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, 2007

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

1100 Louisiana, 10th Floor
Houston, Texas 77002
(Address of Principal Executive Offices, Including Zip Code)

(713) 381-6500
(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 432,998,201 common units of Enterprise Products Partners L.P. outstanding at May 4, 2007. 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		3
		Unaudited Condensed Statements of Consolidated Comprehensive Income		4
		Unaudited Condensed Statements of Consolidated Cash Flows		5
		Unaudited Condensed Statements of Consolidated Partners’ Equity		6
		Notes to Unaudited Condensed Consolidated Financial Statements:
		1. Partnership Organization		7
		2. General Accounting Policies and Related Matters		8
		3. Accounting for Equity Awards		10
		4. Financial Instruments		12
		5. Inventories		13
		6. Property, Plant and Equipment		14
		7. Investments in and Advances to Unconsolidated Affiliates		15
		8. Intangible Assets and Goodwill		16
		9. Debt Obligations		17
		10. Partners’ Equity and Distributions		20
		11. Business Segments		22
		12. Related Party Transactions		25
		13. Earnings Per Unit		29
		14. Commitments and Contingencies		31
		15. Significant Risks and Uncertainties – Weather-Related Risks		33
		16. Supplemental Cash Flow Information		34
		17. Condensed Financial Information of Operating Partnership		35
Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations.		36
Item 3.		Quantitative and Qualitative Disclosures about Market Risk.		56
Item 4.		Controls and Procedures.		58
		PART II. OTHER INFORMATION.
Item 1.		Legal Proceedings.		58
Item 1A.		Risk Factors.		58
Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds.		58
Item 3.		Defaults upon Senior Securities.		59
Item 4.		Submission of Matters to a Vote of Security Holders.		59
Item 5.		Other Information.		59
Item 6.		Exhibits.		59
Signatures				65
Certification Pursuant to Section 302
Certification Pursuant to Section 302
Certification Pursuant to Section 1350
Certification Pursuant to Section 1350

PART I. FINANCIAL INFORMATION.

Item 1. Financial Statements.

ENTERPRISE PRODUCTS PARTNERS L.P.

		March 31,				December 31,
		2007				2006
ASSETS
Current assets:
Cash and cash equivalents		$	58,237			$	22,619
Restricted cash			18,990				23,667
Accounts and notes receivable — trade, net of allowance for doubtful accounts of $22,489 at March 31, 2007 and $23,406 at December 31, 2006			1,267,196				1,306,290
Accounts receivable — related parties			32,481				16,738
Inventories			460,915				423,844
Prepaid and other current assets			135,266				129,000
Total current assets			1,973,085				1,922,158
Property, plant and equipment, net			10,210,898				9,832,547
Investments in and advances to unconsolidated affiliates			598,638				564,559
Intangible assets, net of accumulated amortization of $274,855 at March 31, 2007 and $251,876 at December 31, 2006			980,976				1,003,955
Goodwill			590,639				590,541
Deferred tax asset			2,544				1,855
Other assets			71,208				74,103
Total assets		$	14,427,988			$	13,989,718
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable – trade		$	206,390			$	277,070
Accounts payable – related parties			21,044				6,785
Accrued gas payables			1,528,007				1,364,493
Accrued expenses			37,190				35,763
Accrued interest			80,051				90,865
Other current liabilities			177,329				209,945
Total current liabilities			2,050,011				1,984,921
Long-term debt: (See Note 9)
Senior debt obligations – principal			4,928,068				4,779,068
Junior Subordinated Notes A – principal			550,000				550,000
Other			(29,383	)			(33,478	)
Total long-term debt			5,448,685				5,295,590
Deferred tax liabilities			16,028				13,723
Other long-term liabilities			86,199				86,121
Minority interest			433,575				129,130
Commitments and contingencie
Partners’ equity:
Limited partners
Common units (431,879,824 units outstanding at March 31, 2007 and 431,303,193 units outstanding at December 31, 2006)			6,219,937				6,320,577
Restricted common units (1,118,377 units outstanding at March 31, 2007 and 1,105,237 units outstanding at December 31, 2006)			10,688				9,340
General partner			127,149				129,175
Accumulated other comprehensive income			35,716				21,141
Total partners’ equity			6,393,490				6,480,233
Total liabilities and partners’ equity		$	14,427,988			$	13,989,718

See Notes to Unaudited Condensed Consolidated Financial Statements.

ENTERPRISE PRODUCTS PARTNERS L.P.

		For the Three Months
		Ended March 31,
		2007				2006
Revenues:
Third parties		$	3,258,612			$	3,159,999
Related parties			64,242				90,075
Total			3,322,854				3,250,074
Costs and expenses:
Operating costs and expenses:
Third parties			3,040,533				2,945,220
Related parties			83,946				101,643
Total operating costs and expenses			3,124,479				3,046,863
General and administrative costs:
Third parties			3,575				2,732
Related parties			13,055				11,008
Total general and administrative costs			16,630				13,740
Total costs and expenses			3,141,109				3,060,603
Equity in income of unconsolidated affiliates			6,179				4,029
Operating income			187,924				193,500
Other income (expense):
Interest expense			(63,358	)			(58,077	)
Interest income			2,035				1,661
Other, net			(107	)			308
Other expense			(61,430	)			(56,108	)
Income before provision for income taxes, minority interest and the cumulative effect of change in accounting principle			126,494				137,392
Provision for income taxes			(8,788	)			(2,892	)
Income before minority interest and the cumulative effect of change in accounting principle			117,706				134,500
Minority interest			(5,661	)			(2,198	)
Income before the cumulative effect of change in accounting principle			112,045				132,302
Cumulative effect of change in accounting principle (see Note 2)			—				1,475
Net income		$	112,045			$	133,777
Net income allocation: (see Note 13)
Limited partners’ interest in net income		$	85,049			$	112,369
General partner interest in net income		$	26,996			$	21,408
Earning per unit: (see Note 13)
Basic and diluted income per unit before change in accounting principle		$	0.20			$	0.28
Basic and diluted income per unit		$	0.20			$	0.28

See Notes to Unaudited Condensed Consolidated Financial Statements.

ENTERPRISE PRODUCTS PARTNERS L.P.

		For the Three Months
		Ended March 31,
		2007				2006
Net income		$	112,045			$	133,777
Other comprehensive income:
Cash flow hedges:
Net commodity financial instrument gains during period			14,479				251
Less: Amortization of cash flow financing hedges			(1,089	)			(1,041	)
Total cash flow hedges			13,390				(790	)
Foreign currency translation adjustment			401				—
Total other comprehensive income			13,791				(790	)
Comprehensive income		$	125,836			$	132,987

See Notes to Unaudited Condensed Consolidated Financial Statements.

ENTERPRISE PRODUCTS PARTNERS L.P.

		For the Three Months
		Ended March 31,
		2007				2006
Operating activities:
Net income		$	112,045			$	133,777
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion in operating costs and expenses			119,492				104,816
Depreciation and amortization in general and administrative costs			1,597				1,501
Amortization in interest expense			132				250
Equity in income of unconsolidated affiliates			(6,179	)			(4,029	)
Distributions received from unconsolidated affiliates			16,947				8,253
Cumulative effect of change in accounting principle			—				(1,475	)
Operating lease expense paid by EPCO, Inc.			526				528
Minority interest			5,661				2,198
Gain on sale of assets			(73	)			(61	)
Deferred income tax expense			1,596				1,487
Changes in fair market value of financial instruments			104				(53	)
Net effect of changes in operating accounts (see Note 16)			168,903				247,084
Net cash flows provided by operating activities			420,751				494,276
Investing activities:
Capital expenditures			(614,035	)			(316,798	)
Contributions in aid of construction costs			39,145				12,180
Proceeds from sale of assets			91				75
Decrease in restricted cash			4,677				9,045
Cash used for business combinations			(312	)			—
Investments in unconsolidated affiliates			(38,973	)			(61,528	)
Advances (to) from unconsolidated affiliates			(5,514	)			8,381
Net cash used in investing activities			(614,921	)			(348,645	)
Financing activities:
Borrowings under debt agreements			1,088,000				510,000
Repayments of debt			(939,000	)			(920,000	)
Debt issuance costs			(510	)			—
Distributions paid to partners			(233,145	)			(193,543	)
Distributions paid to minority interests			(1,053	)			(1,495	)
Net proceeds from initial public offering of Duncan Energy Partners reflected as a contribution from minority interests (see Notes 1 and 2)			291,872				—
Other contributions from minority interests			7,965				11,372
Net proceeds from issuance of our common units			16,997				440,928
Net cash provided by (used in) financing activities			231,126				(152,738	)
Effect of exchange rate changes on cash			(1,338	)			—
Net change in cash and cash equivalents			36,956				(7,107	)
Cash and cash equivalents, January 1			22,619				42,098
Cash and cash equivalents, March 31		$	58,237			$	34,991

See Notes to Unaudited Condensed Consolidated Financial Statements.

ENTERPRISE PRODUCTS PARTNERS L.P.

		Limited				General
		Partners				Partner				AOCI				Total
Balance, December 31, 2006		$	6,329,917			$	129,175			$	21,141			$	6,480,233
Net income			85,049				26,996				—				112,045
Operating leases paid by EPCO, Inc.			515				11				—				526
Cash distributions to partners			(202,149	)			(29,387	)			—				(231,536	)
Net proceeds from sales of common units			12,495				255				—				12,750
Proceeds from exercise of unit options			4,162				85				—				4,247
Unit option reimbursements to EPCO, Inc.			(1,577	)			(32	)			—				(1,609	)
Change in funded status of pension and postretirement plans, net of tax			—				—				784				784
Amortization of equity awards			2,213				46				—				2,259
Foreign currency translation adjustment			—				—				401				401
Cash flow hedges			—				—				13,390				13,390
Balance, March 31, 2007		$	6,230,625			$	127,149			$	35,716			$	6,393,490

See Notes to Unaudited Condensed Consolidated Financial Statements.

ENTERPRISE PRODUCTS PARTNERS L.P.

Note 1. Partnership Organization

     Partnership Organization

          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 business and operations of Enterprise Products Partners L.P. and its consolidated 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 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 are 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., a publicly traded affiliate, the units of which are listed on the NYSE under the ticker symbol “TPP.” References to “TEPPCO GP” refer to Texas Eastern Products Pipeline Company, LLC, which is the general partner of TEPPCO and is wholly owned by a private company subsidiary of EPCO.

          References to “Employee Partnerships” mean EPE Unit L.P. and EPE Unit II, L.P., collectively, which are private company affiliates of EPCO. References to “EPE Unit I” and “EPE Unit II” refer to EPE Unit L.P. and EPE Unit II, L.P., respectively.

          On February 5, 2007, a consolidated subsidiary of ours, Duncan Energy Partners L.P. (“Duncan Energy Partners”), completed an initial public offering of its common units (see Note 12). Duncan Energy Partners owns equity interests in certain of our midstream energy businesses.

          For financial reporting purposes, we consolidate the financial statements of Duncan Energy Partners with those of our own and reflect its operations in our business segments. We control Duncan Energy Partners through our ownership of its general partner. Also, due to common control of the entities by Dan L. Duncan, the initial consolidated balance sheet of Duncan Energy Partners reflects our historical carrying basis in each of the subsidiaries contributed to Duncan Energy Partners. Public ownership of Duncan Energy Partners’ net assets and earnings are presented as a component of minority interest in our consolidated financial statements. The borrowings of Duncan Energy Partners are presented as part of our consolidated debt; however, we do not have any obligation for the payment of interest or repayment of borrowings incurred by Duncan Energy Partners.

     Basis of Presentation

          Our results of operations for the three months ended March 31, 2007 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 17 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 Condensed Consolidated Financial Statements should be read in conjunction with our annual report on Form 10-K for the year ended December 31, 2006 (Commission File No. 1-14323).

Note 2. General Accounting Policies and Related Matters

     Accounting for Employee Benefit Plans

          Dixie Pipeline Company (“Dixie”), a consolidated subsidiary, employs the personnel that operate its pipeline system and certain of these employees are eligible to participate in a 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 $0.1 million to its company-sponsored defined contribution plan during the three month periods ended March 31, 2007 and 2006.

          Pension and Postretirement Benefit Plans. Dixie’s net pension benefit costs were $0.2 million for the three month periods ended March 31, 2007 and 2006. Dixie’s net postretirement benefit costs were $0.1 million for the three month periods ended March 31, 2007 and 2006. During the remainder of 2007, Dixie expects to contribute approximately $0.3 million to its postretirement benefit plan and approximately $0.5 million to its pension plan.

     Consolidation Policy

          We evaluate our financial interests in business enterprises to determine if they represent variable interest entities where we are the primary beneficiary. If such criteria are met, we consolidate the financial statements of such businesses with those of our own. Our consolidated financial statements include our accounts and those of our majority-owned subsidiaries in which we have a controlling interest, after the elimination of all material intercompany accounts and transactions. We also consolidate other entities and ventures in which we possess a controlling financial interest as well as partnership interests where we are the sole general partner of the partnership.

          If the investee is organized as a limited partnership or limited liability company and maintains separate ownership accounts, we account for our investment using the equity method if our ownership interest is between 3% and 50% and we exercise significant influence over the investee’s operating and financial policies. For all other types of investments, we apply the equity method of accounting if our ownership interest is between 20% and 50% and we exercise significant influence over the investee’s operating and financial policies. Our proportionate share of profits and losses from transactions with equity method unconsolidated affiliates are eliminated in consolidation to the extent such amounts are material and remain on our balance sheet (or those of our equity method investees) in inventory or similar accounts.

          If our ownership interest in an investee does not provide us with either control or significant influence over the investee, we account for the investment using the cost method.

     Cumulative Effect of Change in Accounting Principle

          In January 2006, we adopted the provisions of Statement of Financial Accounting Standards (“SFAS”) 123(R), “Share-Based Payment.” Upon adoption of this accounting standard, we recognized, as a benefit, a cumulative effect of change in accounting principle of $1.5 million.

     Environmental Costs

          Environmental costs for remediation are accrued based on estimates of known remediation requirements. Such accruals are based on management’s best estimate of the ultimate cost to remediate a site and are adjusted as further information and circumstances develop. Those estimates may change substantially depending on information about the nature and extent of contamination, appropriate remediation technologies, and regulatory approvals. Ongoing environmental compliance costs are charged to expense as incurred. In accruing for environmental remediation liabilities, costs of future expenditures for environmental remediation are not discounted to their present value, unless the amount and timing of the expenditures are fixed or reliably determinable. Expenditures to mitigate or prevent future environmental contamination are capitalized.

          At March 31, 2007 and December 31, 2006, our accrued liabilities for environmental remediation projects totaled $30.2 million and $24.2 million, respectively. These amounts were derived from a range of reasonable estimates based upon studies and site surveys. Unanticipated changes in circumstances and/or legal requirements could result in expenses being incurred in future periods in addition to an increase in actual cash required to remediate contamination for which we are responsible.

          In February 2007, we reserved $6.5 million in cash received from a third party to fund anticipated future environmental remediation costs associated with certain assets that we had acquired from the third party. Previously, the third party had been obligated to indemnify us for such costs. As a result of the settlement, this indemnification was terminated.

     Estimates

          Preparing our Unaudited Condensed Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect 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 the reporting period. Our actual results could differ from these estimates. On an ongoing basis, management reviews its estimates based on currently available information. Changes in facts and circumstances may result in revised estimates.

     Income Taxes

          We are organized as a pass-through entity for income tax purposes. As a result, our partners are responsible for federal income taxes on their share of our taxable income. For the three months ended March 31, 2007, our provision for income taxes of $8.8 million is applicable to state tax obligations under the Texas Margin Tax and certain federal and state tax obligations of Seminole Pipeline Company (“Seminole”) and Dixie.

          In accordance with Financial Accounting Standards Board Interpretation (“FIN”) 48, “Accounting for Uncertainty in Income Taxes,” we must recognize the tax effects of any uncertain tax positions we may adopt, if the position taken by us is more likely than not sustainable. If a tax position meets such criteria, the tax effect to be recognized by us would be the largest amount of benefit with more than a 50% chance of being realized upon settlement. This guidance was effective January 1, 2007, and our adoption of this guidance had no material impact on our financial position, results of operations or cash flows.

     Minority Interest

          As presented in our Unaudited Condensed Consolidated Balance Sheets, minority interest represents third-party ownership interests in the net assets of our consolidated subsidiaries. For financial reporting purposes, the assets and liabilities of our majority owned subsidiaries are consolidated with those of our own, with any third-party ownership interests in such amounts presented as minority interest. Effective February 1, 2007, the public owners of Duncan Energy Partners’ common units are presented as a minority interest in our consolidated financial statements.

          At March 31, 2007, $294.7 million of our minority interest is attributable to the limited partners of Duncan Energy Partners and the remaining $138.9 million to our joint venture partners. For the three months ended March 31, 2007, $2.8 million of our minority interest expense is attributable to the limited partners of Duncan Energy Partners and the remaining $2.8 million to our joint venture partners. For the three months ended March 31, 2007, our contributions from minority interests includes $291.9 million from the limited partners of Duncan Energy Partners, which represents the proceeds Duncan Energy Partners received from its initial public offering.

     Recent Accounting Developments

          SFAS 157, “Fair Value Measurements,” defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. SFAS 157 is effective for fiscal years beginning after November 15, 2007 and we will be required to adopt SFAS 157 on January 1, 2008. We do not believe SFAS 157 will have a material impact on our financial position, results of operations, and cash flows since we already apply its basic concepts in measuring fair values used to record various transactions such as business combinations and asset acquisitions.

          SFAS 159, “Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115,” permits entities to choose to measure many financial assets and financial liabilities at fair value. Unrealized gains and losses on items for which the fair value option has been elected would be reported in net income. SFAS 159 also establishes presentation and disclosure requirements designed to draw comparisons between the different measurement attributes the company elects for similar types of assets and liabilities. SFAS 159 is effective for fiscal years beginning after November 15, 2007. We are currently evaluating the impact that the adoption of SFAS 159 will have on our financial statements.

Note 3. Accounting for Equity Awards

          We account for equity awards using SFAS 123(R). SFAS 123(R) requires us to recognize compensation expense related to equity awards based on the fair value of the award at 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.

     Unit Options and Restricted Units

          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.

          The information in the following table presents unit option activity under the 1998 Plan for the periods indicated:

										Weighted-
						Weighted-				average
						average				remaining				Aggregate
		Number of				strike price				contractual				Intrinsic
		Units				(dollars/unit)				term (in years)				Value (1)
Outstanding at December 31, 2006			2,416,000			$	23.32
Exercised			(138,000	)		$	18.74
Outstanding at March 31, 2007			2,278,000			$	23.60				7.47			$	4,672
Options exercisable at:
March 31, 2007			453,000			$	21.49				4.67			$	4,672

          The total intrinsic value of unit options exercised during the three months ended March 31, 2007 was $1.6 million. We recognized $0.2 million and $0.1 million of compensation expense associated with unit options during the three months ended March 31, 2007 and 2006, respectively.

          As of March 31, 2007, there was an estimated $2.0 million of total unrecognized compensation cost related to nonvested unit options granted under the 1998 Plan. We expect to recognize our share of this cost over a weighted-average period of 2.6 years in accordance with the EPCO administrative services agreement.

          During the three months ended March 31, 2007 and 2006, we received cash of $4.2 million and $0.7 million, respectively, from the exercise of unit options, and our option-related reimbursements to EPCO were $1.6 million and $0.4 million, respectively.

          Under the 1998 Plan, we may also issue restricted common units to key employees of EPCO and directors of our general partner. The following table summarizes information regarding our restricted common units for the periods indicated:

						Weighted-
						Average Grant
		Number of				Date Fair Value
		Units				per Unit (1)
Restricted units at December 31, 2006			1,105,237
Granted (2)			15,140			$	27.38
Forfeited			(2,000	)		$	22.91
Restricted units at March 31, 2007			1,118,377

          None of our restricted common units vested during the three months ended March 31, 2007. During the three months ended March 31, 2007 and 2006, we recognized $1.1 million and $0.7 million, respectively, of compensation expense in connection with restricted common units.

          As of March 31, 2007, there was $16.4 million of total unrecognized compensation cost related to restricted common units. We will recognize our share of such costs in accordance with the EPCO administrative services agreement. At March 31, 2007, these costs are expected to be recognized over a weighted-average period of 2.5 years.

          The 1998 Plan provides for the issuance of up to 7,000,000 common units. As of March 31, 2007, 1,597,000 common units had been issued in connection with the exercise of unit options. After giving effect to outstanding unit options at March 31, 2007 and the issuance and forfeiture of restricted common units through March 31, 2007, a total of 2,012,303 additional common units could be issued under the 1998 Plan.

     Employee Partnerships

          For the three months ended March 31, 2007 and 2006, we recorded $0.5 million and $0.6 million, respectively, of non-cash compensation expense associated with EPE Unit I. We also recorded a nominal amount of non-cash compensation expense associated with EPE Unit II during the three months ended March 31, 2007. As of March 31, 2007, there was $8.8 million of total unrecognized compensation cost related to these awards, of which we will recognize our share in accordance with the EPCO administrative services agreement.

Note 4. Financial Instruments

          We are exposed to financial market risks, including changes in commodity prices and interest rates. In addition, we are exposed to fluctuations in exchange rates between the U.S. dollar and Canadian dollar with respect to a recently acquired NGL marketing business located in Canada. 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 (i) variability of future earnings, (ii) fair values of certain debt instruments and (iii) cash flows resulting from changes in applicable interest rates, commodity prices or exchange rates. 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 interest rate borrowings under various debt agreements. We manage a portion of our interest rate exposure 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.

          Fair Value Hedges – Interest Rate Swaps. As summarized in the following table, we had eleven interest rate swap agreements outstanding at March 31, 2007 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 8.74%

$  50 million

Senior Notes C, 6.375% fixed rate, due Feb. 2013

2

Jan. 2004 to Feb. 2013

Feb. 2013

6.38%to 7.28%

$200 million

Senior Notes G, 5.6% fixed rate, due Oct. 2014

6

4th Qtr. 2004 to Oct. 2014

Oct. 2014

5.60%to 6.33%

$600 million

Senior Notes K, 4.95% fixed rate, due June 2010

2

Aug. 2005 to June 2010

June 2010

4.95%to 5.76%

$200 million

          The total fair value of these eleven interest rate swaps at March 31, 2007 and December 31, 2006, was a liability of $25.0 million and $29.1 million, respectively, with an offsetting decrease in the fair value of the underlying debt. Interest expense for the three months ended March 31, 2007 and 2006 includes a $2.3 million loss and $0.2 million benefit from these swap agreements, respectively.

          Cash Flow Hedges – Treasury Locks. During the fourth quarter of 2006, the Operating Partnership entered into treasury lock transactions having a notional value of $562.5 million. The Operating Partnership entered into these transactions to hedge the underlying U.S. treasury rates related to its anticipated issuances of subordinated debt during the second and fourth quarters of 2007. On February 27, 2007, the Operating Partnership entered into additional treasury lock transactions having a notional

value of $437.5 million. The Operating Partnership entered into these transactions to hedge the underlying U.S. treasury rates related to its anticipated issuances of debt during 2007.

          Each of the treasury lock transactions was designated as a cash flow hedge under SFAS 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended and interpreted. At March 31, 2007, the fair value of our treasury locks was $21.7 million.

     Commodity Risk Hedging Program

          The prices of natural gas, NGLs and certain 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 price risks associated with such products, 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) the value of 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, NGLs or certain petrochemical products. From time to time, we inject natural gas into storage and utilize hedging instruments to lock in the value of our inventory positions. The commodity financial instruments we utilize may be settled in cash or with another financial instrument.

          At March 31, 2007 and December 31, 2006, we had a limited number of commodity financial instruments in our portfolio, which primarily consisted of cash flow hedges. The fair value of our commodity financial instrument portfolio at March 31, 2007 and December 31, 2006 was an asset of $0.2 million and a liability of $3.2 million, respectively. During the three months ended March 31, 2007, we recorded $2.6 million of expense related to our commodity financial instruments. We recorded nominal amounts of earnings from our commodity financial instruments during the three months ended March 31, 2006.

     Foreign Currency Hedging Program

          In October 2006, we acquired all of the outstanding stock of an affiliated NGL marketing company located in Canada from EPCO and Dan L. Duncan. Since this foreign subsidiary’s functional currency is the Canadian dollar, we could be adversely affected by fluctuations in foreign currency exchange rates. We attempt to hedge this risk using foreign exchange purchase contracts to fix the exchange rate. Due to the limited duration of these contracts, we utilize mark-to-market accounting for these transactions, the effect of which has had a minimal impact on our earnings. At March 31, 2007, we had $1.3 million of such contracts outstanding that settled in April 2007.

Note 5. Inventories

          Our inventory amounts were as follows at the dates indicated:

		March 31,				December 31,
		2007				2006
Working inventory		$	451,641			$	387,973
Forward-sales inventory			9,274				35,871
Inventory		$	460,915			$	423,844

          Our regular trade (or “working”) inventory is comprised of inventories of natural gas, NGLs, and certain petrochemical products that are available-for-sale or used by us in the provision of services. Our forward sales inventory consists of segregated NGL and natural gas volumes dedicated to the fulfillment of forward-sales contracts. Our inventory values reflect payments for product purchases, freight charges

associated with such purchase volumes, terminal and storage fees, vessel inspection costs, demurrage charges and other related costs. We value our inventories at the lower of average cost or market.

          Operating costs and expenses, as presented on our Unaudited Condensed Statements of Consolidated Operations, include cost of sales amounts related to the sale of inventories. Our cost of sales were $2.8 billion and $2.7 billion for the three months ended March 31, 2007 and 2006, respectively.

          Due to fluctuating commodity prices in the NGL, natural gas and petrochemical industry, we recognize lower of cost or market (“LCM”) adjustments when the carrying value of our inventories exceed their net realizable value. These non-cash charges are a component of cost of sales in the period they are recognized. For the three months ended March 31, 2007 and 2006, we recognized LCM adjustments of approximately $11.0 million and $11.6 million, respectively.

Note 6. Property, Plant and Equipment

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

		Estimated
		Useful Life				March 31,				December 31,
		in Years				2007				2006
Plants and pipelines (1)			3-35	(5)		$	9,217,439			$	8,774,683
Underground and other storage facilities (2)			5-35	(6)			605,102				596,649
Platforms and facilities (3)			20-31				549,896				161,839
Transportation equipment (4)			3-10				27,608				27,008
Land							40,010				40,010
Construction in progress							1,367,264				1,734,083
Total							11,807,319				11,334,272
Less accumulated depreciation							1,596,421				1,501,725
Property, plant and equipment, net						$	10,210,898			$	9,832,547

          Depreciation expense for the three months ended March 31, 2007 and 2006 was $95.0 million and $83.5 million, respectively. We capitalized $20.7 million and $9.2 million of interest in connection with capital projects during the three months ended March 31, 2007 and 2006, respectively.

Note 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 of accounting. Our investments in and advances to unconsolidated affiliates are grouped according to the business segment to which they relate. See Note 11 for a general discussion of our business segments. The following table presents 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,
		2007				2007				2006
NGL Pipelines & Services:
Venice Energy Service Company L.L.C. (“VESCO”)			13.1	%		$	42,598			$	39,618
K/D/S Promix, L.L.C. (“Promix”)			50	%			52,103				46,140
Baton Rouge Fractionators LLC (“BRF”)			32.3	%			25,159				25,471
Onshore Natural Gas Pipelines & Services:
Jonah Gas Gathering Company (“Jonah”)			17.3	%			157,935				120,370
Evangeline (1)			49.5	%			3,514				4,221
Offshore Pipelines & Services:
Poseidon Oil Pipeline Company, L.L.C. (“Poseidon”)			36	%			61,153				62,324
Cameron Highway Oil Pipeline Company (“Cameron Highway”)			50	%			56,908				60,216
Deepwater Gateway, L.L.C. (“Deepwater Gateway”)			50	%			111,187				117,646
Neptune Pipeline Company, L.L.C. (“Neptune”)			25.7	%			58,778				58,789
Nemo Gathering Company, LLC (“Nemo”)			33.9	%			11,024				11,161
Petrochemical Services:
Baton Rouge Propylene Concentrator, LLC (“BRPC”)			30	%			13,894				13,912
La Porte (2)			50	%			4,385				4,691
Total						$	598,638			$	564,559

          On occasion, the price we pay to acquire an ownership interest in a company exceeds the underlying book value of the capital accounts we acquire. Such excess cost amounts are included within the carrying values of our investments in and advances to unconsolidated affiliates. At March 31, 2007 and December 31, 2006, our investments in Promix, La Porte, Neptune, Poseidon, Cameron Highway, Nemo and Jonah included excess cost amounts totaling $41.8 million and $38.7 million, respectively. These amounts are attributable to the excess of the fair value of each entity’s tangible assets over their respective book carrying values at the time we acquired an interest in each entity. Amortization of such excess cost amounts was $0.5 million during each of the three month periods ended March 31, 2007 and 2006.

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

		For the Three Months
		Ended March 31,
		2007				2006
NGL Pipelines & Services		$	591			$	1,518
Onshore Natural Gas Pipelines & Services			1,029				602
Offshore Pipelines & Services			4,075				1,934
Petrochemical Services			484				(25	)
Total		$	6,179			$	4,029

     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, 2007												March 31, 2006
						Operating				Net								Operating				Net
		Revenues				Income				Income				Revenues				Income (Loss)				Income (Loss)
NGL Pipelines & Services (1)		$	41,732			$	3,260			$	3,829			$	20,286			$	(22,125	)		$	(21,678	)
Onshore Natural Gas Pipelines & Services			108,898				21,615				20,313				108,788				38,896				34,444
Offshore Pipelines & Services			37,193				19,718				12,336				31,696				10,930				3,680
Petrochemical Services			5,553				1,887				1,911				3,868				186				210

     Cameron Highway

          We own a 50.0% interest in Cameron Highway, which owns a crude oil pipeline that gathers production from deepwater areas of the Gulf of Mexico, primarily the South Green Canyon area, for delivery to refineries and terminals in southeast Texas. The Cameron Highway Oil Pipeline commenced operations during the first quarter of 2005. In light of reduced deliveries of crude oil to Cameron Highway caused by production delays, the management committee of Cameron Highway intends to repay its Series A notes (see Note 9) using cash contributions from the partners of Cameron Highway.

          In May 2007, we intend to make an approximate $191 million cash contribution to Cameron Highway. This capital contribution, along with an equal amount contributed by our joint venture partner in Cameron Highway, will be used by Cameron Highway to repay $365.0 million outstanding under its Senior Notes A and $16.3 million of related make-whole premiums and accrued interest.

Note 8. Intangible Assets and Goodwill

     Identifiable Intangible Assets

          The following table summarizes our intangible assets at the dates indicated:

		March 31, 2007												December 31, 2006
		Gross				Accum.				Carrying				Gross				Accum.				Carrying
		Value				Amort.				Value				Value				Amort.				Value
NGL Pipelines & Services		$	528,594			$	(119,888	)		$	408,706			$	528,594			$	(110,644	)		$	417,950
Onshore Natural Gas Pipelines & Services			463,551				(85,557	)			377,994				463,551				(77,402	)			386,149
Offshore Pipelines & Services			207,012				(59,718	)			147,294				207,012				(54,636	)			152,376
Petrochemical Services			56,674				(9,692	)			46,982				56,674				(9,194	)			47,480
Total		$	1,255,831			$	(274,855	)		$	980,976			$	1,255,831			$	(251,876	)		$	1,003,955

          The following table presents the amortization expense of our intangible assets by segment for the periods indicated:

		For the Three Months
		Ended March 31,
		2007				2006
NGL Pipelines & Services		$	9,244			$	6,361
Onshore Natural Gas Pipelines & Services			8,155				8,458
Offshore Pipelines & Services			5,082				5,834
Petrochemical Services			498				499
Total		$	22,979			$	21,152

          For the remainder of 2007, amortization expense associated with our intangible assets is currently estimated at $67.4 million.

     Goodwill

          The following table summarizes our goodwill amounts by segment at the dates indicated:

		March 31,				December 31,
		2007				2006
NGL Pipelines & Services		$	152,693			$	152,595
Onshore Natural Gas Pipelines & Services			282,121				282,121
Offshore Pipelines & Services			82,135				82,135
Petrochemical Services			73,690				73,690
Totals		$	590,639			$	590,541

Note 9. Debt Obligations

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

		March 31,				December 31,
		2007				2006
Operating Partnership senior debt obligations:
Multi-Year Revolving Credit Facility, variable rate, due October 2011		$	390,000			$	410,000
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 (1)			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
Duncan Energy Partners’ debt obligation:
$300 Million Revolving Credit Facility, variable rate, due February 2011			169,000				—
Dixie Revolving Credit Facility, variable rate, due June 2010			10,000				10,000
Other, 8.75% fixed-rate, due June 2010(2)			5,068				5,068
Total principal amount of senior debt obligations			4,928,068				4,779,068
Operating Partnership Junior Subordinated Notes A, due August 2066			550,000				550,000
Total principal amount of senior and junior debt obligations			5,478,068				5,329,068
Other, including unamortized discounts and premiums and changes in fair value (3)			(29,383	)			(33,478	)
Long-term debt		$	5,448,685			$	5,295,590
Standby letters of credit outstanding		$	36,758			$	49,858

     Parent-Subsidiary guarantor relationships

          We act as guarantor of the debt obligations of our Operating Partnership, with the exception of the Dixie revolving credit facility and the senior subordinated notes we assumed in connection with the

GulfTerra Merger. If the Operating Partnership were to default on any debt we guarantee, we would be responsible for full repayment of that obligation. We do not act as guarantor of the debt obligations of Duncan Energy Partners.

     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, 2006.

     Duncan Energy Partners’ debt obligation

          We consolidate the debt of Duncan Energy Partners with that of our own; however, we do not have the obligation to make interest payments or debt payments with respect to the debt of Duncan Energy Partners.

          Duncan Energy Partners entered into a $300.0 million revolving credit facility, all of which may be used for letters of credit, with a $30.0 million sublimit for Swingline loans. Letters of credit outstanding under this facility reduce the amount available for borrowings. At the closing of its initial public offering, Duncan Energy Partners made its initial borrowing of $200.0 million under the facility to fund the $198.9 million cash distribution to the Operating Partnership and the remainder to pay debt issuance costs. At March 31, 2007, the balance outstanding under this facility was $169.0 million.

          This credit facility matures in February 2011 and will be used by Duncan Energy Partners in the future to fund working capital and other capital requirements and for general partnership purposes. Duncan Energy Partners may make up to two requests for one-year extensions of the maturity date (subject to certain restrictions). The revolving credit facility is available to pay distributions upon the initial contribution of assets to Duncan Energy Partners, fund working capital, make acquisitions and provide payment for general purposes. Duncan Energy Partners can increase the revolving credit facility, without consent of the lenders, by an amount not to exceed $150.0 million by adding to the facility one or more new lenders and/or increasing the commitments of existing lenders. No existing lender is required to increase its commitment, unless it agrees to do so in its sole discretion.

          This revolving credit facility offers the following unsecured loans, each having different interest requirements: (i) London Interbank Offered Rate (“LIBOR”) loans bear interest at a rate per annum equal to LIBOR plus the applicable LIBOR margin (as defined in the credit agreement), (ii) Base Rate loans bear interest at a rate per annum equal to the higher of (a) the rate of interest publicly announced by the administrative agent, Wachovia Bank, National Association, as its Base Rate and (b) 0.5% per annum above the Federal Funds Rate in effect on such date and (iii) Swingline loans bear interest a rate per annum equal to LIBOR plus an applicable LIBOR margin.

          The revolving credit facility requires Duncan Energy Partners to maintain a leverage ratio for the prior four fiscal quarters of not more than 4.75 to 1.00 at the last day of each fiscal quarter commencing June 30, 2007; provided that, upon the closing of a permitted acquisition, such ratio shall not exceed (a) 5.25 to 1.00 at the last day of the fiscal quarter in which such specified acquisition occurred and at the last day of each of the two fiscal quarters following the fiscal quarter in which such specified acquisition occurred, and (b) 4.75 to 1.00 at the last day of each fiscal quarter thereafter. In addition, prior to obtaining an investment-grade rating by Standard & Poor’s Ratings Services, Moody’s Investors Service or Fitch Ratings, Duncan Energy Partners’ interest coverage ratio, for the prior four fiscal quarters shall not be less than 2.75 to 1.00 at the last day of each fiscal quarter commencing June 30, 2007.

          The Duncan Energy Partners’ credit facility contains other customary covenants. Also, if an event of default exists under the credit agreement, the lenders will be able to accelerate the maturity date of amounts borrowed under the credit agreement and exercise other rights and remedies.

     Covenants

          We are in compliance with the covenants of our consolidated debt agreements at March 31, 2007 and December 31, 2006.

     Information regarding variable interest rates paid

          The following table presents the range of interest rates paid and weighted-average interest rate paid on our consolidated variable-rate debt obligations during the three months ended March 31, 2007.

		Range of		Weighted-average
		interest rates		interest rate
		paid		paid
Operating Partnership’s Multi-Year Revolving Credit Facility		5.82% to 8.25%		5.84%
Duncan Energy Partners’ Revolving Credit Facility		6.17%		6.17%
Dixie Revolving Credit Facility		5.66% to 5.67%		5.66%

     Consolidated debt maturity table

          The following table presents the scheduled maturities of principal amounts of our debt obligations for the next five years and in total thereafter.

2007		$	—
2008			—
2009			500,000
2010			569,068
2011			1,509,000
Thereafter			2,900,000
Total scheduled principal payments		$	5,478,068

          In accordance with SFAS 6, long-term and current maturities of debt reflect the classification of such obligations at March 31, 2007. With respect to the $500.0 million in principal due under Senior Notes E in October 2007, the Operating Partnership has the ability to use available credit capacity under its Multi-Year Revolving Credit Facility to fund the repayment of this debt. The preceding table and our Unaudited Condensed Consolidated Balance Sheets at March 31, 2007 and December 31, 2006 reflect this ability to refinance.

     Debt Obligations of Unconsolidated Affiliates

          We have three unconsolidated affiliates with long-term debt obligations. The following table shows (i) our ownership interest in each entity at March 31, 2007, (ii) total debt of each unconsolidated affiliate at March 31, 2007 (on a 100% basis to the affiliate) and (iii) the corresponding scheduled maturities of such debt.

		Our								Scheduled Maturities of Debt
		Ownership																												After
		Interest				Total				2007				2008				2009				2010				2011				2011
Cameron Highway			50	%		$	415,000			$	—			$	25,000			$	25,000			$	50,000			$	55,000			$	260,000
Poseidon			36	%			91,000				—				—				—				—				91,000				—
Evangeline			49.5	%			25,650				5,000				5,000				5,000				10,650				—				—
Total						$	531,650			$	5,000			$	30,000			$	30,000			$	60,650			$	146,000			$	260,000

          Cameron Highway’s debt consists of $365.0 million of Series A notes and $50.0 million of Series B notes. Cameron Highway intends to repay its Series A notes in May 2007 using proceeds from capital contributions from its partners. The total amount of the repayment is estimated to be $381.3 million, which includes a $13.1 million make-whole premium and $3.2 million of accrued interest. We intend to fund our share of the capital contribution using borrowings under our Multi-Year Revolving Credit Facility.

          The credit agreements of our unconsolidated affiliates contain various affirmative and negative covenants, including financial covenants. These businesses were in compliance with such covenants at March 31, 2007. The credit agreements of our unconsolidated affiliates restrict their ability to pay cash dividends if a default or an event of default (as defined in each credit agreement) has occurred and is continuing at the time such dividend is scheduled to be paid.

          Apart from the planned repayment of Cameron Highway’s Series A notes, there have been no significant changes in the terms of the debt obligations of our unconsolidated affiliates since those reported in our annual report on Form 10-K for the year ended December 31, 2006.

Note 10. Partners’ Equity and Distributions

          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.

          In accordance with the Partnership Agreement, capital accounts are maintained for our general partner and 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 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).

          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 past issuance of securities under this registration statement, we have the ability to issue approximately $2.1 billion of additional securities under this registration statement as of March 31, 2007.

          In April 2007, we filed a registration statement with the SEC authorizing the issuance of up to 25,000,000 common units in connection with our distribution reinvestment plan (“DRIP”). The DRIP provides unitholders of record and beneficial owners of our common units a voluntary means by which they can increase the number of common units they own by reinvesting the quarterly cash distributions they would otherwise receive into the purchase of additional common units.

          A total of 438,631 of our common units were issued in February 2007 in connection with the DRIP and the employee unit purchase plan (“EUPP”). The issuance of these units generated $12.5 million in net proceeds.

          The following table reflects the number of common units issued and the net proceeds received from underwritten and other common unit offerings completed during the three months ended March 31, 2007:

		Net Proceeds from Sale of Common Units
		Number of				Contributed				Contributed by				Total
		common units				by Limited				General				Net
		issued				Partners				Partner				Proceeds
DRIP and EUPP			438,631			$	12,495			$	255			$	12,750
Total 2007			438,631			$	12,495			$	255			$	12,750

     Summary of Changes in Outstanding Units

          The following table summarizes changes in our outstanding units since December 31, 2006:

						Restricted
		Common				Common
		Units				Units
Balance, December 31, 2006			431,303,193				1,105,237
Units issued in connection with DRIP and EUPP			438,631				—
Units issued in connection with equity-based awards			138,000				15,140
Forfeiture of restricted units			—				(2,000	)
Balance, March 31, 2007			431,879,824				1,118,377

     Summary of Changes in Limited Partners’ Equity

          The following table details the changes in limited partners’ equity since December 31, 2006:

						Restricted
		Common				Common
		units				units				Total
Balance, December 31, 2006		$	6,320,577			$	9,340			$	6,329,917
Net income			84,830				219				85,049
Operating leases paid by EPCO			514				1				515
Cash distributions to partners			(201,633	)			(516	)			(202,149	)
Net proceeds from sales of common units			12,495				—				12,495
Proceeds from exercise of unit options			4,162				—				4,162
Unit option reimbursements to EPCO			(1,577	)			—				(1,577	)
Amortization of equity-based awards			569				1,644				2,213
Balance, March 31, 2007		$	6,219,937			$	10,688			$	6,230,625

     Distributions to Partners

          The percentage interest of Enterprise Products GP in our quarterly cash distributions is increased after certain specified target levels of quarterly distribution rates are met. At current distribution rates, we are in the highest tier of such incentive targets. 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.

          We paid incentive distributions of $25.3 million and $19.1 million to Enterprise Products GP during the three months ended March 31, 2007 and 2006, respectively.

          On April 16, 2007, we announced that our quarterly distribution rate with respect to the first quarter of 2007 would be $0.475 per common unit, or $1.90 on an annualized basis. This distribution will be paid on May 10, 2007, to unitholders of record at the close of business on April 30, 2007.

Note 11. 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 technologies 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 an alternative to GAAP operating income.

          We define total segment gross operating margin as consolidated 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 costs. Gross operating margin is exclusive of other income and expense transactions, provision for income taxes, minority interest, extraordinary charges and the cumulative effect of change in accounting principle. 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 include intersegment and intrasegment transactions, which are generally based on transactions made at market-related rates. Our consolidated revenues reflect the elimination of all material intercompany (both intersegment and intrasegment) transactions.

          We include equity earnings from unconsolidated affiliates in our measurement of segment gross operating margin 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 and/or suppliers. This method of operation 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, crude oil and certain petrochemicals. In general, hydrocarbons enter our asset system in a number of ways, such as an offshore natural gas or crude oil pipeline, an offshore platform, a natural gas processing plant, an onshore natural gas gathering pipeline, an NGL fractionator, an NGL storage facility, or an NGL transportation or distribution pipeline.

          Many of our equity investees are included 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 mixed NGLs extracted by our gas plants. The fractionated NGLs we receive from Promix can then be sold in our NGL marketing activities. Given the integral nature of our equity method investees to our operations, we believe the presentation of earnings from such investees as a component of gross operating margin and operating income is meaningful and appropriate.

          Historically, substantially all of our consolidated revenues were earned in the United States and derived from a wide customer base. The majority of our plant-based operations are located in Texas, Louisiana, Mississippi, New Mexico and Wyoming. Our natural gas, NGL and crude oil pipelines are located in a number of regions of the United States including (i) the Gulf of Mexico offshore Texas and

22

(1)		These amounts are taken from our Unaudited Condensed Statements of Consolidated Operations.
(2)		These non-cash expenses are taken from the operating activities section of our Unaudited Condensed Statements of Consolidated Cash Flows.

23

24

25

common units owned by Enterprise GP Holdings. In addition, at March 31, 2007, EPCO and its affiliates beneficially owned 86.8% of the limited partner interests of Enterprise GP Holdings and 100% of its general partner, EPE Holdings. Enterprise GP Holdings owns all of the membership interests of Enterprise Products GP. 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 EPE Holdings are employees of EPCO.

          In connection with its general partner interest in us, Enterprise Products GP received cash distributions of $29.4 million and $22.6 million from us during the three months ended March 31, 2007 and 2006, respectively. These amounts include incentive distributions of $25.3 million and $19.1 million for the three months ended March 31, 2007 and 2006, respectively.

          We and Enterprise Products GP are both separate legal entities apart from each other and apart from EPCO, Enterprise GP Holdings and their respective other affiliates, with assets and liabilities that are separate from those of EPCO, Enterprise GP Holdings and their respective other affiliates. EPCO and its private company subsidiaries depend on the cash distributions they receive from us, Enterprise GP Holdings and other investments to fund their other operations and to meet their debt obligations. EPCO and its affiliates received $83.0 million and $73.1 million in cash distributions from us during the three months ended March 31, 2007 and 2006, respectively.

          The ownership interests in us that are owned or controlled by Enterprise GP Holdings are pledged as security under its credit facility. In addition, substantially all of the ownership interests in us that are owned or controlled by EPCO and its affiliates, other than those interests owned by Enterprise GP Holdings, Dan Duncan LLC and certain trusts affiliated with Dan L. Duncan, are pledged as security under the credit facility of a private company affiliate of EPCO. This 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. We also lease office space in various buildings from affiliates of EPCO. The rental rates in these lease agreements approximate market rates.

          Historically, we entered into transactions with a Canadian affiliate of EPCO for the purchase and sale of NGL products in the normal course of business. These transactions were at market-related prices. We acquired this affiliate in October 2006 and began consolidating its financial statements with those of our own from the date of acquisition.

     Relationship with TEPPCO

          We received $8.5 million and $5.5 million from TEPPCO during the three months ended March 31, 2007 and 2006, respectively, from the sale of hydrocarbon products. We paid TEPPCO $6.5 million and $4.4 million for NGL pipeline transportation and storage services during the three months ended March 31, 2007 and 2006, respectively.

          Purchase and lease of pipelines for DEP South Texas NGL Pipeline System from TEPPCO. In January 2007, we purchased a 10-mile segment of pipeline from TEPPCO located in the Houston area for $8.0 million that is part of the DEP South Texas NGL Pipeline System. In addition, we entered into a lease with TEPPCO for an 11-mile interconnecting pipeline located in the Houston area. The primary term of this lease expires in September 2007, and will continue on a month-to-month basis subject to termination by either party upon 60 days notice. This pipeline is being leased by a subsidiary of Duncan Energy Partners in connection with operations on its DEP South Texas NGL Pipeline System until construction of a parallel pipeline is completed. These transactions were entered into in accordance with our Board-approved management authorization policy.