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

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

For the transition period from ___ to ___.

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

PART I. FINANCIAL INFORMATION.

Item 1. Financial Statements.

ENTERPRISE PRODUCTS PARTNERS L.P.

		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

ENTERPRISE PRODUCTS PARTNERS L.P.

		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

ENTERPRISE PRODUCTS PARTNERS L.P.

		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

ENTERPRISE PRODUCTS PARTNERS L.P.

														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

ENTERPRISE PRODUCTS PARTNERS L.P.

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).

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.

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

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

     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.

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.

     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

     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

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

     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.

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

     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

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

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.

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

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.

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.

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.

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.

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-

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.

          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

          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.

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

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.

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”).