2005).
4.32	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).
4.33	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 Products Partners 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).
4.34	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).
4.35	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).
4.36	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

55

Exhibit
Number	Exhibit*
	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).
4.37	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).
4.38	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).
4.39	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).
4.40	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).
4.41	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).
4.42	Amended and Restated Credit Agreement dated as of June 29, 2005, among Cameron Highway Oil Pipeline Company, the Lenders party thereto, and SunTrust Bank, as Administrative Agent and Collateral Agent (incorporated by reference to Exhibit 4.1 to Form 8-K filed on July 1, 2005).
4.43	Seventh Supplemental Indenture dated as of June 1, 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 4.46 to Form 10-Q filed November 4, 2005).
4.44	Global Note representing $500,000,000 principal amount of 4.95% Senior Notes due 2010 with attached Guarantee (incorporated by reference to Exhibit 4.47 to Form 10-Q filed November 4, 2005).
4.45	Note Purchase Agreement dated as of December 15, 2005 among Cameron Highway Oil Pipeline Company and the Note Purchasers listed therein (incorporated by reference to Exhibit 4.1 to Form 8-K filed December 21, 2005.)
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	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).
10.3***	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).
10.4***	Form of Option Grant Award under 1998 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.2 to Form S-8 Registration Statement, Reg. No. 333-115633, filed May 19, 2004).
10.5***	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).
10.6***	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

56

Exhibit
Number	Exhibit*
	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).
10.7	Third 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, Enterprise Products OLPGP, Inc., Enterprise GP Holdings L.P., EPE Holdings, LLC, TEPPCO Partners, L.P., Texas Eastern Products Pipeline Company, LLC, TE Products Pipeline Company, Limited Partnership, TEPPCO Midstream Companies, L.P., TCTM, L.P. and TEPPCO GP, Inc. dated August 15, 2005, but effective as of February 24, 2005 (incorporated by reference to Exhibit 10.1 to Form 8-K filed August 22, 2005).
10.8***	EPE Unit L.P. Agreement of Limited Partnership (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed by Enterprise GP Holdings L.P., Commission file no. 1-32610, on September 1, 2005).
10.9***	Enterprise Products Company 2005 EPE Long-Term Incentive Plan (incorporated by reference to Exhibit 10.28 to Amendment No. 3 to Form S-1 Registration Statement (Reg. No. 333-124320) filed by Enterprise GP Holdings L.P. on August 11, 2005).
10.10***	Form of Restricted Unit Grant under the Enterprise Products Company 2005 EPE Long-Term Incentive Plan (incorporated by reference to Exhibit 10.29 to Amendment No. 3 to Form S-1 Registration Statement (Reg. No. 333-124320) filed by Enterprise GP Holdings L.P. on August 11, 2005).
10.11***	Form of Phantom Unit Grant under the Enterprise Products Company 2005 EPE Long-Term Incentive Plan (incorporated by reference to Exhibit 10.30 to Amendment No. 3 to Form S-1 Registration Statement (Reg. No. 333-124320) filed by Enterprise GP Holdings L.P. on August 11, 2005).
10.12***	Enterprise Products Company 2005 EPE Long-Term Incentive Plan, amended and restated as of May 2, 2006 (incorporated by reference to Exhibit 10.01 to the Form 8-K filed by Enterprise GP Holdings L.P. on May 8, 2006).
10.13***	Form of Unit Appreciation Right Grant (EPE Holdings, LLC Directors) under the Enterprise Products Company 2005 EPE Long-Term Incentive Plan (incorporated by reference to Exhibit 10.02 to the Form 8-K filed by Enterprise GP Holdings L.P. on May 8, 2006).
10.14***	Form of Unit Appreciation Right Grant (Enterprise Products GP, LLC Directors) under the Enterprise Products Company 2005 EPE Long-Term Incentive Plan (incorporated by reference to Exhibit 10.03 to the Form 8-K filed by Enterprise GP Holdings L.P. on May 8, 2006).
10.15	Waiver of Provisions of the Conflicts Policies and Procedures of the Third Amended and Restated Administrative Services Agreement dated February 23, 2006 but effective as of February 13, 2006 (incorporated by reference to Exhibit 10.12 to Form 10-K filed on February 27, 2006).
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, 2006 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, 2006 quarterly report on Form 10-Q.
32.1#	Section 1350 certification of Robert G. Phillips for the March 31, 2006 quarterly report on Form 10-Q.
32.2#	Section 1350 certification of Michael A. Creel for the March 31, 2006 quarterly report on Form 10-Q.

*	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.

57

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 9, 2006.

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

58

Index to Exhibits

Exhibit
Number	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

Exhibit
Number	Exhibit*
	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 Registration Statement, Reg. No. 333-121665, 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	Fifth Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P., dated effective as of August 8, 2005 (incorporated by reference to Exhibit 3.1 to Form 8-K filed August 10, 2005).
3.2	Third Amended and Restated Limited Liability Company Agreement of Enterprise Products GP, LLC, dated as of August 29, 2005 (incorporated by reference to Exhibit 3.1 to Form 8-K filed September 1, 2005).
3.3	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 3.1 to Form 8-K filed July 1, 2005).
3.4	Certificate of Incorporation of Enterprise Products OLPGP, Inc., dated December 3, 2003 (incorporated by reference to Exhibit 3.5 to Form S-4 Registration Statement, Reg. No. 333-121665, filed December 27, 2004).
3.5	Bylaws of Enterprise Products OLPGP, Inc., dated December 8, 2003 (incorporated by reference to Exhibit 3.6 to Form S-4 Registration Statement, Reg. No. 333-121665, filed December 27, 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 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).

Exhibit
Number	Exhibit*
4.7	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).
4.8	Contribution Agreement dated September 17, 1999 (incorporated by reference to Exhibit “B” to Schedule 13D filed September 27, 1999 by Tejas Energy, LLC).
4.9	Registration Rights Agreement dated September 17, 1999 (incorporated by reference to Exhibit “E” to Schedule 13D filed September 27, 1999 by Tejas Energy, LLC).
4.10	Unitholder Rights Agreement dated September 17, 1999 (incorporated by reference to Exhibit “C” to Schedule 13D filed September 27, 1999 by Tejas Energy, LLC).
4.11	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).
4.12	Agreement dated as of March 4, 2005 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, 2005).
4.13	$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, and Mizuho Corporate Bank, Ltd., SunTrust Bank and The Bank of Nova Scotia, as Co-Documentation Agents (incorporated by reference to Exhibit 4.1 to Form 8-K filed on August 30, 2004).
4.14	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 4.13, above (incorporated by reference to Exhibit 4.2 to Form 8-K filed on August 30, 2004).
4.15	First Amendment dated October 5, 2005, to 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, and Mizuho Corporate Bank, Ltd., SunTrust Bank and The Bank of Nova Scotia, as Co-Documentation Agents (incorporated by reference to Exhibit 4.3 to Form 8-K filed on October 7, 2005).
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 4.16, 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

Exhibit
Number	Exhibit*
	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, 2005).
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, 2005).
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, 2005).
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, 2005).
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	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).
4.29	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).
4.30	Global Note representing $250,000,000 principal amount of 5.00% Series B Senior Notes due 2015 with attached Guarantee (incorporated by reference to Exhibit 4.31 to Form 10-Q filed on November 4, 2005).
4.31	Global Note representing $250,000,000 principal amount of 5.75% Series B Senior Notes due 2035 with attached Guarantee (incorporated by reference to Exhibit 4.32 to Form 10-Q filed on November 4, 2005).
4.32	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).
4.33	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 Products Partners 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).
4.34	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).
4.35	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).
4.36	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

Exhibit
Number	Exhibit*
	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).
4.37	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).
4.38	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).
4.39	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).
4.40	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).
4.41	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).
4.42	Amended and Restated Credit Agreement dated as of June 29, 2005, among Cameron Highway Oil Pipeline Company, the Lenders party thereto, and SunTrust Bank, as Administrative Agent and Collateral Agent (incorporated by reference to Exhibit 4.1 to Form 8-K filed on July 1, 2005).
4.43	Seventh Supplemental Indenture dated as of June 1, 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 4.46 to Form 10-Q filed November 4, 2005).
4.44	Global Note representing $500,000,000 principal amount of 4.95% Senior Notes due 2010 with attached Guarantee (incorporated by reference to Exhibit 4.47 to Form 10-Q filed November 4, 2005).
4.45	Note Purchase Agreement dated as of December 15, 2005 among Cameron Highway Oil Pipeline Company and the Note Purchasers listed therein (incorporated by reference to Exhibit 4.1 to Form 8-K filed December 21, 2005.)
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	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).
10.3***	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).
10.4***	Form of Option Grant Award under 1998 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.2 to Form S-8 Registration Statement, Reg. No. 333-115633, filed May 19, 2004).
10.5***	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).
10.6***	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

Exhibit
Number	Exhibit*
	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).
10.7	Third 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, Enterprise Products OLPGP, Inc., Enterprise GP Holdings L.P., EPE Holdings, LLC, TEPPCO Partners, L.P., Texas Eastern Products Pipeline Company, LLC, TE Products Pipeline Company, Limited Partnership, TEPPCO Midstream Companies, L.P., TCTM, L.P. and TEPPCO GP, Inc. dated August 15, 2005, but effective as of February 24, 2005 (incorporated by reference to Exhibit 10.1 to Form 8-K filed August 22, 2005).
10.8***	EPE Unit L.P. Agreement of Limited Partnership (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed by Enterprise GP Holdings L.P., Commission file no. 1-32610, on September 1, 2005).
10.9***	Enterprise Products Company 2005 EPE Long-Term Incentive Plan (incorporated by reference to Exhibit 10.28 to Amendment No. 3 to Form S-1 Registration Statement (Reg. No. 333-124320) filed by Enterprise GP Holdings L.P. on August 11, 2005).
10.10***	Form of Restricted Unit Grant under the Enterprise Products Company 2005 EPE Long-Term Incentive Plan (incorporated by reference to Exhibit 10.29 to Amendment No. 3 to Form S-1 Registration Statement (Reg. No. 333-124320) filed by Enterprise GP Holdings L.P. on August 11, 2005).
10.11***	Form of Phantom Unit Grant under the Enterprise Products Company 2005 EPE Long-Term Incentive Plan (incorporated by reference to Exhibit 10.30 to Amendment No. 3 to Form S-1 Registration Statement (Reg. No. 333-124320) filed by Enterprise GP Holdings L.P. on August 11, 2005).
10.12***	Enterprise Products Company 2005 EPE Long-Term Incentive Plan, amended and restated as of May 2, 2006 (incorporated by reference to Exhibit 10.01 to the Form 8-K filed by Enterprise GP Holdings L.P. on May 8, 2006).
10.13***	Form of Unit Appreciation Right Grant (EPE Holdings, LLC Directors) under the Enterprise Products Company 2005 EPE Long-Term Incentive Plan (incorporated by reference to Exhibit 10.02 to the Form 8-K filed by Enterprise GP Holdings L.P. on May 8, 2006).
10.14***	Form of Unit Appreciation Right Grant (Enterprise Products GP, LLC Directors) under the Enterprise Products Company 2005 EPE Long-Term Incentive Plan (incorporated by reference to Exhibit 10.03 to the Form 8-K filed by Enterprise GP Holdings L.P. on May 8, 2006).
10.15	Waiver of Provisions of the Conflicts Policies and Procedures of the Third Amended and Restated Administrative Services Agreement dated February 23, 2006 but effective as of February 13, 2006 (incorporated by reference to Exhibit 10.12 to Form 10-K filed on February 27, 2006).
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, 2006 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, 2006 quarterly report on Form 10-Q.
32.1#	Section 1350 certification of Robert G. Phillips for the March 31, 2006 quarterly report on Form 10-Q.
32.2#	Section 1350 certification of Michael A. Creel for the March 31, 2006 quarterly report on Form 10-Q.

*	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.